ANNUAL REPORT
2016
FINANCIAL HIGHLIGHTS
2 0 1 6 K E Y A C C O M P L I S H M E N T S
• Generated $3.4 billion in cash from operations
• Maintained dividend of $1.44 per share
• Attained top-decile safety performance in our
industry by achieving the best safety record in
our company’s history
F I N A N C I A L S A T A G L A N C E
(dollars in millions, except per share amounts)
TOTAL REVENUES
NET INCOME (LOSS)
BASIC AND DILUTED EARNINGS per common share
DIVIDENDS PAID per common share
BOOK VALUE per common share
• Invested $1 billion to modernize our transmission
system as part of our Energizing the Future initiative
• Installed nearly 550,000 smart meters in Pennsylvania
• Deployed advanced technologies to enhance
transmission system reliability
2016
$14,562
$(6,177)
$(14.49)
$1.44
$14.11
2015
$15,026
$578
$1.37
$1.44
2014
$15,049
$299
$0.71
$1.44
$29.33
$29.49
N E T C A S H F R O M O P E R A T I N G A C T I V I T I E S
(in millions)
2016
2015
2014
$3,371
$3,447
$2,713
0
500
1,000
1,500
2,000
2,500
3,000
3,500
R E G U L A T E D T R A N S M I S S I O N A N D D I S T R I B U T I O N R E V E N U E S
(in millions)
2016
2015
2014
$10,780
$10,636
$9,871
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
T R A N S M I S S I O N A N D D I S T R I B U T I O N R E L I A B I L I T Y I N D E X *
2016
2015
2014
2.78
2.80
2.56
0
0.5
1
1.5
2
2.5
3
* FirstEnergy’s index comprises two indices that are commonly used in the electric utility industry: Transmission Outage Frequency (TOF) and System Average
Interruption Duration Index (SAIDI). Our index measures frequency and duration of service interruptions: the better the performance, the higher the score.
A MESSAGE TO OUR SHAREHOLDERS
In 2016, we continued to make solid progress in pursuing a
regulated growth strategy that will help us better serve our
customers, communities and the environment.
We strengthened our energy infrastructure through
significant investments designed to enhance service reliability
for customers and improve operating efficiencies. These
investments build on the scale and diversity of our regulated
operations, with the goal of achieving more sustainable and
customer-focused growth over the long term.
We’re also addressing the significant challenges facing our
competitive generation business, including weak power
prices, insufficient capacity markets and sluggish demand
for electricity in our region. During the year, we continued
taking aggressive steps to cut costs and advocate for energy
market reforms that could support our critical baseload
generating plants.
TRANSITIONING TO A REGULATED COMPANY
As competitive energy markets continued to devalue
baseload coal and nuclear generation, we announced our
intention to exit these markets and transition to a fully
regulated company. Recognizing that our investors and
employees need closure, we’re pursuing an accelerated time
frame and are targeting to implement this exit by mid-2018.
Consistent with this strategy, we entered
into an agreement to sell four competitive
natural gas power plants in Pennsylvania
and the competitive portion of a Virginia
hydroelectric power station. Under the
terms of the agreement, the five facilities
– Springdale Generating Facility Units 1-5,
Chambersburg Generating Facility Units
12-13, Gans Generating Facility Units 8-9,
Hunlock Creek and the competitive share of
Bath County Hydro – would be purchased
for $925 million in an all-cash transaction
with net proceeds exceeding $300 million
after we repay debt. The transaction is expected to close
in the third quarter of this year, subject to a number of
regulatory approvals and consents from third parties.
Charles E. Jones
President and
Chief Executive Officer
In the fourth quarter of 2016, we recorded a non-cash, pre-tax
impairment charge of $9.2 billion to reduce the carrying
value of certain assets – including generating plants, nuclear
fuel and related materials and supplies – to their estimated
fair value. This decision is based on a recognition that, given
our timetable to exit competitive markets and the anticipated
cash flows over this period, the carrying value of these long-
standing assets is not recoverable.
We’re also taking steps to convert competitive generation to
a regulated or regulated-like construct. In March of this year,
our Mon Power and Potomac Edison utilities filed a plan
Successful refueling outages completed in 2016 at our
Davis-Besse Nuclear Power Station and Unit 1 of our
Beaver Valley Nuclear Power Station will enable the
plants – along with our Perry Nuclear Power Plant – to
continue providing safe, reliable, clean and affordable
electricity to customers.
1
seeking regulatory approval to acquire the competitive
Pleasants Power Station as the least-cost source to meet
a capacity shortfall in their West Virginia service areas. In
addition, we’re participating in legislative efforts in Ohio and
Pennsylvania that recognize the environmental and energy
security benefits of our baseload nuclear plants.
In response to challenging market conditions, we’re making
operational changes at two of our Ohio power plants. In
2016, we announced the planned retirement of Units 1
through 4 – a total capacity of 720 megawatts (MW) – at our
seven-unit W.H. Sammis Plant in Stratton, Ohio. We also
plan to sell or deactivate the 136-MW Unit 1 at our Bay Shore
Plant in Oregon, Ohio. Although employees at both facilities
have worked hard to make these plants more productive
and efficient, we simply cannot continue to operate these
units in the current pricing environment.
These and other significant changes demand that we take
a critical look at how our company can deliver greater value
to customers and shareholders in the years ahead. Toward
that end, a team of employees is evaluating our organization
to identify and understand how shared services – such as
legal, accounting, communications and human resources –
will be allocated across the enterprise and ensure we have
the right structure in place to support our efforts to become
a fully regulated utility.
As your company moves away from competitive generation,
we’re also committed to making the appropriate
investments to ensure the safe and reliable operation of
our generating fleet. And we remain dedicated to achieving
excellence in all aspects of our nuclear performance – from
the fundamentals of safe plant operations to the successful
execution of refueling outages.
INVESTING IN OUR CUSTOMERS
Despite the challenges facing our competitive subsidiaries,
FirstEnergy’s 10 electric utility operating companies remain
strong. Our utilities provide stable, predictable cash flows
and earnings.
We continue to build on this strength by implementing our
Energizing the Future transmission investment program –
an essential part of our efforts to ensure customers benefit
from a more reliable grid in the years ahead.
With phase one of the program nearly completed, we expect
to spend an additional $4.2 billion to $5.8 billion from
2017 to 2021 as we extend it across our entire transmission
system. Projects funded through the program are designed
to help us meet the evolving energy needs of our customers
and ensure long-term service reliability; add resiliency to
our transmission system; meet expected load growth from
shale gas activity in our service area; and increase physical
and cyber security.
To better support these efforts, we created a new transmission
affiliate, Mid-Atlantic Interstate Transmission (MAIT), and
filed for implementation of forward-looking formula rates.
These actions will help us more effectively finance and
build transmission facilities within our Met-Ed and Penelec
service areas.
In New Jersey, we completed an 11.5-mile transmission
line in Mercer, Middlesex and Monmouth counties, which
benefits nearly 34,000 customers of Jersey Central Power
& Light (JCP&L). Also, construction is now underway for a
new transmission substation near Burgettstown, Pa., that
will reinforce the regional transmission system and support
the area’s expanding Marcellus shale gas industry while
benefiting more than 40,000 customers of West Penn Power.
2
6MCUSTOMERS
IN THE MIDWEST AND
MID-ATLANTIC REGIONS
65KSQUARE MILES
OF SERVICE TERRITORY
273KMILES
OF DISTRIBUTION
LINES
Shale gas development also is being supported by two projects in
West Virginia: the 18-mile Oak Mound-Waldo Run transmission line and
the Richwood Hill Transmission Project, which includes equipment that
helps regulate voltage, a switching station and a 2.2-mile transmission
line. Both projects also will help enhance service reliability for thousands
of Mon Power customers.
We’re making steady progress with our Pennsylvania smart meter
program, with nearly 550,000 smart meters installed across our four
utility operating companies in the state last year. We plan to deploy smart
meters to nearly all of our 2 million Pennsylvania customers by mid-2019.
We reached a key milestone in August when we began deploying
automated meter reading and billing functionality for Penn Power
customers. This marks a significant step toward providing customers
with more detailed information on their energy use and helping them
make better-informed energy decisions. Met-Ed, Penelec and West
Penn Power customers with smart meters will transition to automated
billing in 2017.
In Ohio, we will work closely with the Public Utilities Commission of
Ohio (PUCO) on a Grid Modernization Plan that could include smart
meters and other technologies.
3
-
RECOVERING COSTS OF SERVING CUSTOMERS
Favorable rulings on several regulatory initiatives will help
ensure the appropriate and timely recovery of investments
in our distribution system.
In January of this year, the Pennsylvania Public Utility
Commission approved a base rate case settlement that will
help support and build on the significant service reliability
enhancements made in recent years to benefit customers
of Met-Ed, Penelec, Penn Power and West Penn Power. The
ruling will result in approximately $290 million in incremental
annual revenue for those utilities.
In Ohio, the PUCO approved modifications to our
comprehensive Electric Security Plan IV (ESP). The plan’s
Ohio Distribution Modernization Rider enables Toledo Edison,
Ohio Edison and The Illuminating Company to collect $204
million annually (grossed up for taxes) through 2019, with
a possible two-year extension. The resulting revenue could
be used to support major upgrades to our electric system in
Ohio. Potential service reliability projects could include the
rehabilitation of urban-area network systems, replacement of
underground cable, overhead and substation circuit upgrades,
integration of smart grid technologies and evaluation of battery
technology.
In New Jersey, the Board of Public Utilities (BPU) issued
an order adopting a JCP&L rate settlement that increases
revenue $80 million annually and approved the accelerated
recovery of our deferred storm-related costs in the state.
The decision reflects JCP&L’s recent efforts to enhance
service reliability and relationships with key constituencies
in New Jersey.
In West Virginia, the state’s Public Service Commission approved
a settlement agreement with our Mon Power and Potomac
Edison utilities allowing recovery of costs for fuel, purchased
power expenses, energy efficiency programs and environmental
controls incurred by the utilities to provide safe, reliable and
clean electricity to customers.
PURSUING REVENUE GROWTH OPPORTUNITIES
To support long-term growth, we’re developing a wide range of
customer-focused initiatives that also would serve as alternative
sources of revenue for your company.
Established in 2015, our FE Products Group expanded its
portfolio of offerings designed to provide greater value to
customers. While continuing to market existing products such
as surge assistance and protection, electrical services and
security lighting, the group introduced plumbing repair plans
and smart thermostats. We’re also exploring the development
of less-traditional products and services designed to enhance
our customers’ quality of life.
In addition, we created an electrification initiative that connects
commercial and industrial customers with new, energy-efficient
equipment and other products. These include electric forklifts
and heating products designed to improve our business
customers’ productivity and efficiency while enhancing their
competitiveness and sustainability efforts.
We’re well-positioned to bring new products and services
to market. Our utility companies share strong brand name
recognition and a long-standing community presence, and
customers view our utilities as trusted sources for energy-saving
programs and tips. Industry studies have shown that customers
are receptive to buying value-added products and services from
4
their electric companies, and that these offerings help increase
customer satisfaction.
We look forward to developing additional products and services
that can help grow our business while bringing greater comfort,
convenience, security and productivity to our residential and
business customers.
WORKING SAFELY
In 2016, we attained top-decile safety performance in our
industry with a companywide OSHA-recordable injury rate of
0.59 – less than one injury per 200,000 hours worked.
Employees at several locations across our service area achieved
safety milestones, including those working at our Perry
Warehouse in Ohio and our Harrisville Service Center in West
Virginia, who celebrated working safely for 22 and 29 years,
respectively, without OSHA-recordable injuries.
Met-Ed and West Penn Power were honored with the prestigious
Governor’s Award for Safety Excellence (GASE) from the
Pennsylvania Department of Labor and Industry. GASE
recognizes companies that have achieved the highest standards
in workplace safety by establishing successful employer-
employee joint safety programs. Also, our Fort Martin Power
Station in Maidsville, W.Va., earned its fourth-consecutive
OSHA Voluntary Protection Program Star status for its strong
commitment to safe work practices.
Our outstanding safety performance reflects the great
importance we place on ensuring our working men and women
have the tools, information and processes necessary to perform
their duties safely. We will continue to strive every day to
strengthen our safety culture and promote an incident-free
workplace.
OUR MISSION
We are a forward-thinking
electric utility powered by a
diverse team of employees
committed to making
customers’ lives brighter, the
environment better and our
communities stronger.
5
SUSTAINING OUR CUSTOMERS AND
COMMUNITIES
FirstEnergy’s sustainability efforts encompass virtually every
facet of our business and reflect our ongoing commitment
to protect the environment and create lasting value in the
communities where we live and work.
First and foremost, we work to minimize the environmental
impact of our generating plants and other facilities.
For example, our generating fleet has adopted human
performance practices to lessen the impact of these facilities
on our communities and the environment. In addition, our
Mon Power and Potomac Edison utilities are investing in
emission control technologies that enable the regulated
Harrison and Fort Martin power stations to meet increasingly
stringent environmental standards.
Our utility customers benefit from a wide range of energy
efficiency programs designed to help them better manage
their energy use. Residential and low-income programs
include incentives for energy-efficient home construction;
rebates on the purchase of energy-efficient products; home
energy usage reports and audits; and home energy efficiency
kits and education. Commercial and industrial programs
include incentives for installing energy-efficient lighting,
motors, drives and other energy-efficient equipment and
processes; energy audits and technology assessments; and
HVAC efficiency incentives.
Our sustainability efforts also focus on economic
development and community support. Over the past
10 years, we helped attract nearly $27 billion in capital
investment and create more than 75,000 jobs in our
service area. Moreover, since 2001, our companies and the
6
FirstEnergy Foundation have provided more than $68 million
in contributions and grants to nearly 2,900 community-based
organizations and charities, many of which also benefit
from the volunteer efforts of our employees. Among other
priorities, the FirstEnergy Foundation promotes a highly
diverse and educated workforce by supporting professional
development, literacy, and science, technology, engineering
and mathematics (STEM) education initiatives in our
communities.
BUILDING A STRONGER FIRSTENERGY
Although the steps we took in 2016 have created greater
opportunities for your company’s future success, we will
continue to need the best efforts of our employees to meet
the significant challenges that lie ahead.
I believe we’re on the right path to create a fully regulated
company, with a stronger focus on meeting the energy needs
of the 6 million utility customers we’re privileged to serve.
Our diverse, high-performing team is dedicated to providing
those customers with the safe, reliable, clean and affordable
electricity they expect and deserve.
I thank you for your support of FirstEnergy, and I’m confident
our employees are up to the challenge of unlocking the full
value of your investment in our company.
Charles E. Jones
President and Chief Executive Officer
March 15, 2017
PA
PA
OH
NJ
MD
WV
VA
CORPORATE PROFILE
Headquartered in Akron, Ohio, FirstEnergy is a leading regional energy
provider dedicated to safety, operational excellence and responsive
customer service. Our subsidiaries are involved in the transmission,
distribution and generation of electricity.
Our 10 utility operating companies form one of the nation’s largest
investor-owned electric systems based on 6 million customers served
within a nearly 65,000-square-mile area of Ohio, Pennsylvania, New Jersey,
West Virginia, Maryland and New York. The company’s transmission
subsidiaries operate approximately 24,500 miles of transmission lines
connecting the Midwest and Mid-Atlantic regions.
Ohio
Ohio Edison
The Illuminating Company
Toledo Edison
Pennsylvania
Met-Ed
Penelec
Penn Power
West Penn Power
Generating
Stations
Coal
Gas/Oil
Hydro
Nuclear
Wind
Solar
FirstEnergy subsidiaries own or control generating capacity from nuclear,
coal, natural gas, hydro, wind and solar facilities.
West Virginia/Maryland
FirstEnergy Solutions, our competitive subsidiary, is a retail energy
supplier serving residential, commercial and industrial customers in Ohio,
Pennsylvania, New Jersey, Maryland, Michigan and Illinois.
Mon Power
Potomac Edison
New Jersey
Jersey Central Power & Light
7
D E A R S H A R E H O L D E R S :
During 2016, your management team focused on building a stronger FirstEnergy by making
significant investments in its regulated utility operations and launching a strategic review
targeting an exit from competitive generation by mid-2018.
Your Board provided an annual dividend rate of $1.44 per share in 2016. We will continue
to review the dividend on a quarterly basis as FirstEnergy addresses the opportunities and
challenges that lie ahead.
On a personal note, let me express my gratitude to Robert (Yank) B. Heisler Jr., Ted J. Kleisner
and Ernest J. Novak Jr., who will no longer be members of the Board after the 2017 Annual Meeting
of Shareholders. The Board is sincerely thankful for the leadership and guidance Yank, Ted and
Ernie provided during their many years of distinguished service to FirstEnergy and its shareholders.
I welcome Steven J. Demetriou and James F. O’Neil III, who were elected to the Board in January
2017. Steve and Jim are well-respected and seasoned leaders who bring extensive executive
and board experience to our company and its shareholders. Steve is chairman and chief
executive officer of Jacobs Engineering Group, Inc. Prior to joining Jacobs in 2015, he served
as chairman and chief executive officer of Aleris Corporation. Jim is a partner at Western
Commerce Group, an advisory and investment firm, and was formerly president, chief executive
officer and a director of Quanta Services, Inc.
Your Board remains committed to ensuring your interests are well represented as we work
with management to enhance the value of your investment in FirstEnergy. Thank you for your
continued support.
Sincerely,
George M. Smart
Chairman of the Board
F I R S T E N E R G Y B O A R D O F D I R E C T O R S
F I R S T E N E R G Y
E X E C U T I V E O F F I C E R S *
Charles E. Jones
President and Chief Executive Officer
Leila L. Vespoli
Executive Vice President, Corporate Strategy,
Regulatory Affairs and Chief Legal Officer
James H. Lash
Executive Vice President and President,
FE Generation
James F. Pearson
Executive Vice President and Chief Financial Officer
Gary D. Benz
Senior Vice President, Strategy
Lynn M. Cavalier
Chief Human Resource Officer
Dennis M. Chack
Senior Vice President, Marketing and Branding
Michael J. Dowling
Senior Vice President, External Affairs
Bennett L. Gaines
Senior Vice President, Corporate Services and
Chief Information Officer
Charles D. Lasky
Senior Vice President, Human Resources
Robert P. Reffner
Vice President and General Counsel
Donald R. Schneider
President, FirstEnergy Solutions
Steven E. Strah
Senior Vice President and President, FirstEnergy Utilities
K. Jon Taylor
Vice President, Controller and Chief Accounting Officer
* More detailed information on the principal occupation or
employment of each of our executive officers and the principal
business of any organization by which FirstEnergy Executive
Officers are employed may be found on page 164 of this report.
Paul T. Addison
Retired, formerly
Managing Director in the
Utilities Department of
Salomon Smith Barney
(CitiGroup).
Michael J. Anderson
Chairman of the Board
of The Andersons, Inc.
(diversified agribusiness).
William T. Cottle
Retired, formerly
Chairman of the Board,
President and Chief
Executive Officer of
STP Nuclear Operating
Company.
Steven J. Demetriou
Chairman and Chief
Executive Officer of
Jacobs Engineering
Group, Inc. (technical
professional and
construction services
firm).
Robert B. Heisler Jr.
Retired, formerly Dean
of the College of Business
Administration and
Graduate School of
Management of Kent
State University. Retired
Chairman of the Board
of KeyBank N.A.
Julia L. Johnson
President of
NetCommunications, LLC
(regulatory and public
affairs firm).
Charles E. Jones
President and Chief
Executive Officer of
FirstEnergy Corp.
Ted J. Kleisner
Retired, formerly
Chairman of the Board
and Chief Executive
Officer of Hershey
Entertainment & Resorts
Company.
Donald T. Misheff
Retired, formerly
Managing Partner of the
Northeast Ohio offices of
Ernst & Young LLP.
Thomas N. Mitchell
Retired, formerly
President, Chief
Executive Officer and
Director of Ontario
Power Generation Inc.
Ernest J. Novak Jr.
Retired, formerly
Managing Partner of
the Cleveland office of
Ernst & Young LLP.
James F. O’Neil III
Partner, Western
Commerce Group
(advisory and investment
firm).
Christopher D.
Pappas
President, Chief
Executive Officer and
Director of Trinseo S.A.
(plastics, latex and
rubber producer).
Luis A. Reyes
Retired, formerly
Regional Administrator
of the U.S. Nuclear
Regulatory Commission.
George M. Smart
Non-executive Chairman
of the FirstEnergy Corp.
Board of Directors.
Retired, formerly
President of Sonoco-
Phoenix, Inc.
Dr. Jerry Sue Thornton
Chief Executive Officer of
Dream Catcher
Educational Consulting
(higher education
coaching and professional
development). Retired
President of Cuyahoga
Community College.
8
ANNUAL.REPORT..
2016
CONTENTS
i............... Glossary.of.Terms
1.............. Selected.Financial.Data
3............. Management’s.Discussion.and.Analysis
68........... Management.Report
69............ Report.of.Independent.Registered.Public.Accounting.Firm
70........... Consolidated.Statements.of.Income.(Loss)
71............ Consolidated.Statements.of.Comprehensive.Income.(Loss)
72........... Consolidated.Balance.Sheets
73........... Consolidated.Statements.of.Common.Stockholders’.Equity
74........... Consolidated.Statements.of.Cash.Flows
75........... Notes.to.the.Consolidated.Financial.Statements
164.......... Executive.Officers.as.of.February.21,.2017
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former
subsidiaries:
AE
AESC
AE Supply
AGC
ATSI
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
Allegheny Energy Service Corporation, which provided legal, financial and other corporate support services to the
former AE subsidiaries
Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP
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
Buchanan Energy
Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply
Buchanan Generation
Buchanan Generation, LLC, a joint venture between AE Supply and CNX Gas Corporation
CEI
CES
FE
FELHC
FENOC
FES
FESC
FET
FEV
FG
FGMUC
FirstEnergy
Global Holding
Global Rail
GPU
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Competitive Energy Services, a reportable operating segment of FirstEnergy
FirstEnergy Corp., a public utility holding company
FELHC, Inc.
FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FirstEnergy Solutions Corp., together with its consolidated subsidiaries, which provides energy-related products
and services
FirstEnergy Service Company, which provides legal, financial and other corporate support services
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
FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FirstEnergy Generation, LLC, a wholly-owned subsidiary of FES, which owns and operates non-nuclear generating
facilities
FirstEnergy Generation Mansfield Unit 1 Corp., a wholly-owned subsidiary of FG, which owns various leasehold
interests in Bruce Mansfield Unit 1
FirstEnergy Corp., together with its consolidated subsidiaries
Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale
LLC
Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup,
Montana
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
MAIT
ME
MP
NG
OE
Ohio Companies
PATH
PATH-Allegheny
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, formed to own and operate transmission facilities
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
Monongahela Power Company, a West Virginia electric utility operating subsidiary
FirstEnergy Nuclear Generation, LLC, a subsidiary of FES, which owns nuclear generating facilities
Ohio Edison Company, an Ohio electric utility operating subsidiary
CEI, OE and TE
Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH Allegheny Transmission Company, LLC
PATH-WV
PATH West Virginia Transmission Company, LLC
PE
Penn
The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies ME, PN, Penn and WP
PN
PNBV
Shippingport
Signal Peak
TE
TrAIL
Utilities
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup,
Montana
The Toledo Edison Company, an Ohio electric utility operating subsidiary
Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
i
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
ADIT
AEP
AFS
American Arbitration Association
Accumulated Deferred Income Taxes
American Electric Power Company, Inc.
Available-for-sale
AFUDC
Allowance for Funds Used During Construction
ALJ
AMT
AOCI
ARO
ARR
ASLB
Aspen
ASU
Administrative Law Judge
Alternative Minimum Tax
Accumulated Other Comprehensive Income
Asset Retirement Obligation
Auction Revenue Right
Atomic Safety and Licensing Board
Aspen Generating, LLC, a wholly-owned subsidiary of LS Power Equity Partners III, LP
Accounting Standards Update
Bath County
Bath County Pumped Storage Hydro-Power Station
BGS
bps
BNSF
BRA
CAA
CBA
CCR
CDWR
CERCLA
CFL
CFR
CFTC
CO2
CONE
CPP
CSAPR
CSX
CTA
CWA
DCPD
DCR
DMR
DOE
DR
DSIC
DSP
DTA
EDC
EDCP
EE&C
EGS
EGU
ELPC
Basic Generation Service
Basis points
BNSF Railway Company
PJM RPM Base Residual Auction
Clean Air Act
Collective Bargaining Agreement
Coal Combustion Residuals
California Department of Water Resources
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Compact Fluorescent Light
Code of Federal Regulations
Commodity Futures Trading Commission
Carbon Dioxide
Cost-of-New-Entry
EPA's Clean Power Plan
Cross-State Air Pollution Rule
CSX Transportation, Inc.
Consolidated Tax Adjustment
Clean Water Act
Deferred Compensation Plan for Outside Directors
Delivery Capital Recovery
Distribution Modernization Rider
United States Department of Energy
Demand Response
Distribution System Improvement Charge
Default Service Plan
Deferred Tax Asset
Electric Distribution Company
Executive Deferred Compensation Plan
Energy Efficiency and Conservation
Electric Generation Supplier
Electric Generation Unit
Environmental Law & Policy Center
EMAAC
Eastern Mid-Atlantic Area Council of PJM
EmPOWER Maryland
EmPOWER Maryland Energy Efficiency Act
ENEC
EPA
Expanded Net Energy Cost
United States Environmental Protection Agency
ii
EPRI
ERISA
ERO
ESOP
ESP
ESP IV
ESP IV PPA
ESTIP
Facebook®
FASB
FERC
Fitch
FMB
FPA
FTR
GAAP
GHG
GWH
HCl
IBEW
ICE
ICP 2007
ICP 2015
IRP
IRS
ISO
kV
KWH
KPI
LBR
LCAPP
LED
LIBOR
LMP
LOC
LSE
LTIIPs
MAAC
MATS
MDPSC
MISO
MLP
mmBTU
Moody’s
MVP
MW
MWD
MWH
NAAQS
NDT
NEIL
NERC
NGO
Electric Power Research Institute
Employee Retirement Income Security Act of 1974
Electric Reliability Organization
Employee Stock Ownership Plan
Electric Security Plan
Electric Security Plan IV
Unit Power Agreement entered into on April 1, 2016 by and between the Ohio Companies and FES
Executive Short-Term Incentive Program
Facebook is a registered trademark of Facebook, Inc.
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Fitch Ratings
First Mortgage Bond
Federal Power Act
Financial Transmission Right
Accounting Principles Generally Accepted in the United States of America
Greenhouse Gases
Gigawatt-hour
Hydrochloric Acid
International Brotherhood of Electrical Workers
IntercontinentalExchange, Inc.
FirstEnergy Corp. 2007 Incentive Plan
FirstEnergy Corp. 2015 Incentive Compensation Plan
Integrated Resource Plan
Internal Revenue Service
Independent System Operator
Kilovolt
Kilowatt-hour
Key Performance Indicator
Little Blue Run
Long-Term Capacity Agreement Pilot Program
Light Emitting Diode
London Interbank Offered Rate
Locational Marginal Price
Letter of Credit
Load Serving Entity
Long-Term Infrastructure Improvement Plans
Mid-Atlantic Area Council of PJM
Mercury and Air Toxics Standards
Maryland Public Service Commission
Midcontinent Independent System Operator, Inc.
Master Limited Partnership
One Million British Thermal Units
Moody’s Investors Service, Inc.
Multi-Value Project
Megawatt
Megawatt-day
Megawatt-hour
National Ambient Air Quality Standards
Nuclear Decommissioning Trust
Nuclear Electric Insurance Limited
North American Electric Reliability Corporation
Non-Governmental Organization
Ninth Circuit
United States Court of Appeals for the Ninth Circuit
iii
NJBPU
NMB
NOAC
NOL
NOV
NOx
NPDES
NPNS
NRC
NRG
NSR
NUG
NYISO
NYPSC
OCA
OCC
OEPA
OPEB
OPEIU
ORC
OTC
OTTI
OVEC
PA DEP
PCB
PCRB
PJM
New Jersey Board of Public Utilities
Non-Market Based
Northwest Ohio Aggregation Coalition
Net Operating Loss
Notice of Violation
Nitrogen Oxide
National Pollutant Discharge Elimination System
Normal Purchases and Normal Sales
Nuclear Regulatory Commission
NRG Energy, Inc.
New Source Review
Non-Utility Generation
New York Independent System Operator
New York State Public Service Commission
Office of Consumer Advocate
Ohio Consumers' Counsel
Ohio Environmental Protection Agency
Other Post-Employment Benefits
Office and Professional Employees International Union
Ohio Revised Code
Over The Counter
Other-Than-Temporary Impairments
Ohio Valley Electric Corporation
Pennsylvania Department of Environmental Protection
Polychlorinated Biphenyl
Pollution Control Revenue Bond
PJM Interconnection, L.L.C.
PJM Region
PJM Tariff
The aggregate of the zones within PJM
PJM Open Access Transmission Tariff
PM
POLR
POR
PPA
PPB
PPUC
PSA
PSD
PTC
PUCO
PURPA
R&D
RCRA
REC
Particulate Matter
Provider of Last Resort
Purchase of Receivables
Purchase Power Agreement
Parts per Billion
Pennsylvania Public Utility Commission
Power Supply Agreement
Prevention of Significant Deterioration
Price-to-Compare
Public Utilities Commission of Ohio
Public Utility Regulatory Policies Act of 1978
Research and Development
Resource Conservation and Recovery Act
Renewable Energy Credit
Regulation FD
Regulation Fair Disclosure promulgated by the SEC
REIT
RFC
RFP
RGGI
RMR
ROE
RPM
RRS
RSS
RTEP
Real Estate Investment Trust
ReliabilityFirst Corporation
Request for Proposal
Regional Greenhouse Gas Initiative
Reliability Must-Run
Return on Equity
Reliability Pricing Model
Retail Rate Stability
Rich Site Summary
Regional Transmission Expansion Plan
iv
RTO
S&P
SAIDI
SAIFI
SB221
SB310
SBC
SEC
SERTP
Regional Transmission Organization
Standard & Poor’s Ratings Service
System Average Interruption Duration Index
System Average Interruption Frequency Index
Amended Substitute Senate Bill No. 221
Substitute Senate Bill No. 310
Societal Benefits Charge
United States Securities and Exchange Commission
Southeastern Regional Transmission Planning
Seventh Circuit
United States Court of Appeals for the Seventh Circuit
SF6
SIP
SO2
SOS
SPE
SRC
SREC
SSA
SSO
TDS
TMI-2
TO
TTS
Sulfur Hexafluoride
State Implementation Plan(s) Under the Clean Air Act
Sulfur Dioxide
Standard Offer Service
Special Purpose Entity
Storm Recovery Charge
Solar Renewable Energy Credit
Social Security Administration
Standard Service Offer
Total Dissolved Solid
Three Mile Island Unit 2
Transmission Owner
Temporary Transaction Surcharge
Twitter®
Twitter is a registered trademark of Twitter, Inc.
U.S. Court of Appeals for
the D.C. Circuit
UWUA
VEPCO
VIE
VRR
VSCC
WVDEP
WVPSC
United States Court of Appeals for the District of Columbia Circuit
Utility Workers Union of America
Virginia Electric Power Company
Variable Interest Entity
Variable Resource Requirement
Virginia State Corporation Commission
West Virginia Department of Environmental Protection
Public Service Commission of West Virginia
v
ITEM 6.
SELECTED FINANCIAL DATA
FirstEnergy
For the Years Ended December 31,
2016
2015
2014
2013
2012
Revenues
Income (Loss) From Continuing Operations
Earnings (Loss) Available to FirstEnergy Corp.
Earnings (Loss) per Share of Common Stock:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 20)
Basic - Earnings (Loss) Available to FirstEnergy Corp.
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 20)
Diluted - Earnings (Loss) Available to FirstEnergy Corp.
Weighted Average Shares Outstanding:
Basic
Diluted
Dividends Declared per Share of Common Stock
Total Assets(1)
Capitalization as of December 31:
Total Equity
Long-Term Debt and Other Long-Term Obligations
Total Capitalization
$
$
$
$
$
$
$
$
$
$
$
(In millions, except per share amounts)
14,892 $
375 $
392 $
15,049 $
213 $
299 $
15,026 $
578 $
578 $
14,562 $
(6,177 ) $
(6,177 ) $
(14.49 ) $
—
(14.49 ) $
(14.49 ) $
—
(14.49 ) $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
0.51 $
0.20
0.71 $
0.51 $
0.20
0.71 $
0.90 $
0.04
0.94 $
0.90 $
0.04
0.94 $
15,255
755
770
1.81
0.04
1.85
1.80
0.04
1.84
426
426
1.44 $
43,148 $
422
424
1.44 $
52,094 $
420
421
1.44 $
51,552 $
418
419
1.65 $
49,980 $
418
419
2.20
50,110
6,241 $
18,192
24,433 $
12,422 $
19,099
31,521 $
12,422 $
19,080
31,502 $
12,695 $
15,753
28,448 $
13,093
15,114
28,207
(1)Reflects the retrospective application of ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs
to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation
of a debt discount. The retrospective change decreased Total Assets as of December 31 as follows: 2015 - $93 million, 2014 - $96 million, 2013 -
$78 million, 2012 - $65 million, as these amounts were reclassified from deferred charges and other assets to long-term debt and other long-term
obligations.
PRICE RANGE OF COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other
registered exchanges.
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Yearly
$
$
$
$
$
2016
2015
High
Low
High
Low
36.54 $
36.32 $
36.60 $
34.83 $
36.60 $
30.62 $
31.37 $
32.12 $
29.33 $
29.33 $
41.68 $
37.05 $
35.09 $
33.00 $
41.68 $
33.82
32.46
30.31
28.89
28.89
Closing prices are from http://finance.yahoo.com.
1
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2011 in FE’s common stock
compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
HOLDERS OF COMMON STOCK
There were 85,173 and 85,172 holders of 442,344,218 and 442,477,633 shares of FE’s common stock as of December 31, 2016
and January 31, 2017, respectively. Information regarding retained earnings available for payment of cash dividends is given in
Note 12, Capitalization of the Combined Notes to Consolidated Financial Statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
2
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements: This Form 10-K includes forward-looking statements based on information currently available to
management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding
management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms
“anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words.
Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may
cause actual results, performance or achievements to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements, which may include the following:
• The ability to experience growth in the Regulated Distribution and Regulated Transmission segments.
• The accomplishment of our regulatory and operational goals in connection with our transmission investment plan,
including, but not limited to, our planned forward-looking formula rates and the effectiveness of our strategy to reflect a
more regulated business profile.
• Changes in assumptions regarding economic conditions within our territories, assessment of the reliability of our
transmission system, or the availability of capital or other resources supporting identified transmission investment
opportunities.
• The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to,
the ability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit
metrics and strengthen our balance sheet through, among other actions, our cash flow improvement plan and other
proposed capital raising initiatives.
• The risks and uncertainties associated with the lack of viable alternative strategies regarding the CES segment, thereby
causing FES, and possibly FENOC, to restructure its debt and other financial obligations with its creditors or seek
protection under U.S. bankruptcy laws and the losses, liabilities and claims arising from such bankruptcy proceeding,
including any obligations at FirstEnergy.
• The risks and uncertainties at the CES segment, including FES and its subsidiaries and FENOC, related to continued
depressed wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives,
such as potential CES generating unit asset sales, the potential conversion of the remaining generation fleet from
competitive operations to a regulated or regulated-like construct or the potential need to deactivate additional generating
units.
• The substantial uncertainty as to FES’ ability to continue as a going concern and substantial risk that it may be necessary
for FES, and possibly FENOC, to seek protection under U.S. bankruptcy laws.
• The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited
to, any such proceedings related to vendor commitments, such as long-term fuel and transportation agreements.
• The uncertainties associated with the deactivation of older regulated and competitive units, including the impact on vendor
commitments, such as long-term fuel and transportation agreements, and as it relates to the reliability of the transmission
grid, the timing thereof.
• The impact of other future changes to the operational status or availability of our generating units and any capacity
performance charges associated with unit unavailability.
• Changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil prices, and
their availability and impact on margins.
• Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity
and market prices.
• Replacement power costs being higher than anticipated or not fully hedged.
• Our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and
fuel transportation on such margins.
• The speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in
particular.
• The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation,
including NSR litigation, or potential regulatory initiatives or rulemakings (including that such initiatives or rulemakings
could result in our decision to deactivate or idle certain generating units).
• Changes in customers' demand for power, including, but not limited to, changes resulting from the implementation of
state and federal energy efficiency and peak demand reduction mandates.
• Economic or weather conditions affecting future sales and margins such as a polar vortex or other significant weather
events, and all associated regulatory events or actions.
3
• Changes in national and regional economic conditions affecting us, our subsidiaries and/or our major industrial and
commercial customers, and other counterparties with which we do business, including fuel suppliers.
• The impact of labor disruptions by our unionized workforce.
• The risks associated with cyber-attacks and other disruptions to our information technology system that may compromise
our generation, transmission and/or distribution services and data security breaches of 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 impact of the regulatory process and resulting outcomes on the matters at the federal level and in the various states
in which we do business including, but not limited to, matters related to rates and the Ohio DMR.
• The impact of the federal regulatory process on FERC-regulated entities and transactions, in particular FERC regulation
of wholesale energy and capacity markets, including PJM markets and FERC-jurisdictional wholesale transactions; FERC
regulation of cost-of-service rates; and FERC’s compliance and enforcement activity, including compliance and
enforcement activity related to NERC’s mandatory reliability standards.
• The uncertainties of various cost recovery and cost allocation issues resulting from ATSI's realignment into PJM.
• The ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand
reduction mandates.
• Other legislative and regulatory changes, and revised environmental requirements, including, but not limited to, the effects
of the EPA's CPP, CCR, CSAPR and MATS programs, including our estimated costs of compliance, CWA waste water
effluent limitations for power plants, and CWA 316(b) water intake regulation.
• Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to,
the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC or as a result of the
incident at Japan's Fukushima Daiichi Nuclear Plant).
Issues arising from the indications of cracking in the shield building at Davis-Besse.
•
• Changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our
NDTs, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner,
or in amounts that are larger than currently anticipated.
• The impact of changes to significant accounting policies.
• The impact of any changes in tax laws or regulations or adverse tax audit results or rulings.
• The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the
cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries.
• Further actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries’
access to financing, increase the costs thereof, increase requirements to post additional collateral to support, or
accelerate payments under outstanding commodity positions, LOCs and other financial guarantees, and the impact of
these events on the financial condition and liquidity of FirstEnergy and/or its subsidiaries, specifically the subsidiaries
within the CES segment.
Issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do
business.
•
• The risks and other factors discussed from time to time in our SEC filings, and other similar factors.
Dividends declared from time to time on FE's common stock during any period may in the aggregate vary from prior periods due
to circumstances considered by FE's Board of Directors at the time of the actual declarations. A security rating is not a
recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each
rating should be evaluated independently of any other rating.
These forward-looking statements are also qualified by, and should be read together with, the risk factors included in (a) Item 1A.
Risk Factors to FirstEnergy’s Form 10-K for the fiscal year ended December 31, 2016, (b) this 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. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from
time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on
FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those
contained in any forward-looking statements. The registrants expressly disclaim any current intention to update, except as required
by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
4
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRSTENERGY’S BUSINESS
FirstEnergy and its subsidiaries are principally involved in the generation, transmission and distribution of electricity. Its reportable
segments are as follows: Regulated Distribution, Regulated Transmission, and CES.
During the fourth quarter of 2016, FirstEnergy modified its segment reporting to reclassify the results of operations from certain
transmission assets of ME, PN and JCP&L, from the Regulated Distribution segment to the Regulated Transmission segment.
Costs associated with these transmission assets, which are currently included in ME, PN, and JCP&L's stated rates, will be
recovered through MAIT's and JCP&L’s formula rates prospectively, once approved by FERC. The external segment reporting is
consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to
regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments
for 2015 and 2014 have been revised to conform to the current presentation reflecting the operating activity of the identified
transmission assets within Regulated Transmission.
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 service areas of, and customers served by, FirstEnergy's regulated distribution utilities are summarized below (in thousands):
Company
Area Served
Customers
Served (1)
OE
Penn
CEI
TE
JCP&L
ME
PN
WP
MP
PE
Central and Northeastern Ohio
Western Pennsylvania
Northeastern Ohio
Northwestern Ohio
Northern, Western and East Central New Jersey
Eastern Pennsylvania
Western Pennsylvania
Southwest, South Central and Northern Pennsylvania
Northern, Central and Southeastern West Virginia
Western Maryland and Eastern West Virginia
(1) As of December 31, 2016
1,045
165
750
310
1,117
565
588
724
390
404
6,058
The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI and TrAIL
and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated
with the abandoned PATH project. 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 "FERC Matters" below, effective January 31,
2017, MAIT includes the transmission assets of ME and PN, and JCP&L submitted applications to FERC requesting authorization
to implement forward-looking formula transmission rates. Those applications are pending before FERC. Both the forward-looking
and stated rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of
ATSI's and TrAIL's revenue requirement is updated annually based on a projected rate base and projected costs, which is subject
to an annual true-up based on actual costs. Except for the recovery of the PATH abandoned project regulatory asset, the segment's
revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. The segment's results also reflect
the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.
5
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, Illinois, Michigan, New Jersey and
Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including
the Utilities. As of December 31, 2016, this business segment controlled 13,162 MWs of electric generating capacity, including, as
further discussed below, 1,572 MWs of natural gas and hydroelectric generating capacity subject to an asset purchase agreement
with Aspen and the 1,300 MW Pleasants power station which was offered into MP's RFP process by AE Supply. 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.
Corporate support not charged to FE's subsidiaries, 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, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of
which 28% was subject to variable-interest rates, and $2.7 billion was borrowed by FE under its revolving credit facility.
6
EXECUTIVE SUMMARY
FirstEnergy believes having a combination of distribution, transmission and generation assets in a regulated or regulated-like
construct is the best way to serve customers. FirstEnergy’s strategy is to be a fully regulated utility, focusing on stable and
predictable earnings and cash flow from its regulated business units.
Over the past several years, CES has been impacted by a prolonged decrease in demand and excess generation supply in the
PJM Region, which has resulted in a period of protracted low power and capacity prices. To address this, CES sold or deactivated
more than 6,770 MWs of competitive generation from 2012 to 2015. Additionally, CES has continued to focus on cost reductions,
including those identified as part of FirstEnergy's previously disclosed cash flow improvement plan.
However, the energy and capacity markets continue to be weak, as evidenced by the significantly depressed capacity prices from
the 2019/2020 PJM Base Residual Auction in May of 2016 as well as the current forward pricing and the long-term fundamental
view on energy and capacity prices, which resulted in a non-cash pre-tax impairment charge of $800 million ($23 million at FES)
recognized in the second quarter of 2016 representing the total amount of goodwill at CES.
As part of a continual process to evaluate its overall generation business, on July 22, 2016, FirstEnergy announced its intent to
exit the 136 MW Bay Shore Unit 1 generating station by October 2020 and to deactivate Units 1-4 of the W.H. Sammis generating
station totaling 720 MWs by May 2020, resulting in a $647 million ($517 million at FES) non-cash pre-tax impairment charge in
the second quarter of 2016. Furthermore, in November of 2016, FirstEnergy announced that it had begun a strategic review of its
competitive operations as it transitions to a fully regulated utility with a target to implement its exit from competitive operations by
mid-2018.
As a result of this strategic review, FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset
purchase agreement to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in Bath
County (1,572 MWs of combined capacity) for an all cash purchase price of $925 million, subject to customary and other closing
conditions as further discussed below under "Competitive Generation Asset Sale", including the satisfaction and discharge of $305
million of AE Supply's senior notes, which is expected to require the payment of a "make-whole" premium currently estimated to
be approximately $100 million based on current interest rates. Additionally, in connection with MP's RFP seeking additional
generation capacity, AE Supply offered the Pleasants power station (1,300 MWs) for approximately $195 million. A winning bidder
is expected to be announced in connection with the filing of appropriate applications for approval of the transactions with the
WVPSC and FERC.
Although FirstEnergy is targeting mid-2018 to exit from competitive operations, the options for the remaining portion of CES'
generation are still uncertain, but could include one or more of the following:
• Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,
• Additional asset sales and/or plant deactivations,
• Restructuring FES debt with its creditors, and/or
• Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.
Furthermore, adverse outcomes in previously disclosed disputes regarding long-term coal transportation contracts and/or the
inability to extend or refinance debt maturities at FES subsidiaries, could accelerate management's targeted timeline and limit its
options to exit competitive operations to either restructuring debt with its creditors or seeking protection under U.S. bankruptcy
laws for FES and possibly FENOC.
As part of assessing the viability of strategic alternatives, FirstEnergy determined that the carrying value of long-lived assets of
the competitive business were not recoverable, specifically given FirstEnergy’s target to implement its exit from competitive
operations by mid-2018, significantly before the end of their original useful lives, and the anticipated cash flows over this shortened
period. As a result, CES recorded a non-cash pre-tax impairment charge of $9,218 million ($8,082 million at FES) in the fourth
quarter of 2016 to reduce the carrying value of certain assets to their estimated fair value, including long-lived assets such as
generating plants and nuclear fuel, as well as other assets such as materials and supplies.
7
Today, the competitive generation portfolio is comprised of more than 13,000 MWs of generation, primarily from coal, nuclear and
natural gas and oil fuel sources. The assets can generate approximately 70-75 million MWHs annually, with up to an additional
five million MWHs available from purchased power agreements for wind, solar, and CES' entitlement in OVEC, of which a portion
is sold through various retail channels and the remainder targeting forward wholesale or spot sales. Subject to the completion of
the sale of the AE Supply natural gas generating plants and AGC’s interest in Bath County and, if accepted in the MP RFP process
as the winning bidder, the transfer of the Pleasants Power station to MP, the size and generation capacity of CES’ current portfolio
will reduce to approximately 10,000 MWs with approximately 60-65 million MWHs produced annually.
The competitive business continues to be managed conservatively due to the stress of weak energy prices, insufficient results
from recent capacity auctions and anemic demand forecasts that have lowered the value of the business. Furthermore, the credit
quality of CES, specifically FES' unsecured debt rating of Caa1 at Moody’s, CCC+ at S&P and C at Fitch and negative outlook
from each of the rating agencies has challenged its ability to hedge generation with retail and forward wholesale sales due to
collateral requirements that otherwise would reduce available liquidity. A lack of viable alternative strategies for its competitive
portfolio has and would further stress the financial condition of FES. As a result, CES' contract sales are expected to decline from
53 million MWHs in 2016 to 40-45 million MWHs in 2017 and to 35-40 million MWHs in 2018. While the reduced contract sales
will decrease potential collateral requirements, market price volatility may significantly impact CES' financial results due to the
increased exposure to the wholesale spot market.
As previously disclosed, FES has $130 million of debt maturities that need to be refinanced in 2017 (and $515 million of maturing
debt in 2018 beginning in the second quarter). Based on its current senior unsecured debt rating and current capital structure,
reflecting the impact of the impairment charges discussed above, as well as the forecasted decline in wholesale forward market
prices over the next few years, these debt maturities will be difficult to refinance, even on a secured basis, which would further
stress FES' anticipated liquidity. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including
additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like
construct in a way that provides FES with the means to satisfy its obligations over the long-term, may require FES to restructure
debt and other financial obligations with its creditors or seek protection under U.S bankruptcy laws. In the event FES seeks
protection under U.S. bankruptcy laws, FENOC may similarly seek such protection. Although management is exploring capital and
other cost reductions, asset sales, and other options to improve cash flow as well as continuing with legislative efforts to explore
a regulatory solution, these obligations and their impact on 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.
As FirstEnergy continues to evaluate and implement the strategic review for its competitive operations, management continues to
focus on its two regulated businesses - Regulated Transmission and Regulated Distribution - which focus on delivering enhanced
customer service and reliability, strengthening grid and cyber-security and adding resiliency and operating flexibility to the
transmission and distribution infrastructure as well as improving the reliability and efficiency of Regulated Distribution's generation
capacity - all while delivering solid results.
Together, the Regulated Transmission and Distribution businesses provide stable, predictable earnings and cash flows to support
FE’s dividend. These regulated businesses are expected to provide 4%−6% compounded annual earnings growth from 2016 to
2019, which increases to 7%−9% with the inclusion of the DMR in Ohio which was implemented on January 1, 2017 to support
investment in modernization of the Ohio Companies' distribution systems.
With more than 24,000 miles in operations, the transmission system is the centerpiece of FirstEnergy’s regulated investment
strategy. Rate base is expected to grow 9% over the next five years as the company plans to invest $4.2 to $5.8 billion in capital
from 2017 to 2021 as part of its Energizing the Future transmission plan, which began as a $4.2 billion investment plan from 2014
through 2017 to upgrade FirstEnergy's transmission system.
These investments continue to be focused in the stand-alone transmission companies with effective and proposed forward-looking
formula rates including ATSI, TrAIL, MAIT (which include the transmission assets of ME and PN, effective January 31, 2017), and
JCP&L. Filings were made with FERC on October 28, 2016 to implement and transition to a forward-looking formula rate for MAIT's
and JCP&L's transmission investments. FirstEnergy believes its existing transmission infrastructure creates incremental
investment opportunities of approximately $20 billion beyond those identified through 2021 which will make the transmission
system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. FirstEnergy
plans to fund a portion of these investments with $500 million of equity annually from 2017 through 2019.
8
In addition to the significant opportunities at Regulated Transmission, the scale and diversity of the ten Utilities that comprise the
Regulated Distribution segment uniquely position this business unit for growth and represents an additional investment opportunity.
In 2016, eight of the ten Utilities completed rate proceedings which will provide benefits to the customers and communities those
Utilities serve while providing for additional growth opportunities, such as future investments in smart meter technology and electric
system improvement projects to increase reliability and improve service to their customers as well as exploring future opportunities
in customer engagement that focuses on the electrification of customers' homes and businesses by providing a full range of
products and services.
Although weather adjusted distribution deliveries through 2019 are forecasted to be flat as compared to 2016, Regulated
Distribution’s earnings over the next three years are anticipated to increase as a result of (i) the PUCO-approved ESP IV, which
includes $204 million in additional annual revenue pursuant to DMR which became effective January 1, 2017, (ii) the PAPUC-
approved settlement agreements in the Pennsylvania Companies’ base rate cases, which include approximately $290 million in
aggregate additional annual revenue, effective January 27, 2017, and (iii) the NJBPU-approved settlement in JCP&L’s base rate
case, which provides for an $80 million annual revenue increase effective January 1, 2017.
Planned capital expenditures for Regulated Distribution are approximately $1.3 billion, annually for 2017 through 2019.
FINANCIAL OVERVIEW
(In millions, except per share amounts)
2016
2015
2014
2016 vs 2015
2015 vs 2014
REVENUES:
$
14,562 $
15,026 $
15,049 $
(464 )
(3 )% $
(23 )
— %
For the Years Ended December 31
Increase (Decrease)
OPERATING EXPENSES:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total operating expenses
OPERATING INCOME (LOSS)
OTHER INCOME (EXPENSE):
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total other expense
INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES
(BENEFITS)
INCOME TAXES (BENEFITS)
INCOME (LOSS) FROM CONTINUING
OPERATIONS
Discontinued operations (net of income taxes of
$69)
1,666
3,813
3,858
147
1,313
320
1,042
10,665
22,824
(8,262 )
84
—
(1,157 )
103
(970 )
(9,232 )
(3,055 )
(6,177 )
—
1,855
4,318
3,749
242
1,282
268
978
42
12,734
2,292
(22 )
(362 )
(1,132 )
117
(1,399 )
893
315
578
—
2,280
4,716
3,962
835
1,220
12
962
—
13,987
1,062
72
—
(1,081 )
118
(891 )
(189 )
(505 )
109
(95 )
31
52
64
10,623
10,090
(10,554 )
(10 )%
(12 )%
3 %
(39 )%
2 %
19 %
7 %
NM
79 %
NM
(425 )
(398 )
(213 )
(593 )
62
256
16
42
(1,253 )
1,230
106
362
(25 )
(14 )
429
NM
(100 )%
2 %
(12 )%
(31 )%
171
(10,125 )
(42 )
(3,370 )
213
(6,755 )
NM
NM
NM
86
—
— %
(94 )
(362 )
(51 )
(1 )
(508 )
722
357
365
(86 )
279
NET INCOME (LOSS)
$
(6,177 ) $
578 $
299 $
(6,755 )
NM $
EARNINGS (LOSS) PER SHARE OF COMMON
STOCK:
Basic - Continuing Operations
Basic - Discontinued Operations
Basic - Net Income (Loss)
Diluted - Continuing Operations
Diluted - Discontinued Operations
Diluted - Net Income (Loss)
NM - Not Meaningful
$
$
$
$
(14.49 ) $
—
(14.49 ) $
(14.49 ) $
—
(14.49 ) $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
0.51 $
0.20
0.71 $
0.51 $
0.20
0.71 $
(15.86 )
—
(15.86 )
(15.86 )
—
(15.86 )
NM $
— %
NM $
NM $
— %
NM $
0.86
(0.20 )
0.66
0.86
(0.20 )
0.66
9
(19 )%
(8 )%
(5 )%
(71 )%
5 %
NM
2 %
NM
(9 )%
NM
NM
NM
5 %
(1 )%
57 %
NM
NM
NM
(100 )%
93 %
NM
(100 )%
93 %
NM
(100 )%
93 %
FirstEnergy’s net loss in 2016 was $(6,177) million, or a basic and diluted loss of $(14.49) per share of common stock, compared
with net income of $578 million, or basic and diluted earnings of $1.37 per share of common stock in 2015, and $299 million, or
basic and diluted earnings of $0.71 per share of common stock in 2014. Highlights of the key changes in year-over-year financial
results are included below:
2016 compared with 2015
FirstEnergy's operating results in 2016 decreased $6,755 million as compared to 2015, primarily reflecting pre-tax impairment
charges of $10,665 million recognized in 2016, as discussed in the "Executive Summary" above, including the following:
• The impairment of $800 million of goodwill at CES in the second quarter of 2016, reflecting a weak outlook for energy
•
•
and capacity markets.
Impairment charges totaling $647 million in the second quarter of 2016 resulting from management's decision to exit the
Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station.
Impairment charges of $9,218 million resulting from management's plans to exit competitive operations by mid-2018 and
the anticipated cash flows over this shortened period.
Additionally, the Company recognized valuation allowances against state and local NOL carryforwards of $168 million as further
discussed below.
FirstEnergy’s 2016 revenues decreased $464 million as compared to the same period in 2015, resulting from a $835 million
decrease at CES, partially offset by an increases of $47 million and $97 million at Regulated Distribution and Regulated
Transmission, respectively.
• The decrease in revenue at CES resulted from a 15 million MWH decline in contract sales, as the segment continues to
align sales to its generation, as well as lower capacity revenue associated with lower capacity auction prices. The decline
in contract sales volume was partially offset by higher wholesale sales and higher net gains on financially settled
contracts.
• The increase in revenue at Regulated Transmission primarily reflect recovery of incremental operating expenses and a
higher rate base at ATSI and TrAIL, partially offset by adjustments associated with ATSI and TrAIL's annual rate filing for
costs previously recovered as well as a lower ROE in 2016 at ATSI under its FERC-approved comprehensive settlement
related to the implementation of its forward-looking rate.
• The increase in revenue at Regulated Distribution primarily resulted from higher weather-related distribution deliveries
and the full year impact of net rate increases implemented in 2015, partially offset by lower generation sales. Distribution
deliveries increased 0.3%, or 0.4 million MWHs, reflecting higher weather-related sales partially offset by the impact of
lower weather-adjusted average customer usage reflecting the impact of more energy efficient products and services.
Operating expenses increased $10,090 million in 2016 as compared to 2015, reflecting increases at CES of $9,799 million,
primarily associated with the asset impairment charges discussed above, and Regulated Transmission of $77 million, partially
offset by a decrease of $50 million at Regulated Distribution.
Changes in certain operating expenses include the following:
• Purchased power decreased $505 million mainly due to lower volumes at CES and Regulated Distribution and lower
capacity expense at CES.
• Fuel expense decreased $189 million mainly resulting from lower generation at CES associated with outages and lower
economic dispatch of fossil units reflecting low wholesale spot market energy prices, as well as lower unit prices on fossil
fuel contracts.
• Pension and OPEB mark-to-market adjustments decreased $95 million to $147 million in 2016. The 2016 adjustment
resulted from a 25 bps decrease in the discount rate used to measure benefit obligations partially offset by higher than
expected asset returns and changes in certain actuarial assumptions.
• Other operating expenses increased $109 million, primarily reflecting an increase at Regulated Distribution resulting from
the recognition of economic development and energy efficiency obligations in accordance with the PUCO's order
approving the Ohio Companies' ESP IV, higher network transmission expenses, which are recovered through
transmission rates, higher retirement benefit costs, and higher operating and maintenance expenses associated with
storm restoration costs, partially offset by lower PJM transmission costs and lower nuclear planned outage costs at CES.
Other expense decreased $429 million, primarily due to the absence of a $362 million pre-tax impairment charge associated with
FEV's investment in Global Holding recognized in 2015 and lower OTTI on NDT investments.
10
FirstEnergy’s 2016 effective tax rate was 33.1% on pre-tax losses as compared to 35.3% on pre-tax income in 2015. The change
primarily relates to the $800 million impairment of goodwill, of which $433 million was non-deductible for tax purposes. Additionally,
$168 million of valuation allowances were recorded against state and local NOL carryforwards and $78 million of valuation
allowances were recorded against state and local property deferred tax assets, that management believes, more likely than not,
will not be realized.
2015 compared with 2014
FirstEnergy’s 2015 income from continuing operations increased $365 million as compared to 2014, resulting from a year-over-
year improvement of $506 million at CES, $155 million at Regulated Distribution and $73 million at Regulated Transmission.
In 2015, FirstEnergy’s revenues decreased $23 million as compared to 2014, primarily resulting from a $905 million decrease at
CES partially offset by a $528 million increase at Regulated Distribution and a $237 million increase at Regulated Transmission.
• The decrease in revenue at CES resulted from a 31 million MWHs decline in contract sales, in line with CES’ strategy to
align sales to its generation, partially offset by higher wholesale sales, including increased capacity revenue associated
with higher capacity auction prices.
• The increase in revenue at Regulated Distribution resulted from the implementation of new rates at certain operating
companies as well as a year-over-year increase in generation revenue. Distribution deliveries decreased 0.8%, or 1.1
million MWHs, as weather adjusted sales declined as a result of energy efficiency products and services and decreases
in certain industrial sectors, partially offset by an increase in weather-related sales.
• The increase at Regulated Transmission primarily reflected a higher rate base and recovery of incremental operating
expenses as well as ATSI’s transition to a forward-looking rate, effective January 1, 2015. These increases were partially
offset by a lower ROE at ATSI in the last six months of 2015 as part of its FERC-approved settlement discussed above.
Operating expenses decreased $1,253 million in 2015 as compared to 2014, including a $593 million decrease in the Company's
Pension and OPEB mark-to-market adjustment, reflecting a decrease at CES of $1,747 million, partially offset by increases at
Regulated Distribution and Regulated Transmission of $257 million and $71 million, respectively.
Changes in certain operating expenses include the following:
• Fuel expense declined $425 million, primarily at CES, resulting from lower fossil generation associated with low energy
prices, lower unit costs, and lower settlement and termination charges on fuel and transportation contracts.
• Purchased power decreased $398 million, primarily reflecting lower volumes at CES, resulting from lower contract sales,
partially offset by higher volumes at Regulated Distribution due to lower customer shopping as discussed above, and
higher capacity expense associated with higher capacity rates.
• Other operating expenses decreased $213 million, primarily reflecting a decrease at CES associated with lower PJM
transmission costs and retail-related costs partially offset by higher nuclear planned outage costs. Regulated Distribution
other operating expenses increased $163 million resulting from higher network transmission expenses, which are
recovered through transmission rates, and higher operating and maintenance expenses associated with reliability
improvements.
• Amortization of regulatory assets, net increased $256 million primarily reflecting the recovery of deferred costs, including
storm costs, associated with the implementation of new rates discussed above.
FirstEnergy's other expenses increased $508 million, or 57%, year-over-year, primarily resulting from a $362 million pre-tax, non-
cash impairment charge associated with FEV’s investment in Global Holding, lower investment income, including a $65 million
increase in OTTI on NDT investments, and higher interest expense associated with higher average debt levels.
FirstEnergy’s effective tax rate on income from continuing operations was 35.3% in 2015 compared to (24.6)% in 2014. The
increase in the effective tax rate was attributable to tax planning initiatives executed during 2014, including tax benefits associated
with an IRS approved change in accounting method for costs associated with the refurbishment of meters and transformers and
the expiration of the statute of limitations on uncertain state tax positions. Additionally, during 2014, FirstEnergy recognized a
reduction in income tax expense of $25 million that related to prior periods resulting from adjustments to its tax basis balance
sheet.
11
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments.
A reconciliation of segment financial results is provided in Note 19, Segment Information, of the Combined Notes to Consolidated
Financial Statements. Certain prior year amounts have been reclassified to conform to the current year presentation.
During the fourth quarter of 2016, FirstEnergy modified its segment reporting to reclassify the results of operations from certain
transmission assets of ME, PN and JCP&L, from the Regulated Distribution segment to the Regulated Transmission segment.
Costs associated with these transmission assets, which are currently included in ME, PN, and JCP&L's stated rates, will be
recovered through MAIT's and JCP&L’s formula rates prospectively, once approved by FERC. The external segment reporting is
consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to
regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments
for 2015 and 2014 have been revised to conform to the current presentation reflecting the operating activity of the identified
transmission assets within Regulated Transmission.
Net income (loss) by business segment was as follows:
Net Income (Loss) By Business Segment:
Regulated Distribution
Regulated Transmission
Competitive Energy Services
Corporate/Other (1)
Net Income (Loss)
Basic Earnings (Losses) Per Share:
Continuing operations
Discontinued operations
Earnings (loss) per basic share
Diluted Earnings (Losses) Per Share:
Continuing operations
Discontinued operations
Earnings (loss) per diluted share
2016
$
651 $
331
(6,919 )
(240 )
$
(6,177 ) $
$
$
$
$
(14.49 ) $
—
(14.49 ) $
(14.49 ) $
—
(14.49 ) $
Increase (Decrease)
2015
2016 vs 2015
(In millions, except per share amounts)
2014
2015 vs 2014
588 $
328
89
(427 )
578 $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
433 $
255
(331 )
(58 )
299 $
0.51 $
0.20
0.71 $
0.51 $
0.20
0.71 $
63 $
3
(7,008 )
187
(6,755 ) $
(15.86 ) $
—
(15.86 ) $
(15.86 ) $
—
(15.86 ) $
155
73
420
(369 )
279
0.86
(0.20 )
0.66
0.86
(0.20 )
0.66
(1) Includes Corporate support costs not charged to FE's subsidiaries and other businesses that do not constitute an operating segment, interest expense on stand-
alone holding company debt and corporate income taxes 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.
12
Summary of Results of Operations — 2016 Compared with 2015
Financial results for FirstEnergy’s business segments in 2016 and 2015 were as follows:
2016 Financial Results
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
(In millions)
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Investment income
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total Other Expense
$
9,401 $
228
—
9,629
1,151 $
—
—
1,151
3,892 $
178
479
4,549
(181 ) $
(107 )
(479 )
(767 )
567
3,273
2,436
101
676
313
720
—
8,086
1,543
49
—
(586 )
20
(517 )
—
—
161
1
187
7
153
—
509
642
—
—
(158 )
34
(124 )
1,099
1,019
1,526
45
387
—
134
10,665
14,875
(10,326 )
66
—
(194 )
37
(91 )
—
(479 )
(265 )
—
63
—
35
—
(646 )
(121 )
(31 )
—
(219 )
12
(238 )
Income (Loss) Before Income Taxes (Benefits)
Income taxes (benefits)
Net Income (Loss)
1,026
375
651 $
$
518
187
331 $
(10,417 )
(3,498 )
(6,919 ) $
(359 )
(119 )
(240 ) $
14,263
299
—
14,562
1,666
3,813
3,858
147
1,313
320
1,042
10,665
22,824
(8,262 )
84
—
(1,157 )
103
(970 )
(9,232 )
(3,055 )
(6,177 )
13
2015 Financial Results
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
(In millions)
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
14,760
266
—
15,026
1,855
4,318
3,749
242
1,282
268
978
42
12,734
2,292
(22 )
(362 )
(1,132 )
117
(1,399 )
893
315
578
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Operating Income
Other Income (Expense):
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total Other Expense
Income Before Income Taxes
Income taxes
Net Income
$
9,386 $
196
—
9,582
1,054 $
—
—
1,054
4,493 $
205
686
5,384
(173 ) $
(135 )
(686 )
(994 )
533
3,548
2,240
179
664
261
703
8
8,136
1,446
42
—
(600 )
25
(533 )
—
—
156
3
164
7
102
—
432
622
—
—
(147 )
44
(103 )
1,322
1,456
1,670
60
394
—
140
34
5,076
308
(16 )
—
(192 )
39
(169 )
—
(686 )
(317 )
—
60
—
33
—
(910 )
(84 )
(48 )
(362 )
(193 )
9
(594 )
913
325
588 $
519
191
328 $
139
50
89 $
$
(678 )
(251 )
(427 ) $
14
Changes Between 2016 and 2015 Financial
Results Increase (Decrease)
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
(In millions)
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Investment income
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total Other Expense
$
15 $
32
—
47
97 $
—
—
97
(601 ) $
(27 )
(207 )
(835 )
(8 ) $
28
207
227
34
(275 )
196
(78 )
12
52
17
(8 )
(50 )
97
7
—
14
(5 )
16
—
—
5
(2 )
23
—
51
—
77
20
—
—
(11 )
(10 )
(21 )
(223 )
(437 )
(144 )
(15 )
(7 )
—
(6 )
10,631
9,799
(10,634 )
82
—
(2 )
(2 )
78
—
207
52
—
3
—
2
—
264
(37 )
17
362
(26 )
3
356
(497 )
33
—
(464 )
(189 )
(505 )
109
(95 )
31
52
64
10,623
10,090
(10,554 )
106
362
(25 )
(14 )
429
Income (Loss) Before Income Taxes (Benefits)
Income taxes (benefits)
Net Income (Loss)
113
50
63 $
$
(1 )
(4 )
3 $
(10,556 )
(3,548 )
(7,008 ) $
319
132
187 $
(10,125 )
(3,370 )
(6,755 )
15
Regulated Distribution — 2016 Compared with 2015
Regulated Distribution's net income increased $63 million in 2016 compared to 2015, including a $78 million decrease in its
Pension and OPEB mark-to-market adjustment, partially offset by regulatory charges of $51 million resulting from the PUCO's
March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV. Excluding the impact
of these adjustments, year-over-year earnings reflect higher distribution deliveries and the full year impact of net rate increases
implemented in 2015 as a result of approved rate cases at certain of the Utilities, as further described below, partially offset by
higher retirement benefit costs and other operating expenses.
Revenues —
The $47 million increase in total revenues resulted from the following sources:
Revenues by Type of Service
2016
2015
(Decrease)
Distribution services
$
4,785 $
4,510 $
275
(In millions)
For the Years Ended
December 31
Increase
Generation sales:
Retail
Wholesale
Total generation sales
Other
Total Revenues
4,119
497
4,616
228
9,629 $
4,303
573
4,876
196
9,582 $
(184 )
(76 )
(260 )
32
47
$
Distribution services revenues increased $275 million primarily resulting from the full year impact of approved base distribution
rate increases at the Pennsylvania Companies, effective May 3, 2015, and MP and PE in West Virginia, effective February 25,
2015, partially offset by a distribution rate decrease at JCP&L, including the recovery of 2011 and 2012 storm costs, effective April
1, 2015. Additionally, distribution revenues were impacted by higher rates associated with the recovery of deferred costs as well
as higher weather-related usage, as described below. Distribution deliveries by customer class are summarized in the following
table:
Electric Distribution MWH Deliveries
2016
2015
(Decrease)
For the Years Ended
December 31
Increase
Residential
Commercial
Industrial
Other
Total Electric Distribution MWH Deliveries
(In thousands)
54,840
43,340
50,082
579
148,841
54,466
43,091
50,269
585
148,411
0.7 %
0.6 %
(0.4 )%
(1.0 )%
0.3 %
Higher distribution deliveries to residential and commercial customers reflect increased weather-related usage resulting from
cooling degree days that were 18% above 2015, and 37% above normal, partially offset by heating degree days that were 6%
below 2015, and 9% below normal. Additionally, distribution deliveries to residential and commercial customers were impacted by
declining average customer usage associated with more energy efficient products and services. Year-to-date deliveries to industrial
customers declined slightly as the increase from shale customer usage was more than offset by a decrease from steel and
chemical customer usage.
16
The following table summarizes the price and volume factors contributing to the $260 million decrease in generation revenues in
2016, as compared to 2015:
Source of Change in Generation Revenues
Increase
(Decrease)
(In millions)
Retail:
Effect of decrease in sales volumes
$
Change in prices
Wholesale:
Effect of increase in sales volumes
Change in prices
Capacity revenue
Decrease in Generation Revenues
$
(196 )
12
(184 )
47
(107 )
(16 )
(76 )
(260 )
The decrease in retail generation sales volumes was primarily due to increased customer shopping in Ohio, Pennsylvania, and
New Jersey. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 83% from
80% for the Ohio Companies, to 67% from 65% for the Pennsylvania Companies and to 51% from 50% for JCP&L. The increase
in retail generation prices primarily resulted from an ENEC rate increase in West Virginia, effective January 1, 2016, partially offset
by lower default service auction prices in Ohio and Pennsylvania.
Wholesale generation revenues decreased $76 million in 2016 compared to the same period of 2015, primarily due to lower spot
market energy prices, partially offset by higher wholesale sales. The difference between current wholesale generation revenues
and certain energy costs incurred is deferred for future recovery or refund, with no material impact to earnings.
Other revenues increased $32 million, primarily related to a $29 million gain on the sale of oil and gas rights at WP.
Operating Expenses —
Total operating expenses decreased $50 million primarily due to the following:
• Fuel expense increased $34 million in 2016, as compared to the same period of 2015, primarily related to higher
generation.
• Purchased power costs decreased $275 million in 2016, as compared to the same period of 2015, primarily due to lower
volumes resulting from increased customer shopping, as described above, as well as lower unit costs reflecting lower
default service auction prices in Ohio and Pennsylvania.
17
Source of Change in Purchased Power
Increase
(Decrease)
(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs
$
Change due to decreased volumes
Purchases from affiliates:
Change due to decreased unit costs
Change due to decreased volumes
Capacity expense
Amortization of deferred costs
Decrease in Purchased Power Costs
$
(133 )
(6 )
(139 )
(2 )
(204 )
(206 )
(5 )
75
(275 )
• Other operating expenses increased $196 million primarily due to:
• An increase of $51 million resulting from the recognition of economic development and energy efficiency
obligations in accordance with the PUCO's March 31, 2016 Opinion and Order adopting and approving, with
modifications, the Ohio Companies' ESP IV.
• Higher retirement benefit costs of $57 million.
• Higher transmission expenses of $56 million primarily related to an increase in network transmission expenses
at the Ohio Companies, partially offset by lower congestion expenses at MP. The difference between current
revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material
impact on current period earnings.
• Higher operating and maintenance expense of $33 million, primarily due to increased storm restoration costs,
which are deferred for future recovery resulting in no material impact on current period earnings.
• Pension and OPEB mark-to-market adjustments decreased $78 million to $101 million in 2016. The 2016 adjustment
resulted from a 25 bps decrease in the discount rate used to measure benefit obligations partially offset by higher than
expected asset returns and changes in certain actuarial assumptions.
• Depreciation expenses increased $12 million due to a higher asset base.
• Net amortization of regulatory assets increased $52 million primarily due to:
• A full year recovery of storm costs in New Jersey, Pennsylvania, and West Virginia, effective with the
implementation of new rates as discussed above ($35 million),
• Recovery of West Virginia vegetation management program costs ($40 million), partially offset by
• Higher deferral of storm restoration costs ($39 million).
• General taxes increased $17 million primarily due to higher revenue-related taxes in Pennsylvania and higher property
taxes in Ohio.
Other Expense —
Total other expense decreased $16 million primarily related to lower interest expense resulting from various debt maturities at
JCP&L and OE in 2016.
Income Taxes —
Regulated Distribution’s effective tax rate was 36.5% and 35.6% for 2016 and 2015, respectively.
18
Regulated Transmission — 2016 Compared with 2015
Net income increased $3 million in 2016 compared to 2015, primarily resulting from a higher rate base, partially offset by
adjustments associated with ATSI and TrAIL's annual rate filing for costs previously recovered, a lower return on equity at ATSI,
and lower capitalized financing costs.
Revenues —
Total revenues increased $97 million principally due to recovery of incremental operating expenses and a higher rate base at ATSI
and TrAIL, partially offset by adjustments associated with ATSI's and TrAIL's annual rate filing for costs previously recovered as
well as a lower ROE at ATSI under its FERC-approved comprehensive settlement related to the implementation of its forward-
looking rate effective January 1, 2015.
Revenues by transmission asset owner are shown in the following table:
Revenues by Transmission Asset Owner
2016
2015
(Decrease)
For the Years Ended
December 31
Increase
ATSI
TrAIL
PATH
Utilities
Total Revenues
Operating Expenses —
(In millions)
540 $
252
12
347
1,151 $
446 $
252
13
343
1,054 $
$
$
94
—
(1 )
4
97
Total operating expenses increased $77 million principally due to higher property taxes and depreciation expense at ATSI, which
are recovered through ATSI's forward-looking formula rate.
Other Expenses —
Other expense increased $21 million in 2016, as compared to 2015, primarily due to lower capitalized financing costs resulting
from lower construction work in progress balances at ATSI as well as increased interest expense resulting from a long-term debt
issuance of $150 million at ATSI in the fourth quarter of 2015, the proceeds of which, in part, paid off short-term borrowings.
Income Taxes —
Regulated Transmission’s effective tax rate was 36.1% and 36.8% for 2016 and 2015, respectively.
CES — 2016 Compared with 2015
Operating results decreased $7,008 million in 2016 compared to 2015, primarily resulting from pre-tax asset impairment charges
of $10,665 million discussed above, partially offset by lower mark-to-market gains on commodity contract positions, a lower
Pension and OPEB mark-to-market adjustment and lower settlement and termination costs related to coal contracts. Excluding
these items, year-over-year operating results were impacted by lower capacity revenues, lower sales volumes, a termination
charge associated with an FES customer contract, and higher retirement and employee benefit costs, partially offset by lower fuel
costs, reduced transmission expenses, and lower purchased power.
Revenues —
Total revenues decreased $835 million in 2016, as compared to 2015, primarily due to decreased sales volumes and lower capacity
revenue, partially offset by higher net gains on financially settled contracts and an increase in short-term (net hourly position)
transactions, as further described below.
19
The decrease in total revenues resulted from the following sources:
Revenues by Type of Service
Contract Sales:
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Total Contract Sales
Wholesale
Transmission
Other
Total Revenues
MWH Sales by Channel
Contract Sales:
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Total Contract Sales
Wholesale
Total MWH Sales
For the Years Ended
December 31
2016
2015
(In millions)
Increase
(Decrease)
$
$
812 $
814
169
583
463
2,841
1,457
73
178
4,549 $
1,269 $
1,012
265
712
558
3,816
1,225
138
205
5,384 $
(457 )
(198 )
(96 )
(129 )
(95 )
(975 )
232
(65 )
(27 )
(835 )
For the Years Ended
December 31
2016
2015
(In thousands)
Increase
(Decrease)
15,310
13,730
2,431
9,969
11,414
52,854
15,201
68,055
23,585
15,443
3,878
11,950
12,902
67,758
7,326
75,084
(35.1 )%
(11.1 )%
(37.3 )%
(16.6 )%
(11.5 )%
(22.0 )%
107.5 %
(9.4 )%
The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Revenues
Increase (Decrease)
MWH Sales Channel:
Sales
Volumes
Prices
Gain on
Settled
Contracts
(In millions)
Capacity
Revenue
Total
Direct
$
(445 )
$
(12 ) $
Governmental Aggregation
Mass Market
POLR
Structured Sales
Wholesale
(112 )
(99 )
(118 )
(64 )
223
(86 )
3
(11 )
(31 )
(10 )
— $
—
—
—
—
98
— $
—
—
—
—
(79 )
(457 )
(198 )
(96 )
(129 )
(95 )
232
Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflects the continuation
of FES' strategy to more effectively hedge its generation, as discussed above. The Direct, Governmental Aggregation, and Mass
Market customer base was 1.1 million as of December 31, 2016, compared to 1.6 million as of December 31, 2015. Although unit
20
pricing was lower year-over-year in the Direct and Governmental Aggregation channels, the decrease was primarily attributable to
lower capacity expenses, as discussed below, which is a component of the retail price.
The decrease in POLR sales of $129 million was primarily due to lower volumes. Structured Sales decreased $95 million, primarily
due to the impact of lower market prices and lower structured transaction volumes.
Wholesale revenues increased $232 million, primarily due to an increase in short-term (net hourly position) transactions and higher
net gains on financially settled contracts, partially offset by a decrease in capacity revenue from lower capacity auction prices and
lower spot market energy prices.
Transmission revenue decreased $65 million, primarily due to lower congestion revenue associated with less volatile market
conditions.
Other revenue decreased $27 million, primarily due to the absence of a gain on the sale of property to a regulated affiliate in 2015
and lower lease revenues from the expiration of a nuclear sale-leaseback agreement.
Operating Expenses —
Total operating expenses increased $9,799 million in 2016 due to the following:
• Fuel costs decreased $223 million, primarily due to lower generation associated with outages and lower economic
dispatch of fossil units resulting from low wholesale spot market energy prices, as discussed above, as well as lower unit
prices on fossil fuel contracts. Additionally, fuel costs were impacted by lower settlement and termination costs on coal
contracts. The impact of settlements and terminations of coal contracts resulted in a pre-tax loss of $58 million and $67
million in 2016 and 2015, respectively.
• Purchased power costs decreased $437 million due to lower capacity expenses ($234 million) and lower volumes ($203
million). The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower
contract sales and lower capacity rates associated with CES' retail sales obligations. Lower volumes primarily resulted
from lower contract sales, as discussed above, partially offset by higher economic purchases, resulting from the low
wholesale spot market price environment.
• Fossil operating costs increased $4 million, primarily due to increased outage costs and higher employee benefit costs,
partially offset by lower operating costs from the deactivation of certain fossil plants in April 2015.
• Nuclear operating costs decreased $39 million, primarily as a result of lower refueling outage costs, partially offset by
higher employee benefit costs. There were two refueling outages in 2016 as compared to three refueling outages in 2015.
• Retirement benefit costs increased $31 million.
• Transmission expenses decreased $175 million, primarily due to lower congestion and market-based ancillary costs
associated with less volatile market conditions as compared to 2015, as well as lower load requirements.
• Other operating expenses increased $35 million, primarily due to lower mark-to-market gains on commodity contract
positions of $84 million and a $37 million charge associated with the termination of an FES customer contract, partially
offset by lower lease expense as a result of the expiration of a nuclear sale-leaseback agreement.
• Pension and OPEB mark-to-market adjustments decreased $15 million to $45 million in 2016. The 2016 adjustment
resulted from a 25 bps decrease in the discount rate used to measure benefit obligations, partially offset by higher than
expected asset returns and changes in other actuarial assumptions.
• Depreciation expense decreased $7 million, primarily as a result of an out-of-period adjustment to reduce depreciation of
a hydroelectric generating station, partially offset by a higher asset base.
• General taxes decreased $6 million, primarily due to lower gross receipts taxes associated with lower retail sales
volumes.
•
Impairment of assets increased $10,631 million, primarily due to impairments of goodwill and the competitive generation
assets discussed above.
21
Other Expense —
Total other expense decreased $78 million in 2016 compared to 2015 primarily due to lower OTTI on NDT investments.
Income Taxes (Benefits) —
CES' effective tax rate was 33.6% on pre-tax losses and 36.0% on pre-tax income for 2016 and 2015, respectively. The change
in the effective tax rate is primarily due to $168 million of valuation allowances recorded against state and local NOL carryforwards
and $78 million of valuation allowances recorded against state and local property deferred tax assets, that management believes,
more likely than not, will not be realized, as well as the impairment of $800 million of goodwill, of which $433 million is non-
deductible for tax purposes.
Corporate/Other — 2016 Compared with 2015
Financial results and reconciling items included in Corporate/Other resulted in a $187 million increase in net income in 2016
compared to 2015 primarily due to the absence of a $362 million pre-tax impairment of FirstEnergy's equity method investment in
Global Holding recognized in 2015. Excluding the impact of this adjustment, year-over-year results were impacted by higher
operating and maintenance costs, higher interest expense and changes in the consolidated effective tax rate, which for 2016 was
33.1% on pre-tax losses and for 2015 was 35.5% on pre-tax income. The increased interest expense primarily relates to debt
redemption costs related to the FE revolving credit facility and term loans, as discussed in "Capital Resources and Liquidity". The
higher consolidated effective tax rate primarily resulted from the absence of tax benefits recognized in 2015 associated with an
IRS-approved change in accounting method that increased the tax basis in certain assets resulting in higher future tax deductions,
as well as from changes in state apportionment factors.
22
Summary of Results of Operations — 2015 Compared with 2014
Financial results for FirstEnergy’s business segments in 2015 and 2014 were as follows:
2015 Financial Results
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
(In millions)
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Operating Income
Other Income (Expense):
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized interest
Total Other Expense
Income From Continuing Operations Before
Income Taxes
Income taxes
Income From Continuing Operations
Discontinued Operations, net of tax
Net Income
$
9,386 $
196
—
9,582
1,054 $
—
—
1,054
4,493 $
205
686
5,384
(173 ) $
(135 )
(686 )
(994 )
533
3,548
2,240
179
664
261
703
8
8,136
1,446
42
—
(600 )
25
(533 )
—
—
156
3
164
7
102
—
432
622
—
—
(147 )
44
(103 )
1,322
1,456
1,670
60
394
—
140
34
5,076
308
(16 )
—
(192 )
39
(169 )
913
325
588
—
588 $
519
191
328
—
328 $
139
50
89
—
89 $
$
—
(686 )
(317 )
—
60
—
33
—
(910 )
(84 )
(48 )
(362 )
(193 )
9
(594 )
(678 )
(251 )
(427 )
—
(427 ) $
14,760
266
—
15,026
1,855
4,318
3,749
242
1,282
268
978
42
12,734
2,292
(22 )
(362 )
(1,132 )
117
(1,399 )
893
315
578
—
578
23
2014 Financial Results
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
(In millions)
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
$
8,850 $
204
—
9,054
817 $
—
—
817
5,281 $
189
819
6,289
(193 ) $
(99 )
(819 )
(1,111 )
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Investment income
Impairment of equity method investment
Interest expense
Capitalized interest
Total Other Expense
567
3,385
2,077
506
651
1
692
—
7,879
1,175
56
—
(603 )
14
(533 )
—
—
143
2
134
11
71
—
361
456
—
—
(117 )
55
(62 )
1,713
2,150
2,075
327
387
—
171
—
6,823
(534 )
54
—
(197 )
37
(106 )
14,755
294
—
15,049
2,280
4,716
3,962
835
1,220
12
962
—
13,987
1,062
72
—
(1,081 )
118
(891 )
171
(42 )
213
86
299
—
(819 )
(333 )
—
48
—
28
—
(1,076 )
(35 )
(38 )
—
(164 )
12
(190 )
(225 )
(167 )
(58 )
—
(58 ) $
Income (Loss) From Continuing Operations
Before Income Taxes (Benefits)
Income taxes (benefits)
Income (Loss) From Continuing Operations
Discontinued Operations, net of tax
Net Income (Loss)
$
642
209
433
—
433 $
394
139
255
—
255 $
(640 )
(223 )
(417 )
86
(331 ) $
24
Changes Between 2015 and 2014 Financial
Results Increase (Decrease)
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
(In millions)
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets
Total Operating Expenses
Operating Income
Other Income (Expense):
Investment loss
Impairment of equity method investment
Interest expense
Capitalized interest
Total Other Expense
$
536 $
(8 )
—
528
237 $
—
—
237
(788 ) $
16
(133 )
(905 )
20 $
(36 )
133
117
(34 )
163
163
(327 )
13
260
11
8
257
271
(14 )
—
3
11
—
—
—
13
1
30
(4 )
31
—
71
166
—
—
(30 )
(11 )
(41 )
(391 )
(694 )
(405 )
(267 )
7
—
(31 )
34
(1,747 )
842
(70 )
—
5
2
(63 )
779
273
506
(86 )
420 $
—
133
16
—
12
—
5
—
166
(49 )
(10 )
(362 )
(29 )
(3 )
(404 )
(453 )
(84 )
(369 )
—
(369 ) $
5
(28 )
—
(23 )
(425 )
(398 )
(213 )
(593 )
62
256
16
42
(1,253 )
1,230
(94 )
(362 )
(51 )
(1 )
(508 )
722
357
365
(86 )
279
Income From Continuing Operations Before
Income Taxes
Income taxes
Income From Continuing Operations
Discontinued Operations, net of tax
Net Income
271
116
155
—
155 $
125
52
73
—
73 $
$
25
Regulated Distribution — 2015 Compared with 2014
Regulated Distribution's net income increased $155 million in 2015 compared to 2014, including a $327 million decrease in its
Pension and OPEB mark-to-market adjustment. Excluding the impact of this adjustment, year-over-year earnings were impacted
by increased operating expenses, including higher reliability maintenance expenses, higher benefit costs, and higher depreciation
associated with increased capital investments, and a higher effective tax rate, partially offset by a net increase in new rates
implemented in 2015 at certain of the Utilities.
Revenues —
The $528 million increase in total revenues resulted from the following sources:
Revenues by Type of Service
2015
2014
(Decrease)
Distribution services
$
4,510 $
4,056 $
454
(In millions)
For the Years Ended
December 31
Increase
Generation sales:
Retail
Wholesale
Total generation sales
Other
Total Revenues
4,303
573
4,876
196
9,582 $
4,043
751
4,794
204
9,054 $
260
(178 )
82
(8 )
528
$
Distribution services revenues increased $454 million primarily resulting from approved base distribution rate increases at the
Pennsylvania Companies, effective May 3, 2015, and at MP and PE in West Virginia, effective February 25, 2015, partially offset
by a distribution rate decrease at JCP&L, including the recovery of 2011 and 2012 storm costs, effective April 1, 2015. Additionally,
distribution revenues were impacted by higher rates associated with the recovery of deferred costs, as well as higher weather-
related usage, as described below. Partially offsetting these items were the impacts of lower residential and industrial customer
usage as described below. Distribution deliveries by customer class are summarized in the following table:
Electric Distribution MWH Deliveries
2015
2014
(Decrease)
For the Years Ended
December 31
Increase
Residential
Commercial
Industrial
Other
Total Electric Distribution MWH Deliveries
(In thousands)
54,466
43,091
50,269
585
148,411
54,766
42,925
51,276
586
149,553
(0.5 )%
0.4 %
(2.0 )%
(0.2 )%
(0.8 )%
Lower deliveries to residential customers, reflect declining weather-adjusted average customer usage due, in part, to increasing
energy efficiency products and services as well as heating degree days that were 10.8% below the same period in 2014 and 2.8%
below normal, partially offset by cooling degree days that were 32% above 2014 and 17% above normal. Commercial sales
increased year-over-year from the increase in cooling degree days, partially offset by the lower heating degree days as well as
decreased weather-adjusted average customer usage similar to the impact to residential customers. Deliveries to industrial
customers decreased 2%, as the increase from shale and petroleum customer usage was more than offset by a decrease from
steel and mining customer usage.
26
The following table summarizes the price and volume factors contributing to the $82 million increase in generation revenues in
2015 compared to 2014:
Source of Change in Generation Revenues
Increase
(Decrease)
(In millions)
Retail:
Effect of increase in sales volumes
$
Change in prices
Wholesale:
Effect of decrease in sales volumes
Change in prices
Capacity revenue
Increase in Generation Revenues
$
146
114
260
(151 )
(82 )
55
(178 )
82
The increase in retail generation sales volume was primarily due to lower customer shopping in Ohio, Pennsylvania, and New
Jersey and an increase in weather-related usage, partially offset by the impacts of energy efficiency as described above. Total
generation provided by alternative suppliers as a percentage of total MWH deliveries decreased to 80% from 81% for the Ohio
Companies, 65% from 67% for the Pennsylvania Companies and 50% from 52% for JCP&L. The increase in prices primarily
resulted from higher default service auction prices.
Wholesale generation revenue decreased $178 million in 2015 compared to 2014, primarily reflecting decreased volume
associated with the termination of certain NUG contracts at JCP&L and PN and lower economic dispatch of fossil generating units
associated with low spot market energy prices. Partially offsetting the decrease was an increase in capacity revenue resulting from
higher capacity prices. The difference between current wholesale generation revenues and certain energy costs incurred are
deferred for future recovery, with no material impact on earnings.
Operating Expenses —
Total operating expenses increased $257 million primarily due to the following:
• Fuel expense decreased $34 million in 2015 primarily related to lower economic dispatch resulting from low spot market
energy prices.
• Purchased power costs were $163 million higher in 2015 primarily due to increased volumes reflecting lower customer
shopping as described above, higher unit costs related to higher default service auction prices, and higher capacity
expense at MP, partially offset by lower volumes resulting from the termination of certain NUG contracts at JCP&L and
PN.
27
Source of Change in Purchased Power
Increase
(Decrease)
(In millions)
Purchases from non-affiliates:
Change due to increased unit costs
$
Change due to increased volumes
Purchases from affiliates:
Change due to decreased unit costs
Change due to decreased volumes
Capacity expense
Amortization of deferred costs
Increase in Purchased Power Costs
$
66
185
251
(21 )
(113 )
(134 )
36
10
163
Other operating expenses increased $163 million primarily due to:
• Higher transmission expenses of $73 million primarily due to an increase in network transmission expenses at
the Ohio Companies, partially offset by lower congestion expenses at MP. The differences between current retail
transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material
impact on current period earnings.
•
Increased regulated generation operating and maintenance expenses of $7 million, reflecting higher planned
outage expenses in 2015 compared to 2014.
• Higher retirement benefit costs of $22 million.
• Higher distribution operating and maintenance expenses of $61 million, reflecting increased reliability
maintenance and other employee benefit costs, partially offset by lower storm restoration costs.
• Pension and OPEB mark-to-market adjustments decreased $327 million to $179 million, which was impacted by lower
than expected asset returns, partially offset by an increase in the discount rate used to measure benefit obligations.
• Depreciation expense increased $13 million due to a higher asset base, partially offset by lower depreciation rates at
JCP&L effective with the implementation of new rates from its distribution base rate case as well as lower depreciation
rates in Pennsylvania based on updated asset life studies approved by the PPUC.
• Net regulatory asset amortization increased $260 million primarily due to:
• Recovery of storm costs in New Jersey, Pennsylvania, and West Virginia effective with the implementation of
new rates as discussed above ($66 million),
• Higher energy efficiency program cost recovery ($66 million),
• Lower deferral of TTS costs in West Virginia ($37 million),
• Higher amortizations of above-market NUG costs in Pennsylvania and New Jersey ($36 million),
• Lower deferral of West Virginia vegetation management expenses ($31 million),
• Higher default generation service cost amortization ($28 million), and
• Recovery of Pennsylvania legacy meter costs ($22 million); partially offset by
• Higher cost deferral of Ohio network transmission expenses ($33 million).
• General taxes increased $11 million primarily due to higher revenue-related taxes in Pennsylvania, partially offset by
lower property taxes in Ohio.
28
Other Expense —
Other expense was flat in 2015 as compared to 2014, as lower investment income was offset by lower interest expense and higher
capitalized financing costs.
Income Taxes —
Regulated Distribution’s effective tax rate was 35.6% and 32.6% for 2015 and 2014, respectively. The increase in the effective tax
rate resulted from changes in state apportionment factors and tax benefits recognized in 2014.
Regulated Transmission — 2015 Compared with 2014
Net income increased $73 million in 2015 compared to 2014. Higher Transmission revenues associated with ATSI's "forward
looking" rate and higher rate base were partially offset by higher interest expense and lower capitalized financing costs.
Revenues —
Total revenues increased $237 million principally at ATSI and TrAIL, reflecting recovery of incremental operating expenses and a
higher rate base. Effective January 1, 2015, ATSI's formula rate transitioned to a "forward looking" approach, where transmission
revenues are based on actual costs.
Revenues by transmission asset owner are shown in the following table:
Revenues by Transmission Asset Owner
2015
2014
Increase
(Decrease)
For the Years Ended
December 31
ATSI
TrAIL
PATH
Utilities
Total Revenues
Operating Expenses —
(In millions)
$
$
446 $
252
13
343
1,054 $
242 $
214
13
348
817 $
204
38
—
(5 )
237
Total operating expenses increased $71 million principally due to higher operating and maintenance expenses, depreciation, and
property taxes at ATSI, which are recovered through ATSI's "forward looking" rate.
Other Expenses —
Other expenses increased $41 million due to increased interest expense resulting from debt issuances of $1.0 billion at FET and
$400 million at ATSI, the proceeds of which, in part, paid off short term borrowings as well as lower capitalized financing costs.
Income Taxes —
Regulated Transmission’s effective tax rate was 36.8% and 35.3% for 2015 and 2014, respectively. The increase in the effective
tax rate resulted from changes in state apportionment factors and tax benefits recognized in 2014.
CES — 2015 Compared with 2014
Operating results increased $420 million in 2015, compared to 2014, primarily from higher capacity revenues and the absence of
the impact of the high market prices associated with extreme weather events and unplanned outages in 2014 that resulted in
higher purchased power and transmission costs, partially offset by lower contract sales volumes. Additionally, changes in year-
over-year operating results were impacted by lower Pension and OPEB mark-to-market adjustments, lower settlement and
29
termination costs related to coal and transportation contracts, and the absence of a $78 million after-tax gain on the sale of certain
hydroelectric facilities recognized in February 2014.
Revenues —
Total revenues decreased $905 million in 2015, compared to 2014, primarily due to decreased sales volumes. Revenues were
also impacted by higher unit prices compared to 2014 as a result of increased channel pricing, as well as higher capacity revenues,
as further described below.
The decrease in total revenues resulted from the following sources:
Revenues by Type of Service
2015
2014
(Decrease)
For the Years Ended
December 31
Increase
Contract Sales:
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Total Contract Sales
Wholesale
Transmission
Other
Total Revenues
(In millions)
1,269 $
1,012
265
712
558
3,816
1,225
138
205
5,384 $
2,359 $
1,184
452
902
522
5,419
461
220
189
6,289 $
(1,090 )
(172 )
(187 )
(190 )
36
(1,603 )
764
(82 )
16
(905 )
$
$
MWH Sales by Channel
2015
2014
(Decrease)
For the Years Ended
December 31
Increase
Contract Sales:
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Total Contract Sales
Wholesale
Total MWH Sales
NM - Not Meaningful
(In thousands)
23,585
15,443
3,878
11,950
12,902
67,758
7,326
75,084
44,012
19,569
6,773
15,708
12,814
98,876
680
99,556
(46.4 )%
(21.1 )%
(42.7 )%
(23.9 )%
0.7 %
(31.5 )%
NM
(24.6 )%
30
The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Revenues
Increase (Decrease)
MWH Sales Channel:
Sales
Volumes
Prices
Gain on
Settled
Contracts
Capacity
Revenue
Total
(In millions)
Direct
$
(1,095 ) $
Governmental Aggregation
Mass Market
POLR
Structured Sales
Wholesale
(249 )
(193 )
(216 )
3
197
5 $
77
6
26
33
(8 )
— $
—
—
—
—
107
— $ (1,090 )
—
(172 )
—
—
—
468
(190 )
36
764
(187 )
Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflecting FES' strategy
to more effectively hedge its generation as discussed above. Although unit pricing was higher year-over-year in the Direct,
Governmental Aggregation, and Mass Market channels, the increase was primarily attributable to higher capacity expense as
discussed below, which is a component of the retail price, partially offset by a lower energy component of the retail price resulting
from lower year-over-year market prices. The Direct, Governmental Aggregation and Mass Market customer base was 1.6 million
as of December 31, 2015, compared to 2.1 million as of December 31, 2014.
The decrease in POLR sales of $190 million was due to lower volumes, partially offset by higher rates associated with POLR
auctions. Structured Sales increased $36 million due to low market prices that increased the gains on various structured financial
sales contracts and higher structured transaction volumes.
Wholesale revenues increased $764 million, primarily due to an increase in capacity revenue from capacity auctions, increase in
short-term (net hourly position) transactions, and higher net gains on financially settled contracts, partially offset by lower spot
market energy prices, which limited additional wholesale sales.
Transmission revenue decreased $82 million, primarily due to lower congestion revenue resulting from the market conditions
associated with the extreme weather events in 2014.
Other revenue increased $16 million, primarily due to a gain on the sale of property to a regulated affiliate in 2015 and higher lease
revenues from additional equity interests in affiliated sale and leasebacks repurchased in November 2014. CES earns lease
revenue associated with the equity interests it purchased.
Operating Expenses —
Total operating expenses decreased $1,747 million in 2015 due to the following:
• Fuel costs decreased $391 million, primarily due to lower economic dispatch of fossil units resulting from low spot market
energy prices and lower nuclear unit prices, resulting from the suspension of the DOE nuclear disposal fee, effective May
16, 2014. Additionally, fuel costs were impacted by a decrease in settlement and termination costs related to coal and
transportation contracts. The impact of terminations and settlements of coal and transportation contracts resulted in a
pre-tax loss of $67 million and $166 million in 2015 and 2014, respectively.
• Purchased power costs decreased $694 million due to lower volumes ($888 million), partially offset by higher unit prices
($39 million) and higher capacity expenses ($155 million). Lower volumes were primarily due to decreased load
requirements resulting from lower sales, as discussed above, partially offset by lower fossil generation, as discussed
above. The higher unit prices are primarily due to higher losses on financially settled contracts, partially offset by lower
market prices in 2015 as compared to 2014. The increase in capacity expense, which is a component of CES' retail price,
was primarily the result of higher capacity rates associated with CES' retail sales obligations.
31
• Nuclear operating costs increased $84 million as a result of higher refueling outage costs and higher employee benefit
expenses. There were three refueling outages in 2015 as compared to two refueling outages in 2014.
• Transmission expenses decreased $273 million, primarily due to lower operating reserve and market-based ancillary
costs associated with market conditions resulting from the extreme weather events in 2014.
• General taxes decreased $31 million, primarily due to lower gross receipts taxes associated with lower retail sales
volumes.
• Pension and OPEB mark-to-market adjustments decreased $267 million to $60 million, which was impacted by lower
than expected asset returns, partially offset by an increase in the discount rate used to measure benefit obligations.
• Other operating expenses decreased $216 million, primarily due to a $141 million decrease in mark-to-market expenses
on commodity contract positions reflecting lower market prices and a $71 million decrease in retail-related costs.
•
Impairment of assets were $34 million in 2015 due to impairment charges associated with non-core assets.
Other Expense —
Total other expense increased $63 million in 2015 compared to 2014 primarily due to higher OTTI on NDT investments, partially
offset by the absence of an $8 million loss on debt redemptions in 2014.
Discontinued Operations —
There were no discontinued operations in 2015. In 2014, discontinued operations primarily included a pre-tax gain of approximately
$142 million ($78 million after-tax) associated with the sale of certain hydroelectric assets on February 12, 2014.
Income Tax (Benefits) —
CES' effective tax rate was 36.0% and 34.8% for 2015 and 2014, respectively. The increase in the effective tax rate resulted from
changes in state apportionment factors and realized tax benefits recognized in 2014.
Corporate/Other — 2015 Compared with 2014
Financial results and reconciling items included in Corporate/Other resulted in a $369 million decrease in net income in 2015
compared to 2014 primarily due to a $362 million pre-tax impairment of FirstEnergy's equity method investment in Global Holding,
higher costs associated with environmental remediation at legacy plants, higher interest expense and a higher effective tax rate.
During 2015, based on the significant decline in coal pricing and the current outlook for the coal market, FirstEnergy assessed the
carrying value of its investment in Global Holding and determined there was an other than temporary decline in the fair value below
its carrying value, which resulted in the impairment charge. The increased interest expense primarily relates to FE's $1 billion term
loan entered into in March 2014 and the absence of a gain on the termination of interest rate swaps in 2014. The higher effective
tax rate primarily resulted from the absence of tax benefits recognized in 2014 associated with an IRS-approved change in
accounting method that increased the tax basis in certain assets resulting in higher future tax deductions, a reduction in state
deferred tax liabilities resulting from changes in state apportionment factors, the elimination of certain tax liabilities associated with
basis differences as well as certain tax benefits recorded in 2014 that related to prior periods.
Regulatory Assets
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers
through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future
regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory
assets and liabilities based on federal and state jurisdictions. The following table provides information about the composition of
net regulatory assets as of December 31, 2016 and December 31, 2015, and the changes during the year ended December 31,
2016:
32
Regulatory Assets (Liabilities) by Source
December 31,
2016
December 31,
2015
Increase
(Decrease)
(In millions)
Regulatory transition costs
$
Customer receivables for future income taxes
Nuclear decommissioning and spent fuel disposal costs
Asset removal costs
Deferred transmission costs
Deferred generation costs
Deferred distribution costs
Contract valuations
Storm-related costs
Other
Net Regulatory Assets included on the Consolidated Balance Sheets
$
90 $
444
(304 )
(470 )
127
215
296
153
353
110
1,014 $
185 $
355
(272 )
(372 )
115
243
335
186
403
170
1,348 $
(95 )
89
(32 )
(98 )
12
(28 )
(39 )
(33 )
(50 )
(60 )
(334 )
Regulatory assets that do not earn a current return totaled approximately $153 million and $148 million as of December 31, 2016
and 2015, respectively, primarily related to storm damage costs, and are currently being recovered through rates.
As of December 31, 2016 and December 31, 2015, FirstEnergy had approximately $157 million and $116 million of net regulatory
liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified within other noncurrent liabilities
on the Consolidated Balance Sheets.
33
CAPITAL RESOURCES AND LIQUIDITY
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.
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 2017 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, including cash
requirements to fund Regulated Transmission's capital program, may be met through a combination of an additional $500 million
of equity in each year 2017 through 2019, and new long-term debt, in each case, subject to market conditions and other factors.
FirstEnergy also expects to issue long-term debt at certain Utilities to, among other things, 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, the unregulated companies' money pool, and proceeds generated from previously disclosed asset sales, subject to
closing, and with respect to FES, a two-year secured line of credit with FE of up to $500 million, as further described below.
Additionally, FES subsidiaries have debt maturities in 2017 and 2018 of $130 million and $515 million, respectively. The inability
to refinance such debt maturities could cause FES to take one or more of the following actions: (i) restructuring of debt and other
financial obligations, (ii) additional borrowings under its credit facility with FE, (iii) further asset sales or plant deactivations, and/or
(iv) seek protection under U.S. bankruptcy laws. In the event FES seeks such protection, FENOC may similarly seek protection
under U.S. bankruptcy laws.
In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed funding obligations for future
years 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.
Capital expenditures for 2016 and anticipated expenditures for 2017 and 2018 by reportable segment are included below:
Reportable Segment
2016 Actual(1)
2016
Pension/OPEB
Mark-to-
Market Capital
Costs
2016 Actual
Excluding
Pension/OPEB
Mark-to-Market
Capital Costs
(In millions)
2017
Forecast(2)
2018
Forecast(2)
$
Regulated Distribution
Regulated Transmission(4)
CES(3)
Corporate/Other
Total
$
1,327 $
1,005
547
93
2,972 $
46 $
4
(3 )
—
47 $
1,281 $
1,001
550
93
2,925 $
1,325 $
1,000
365
95
2,785 $
1,305
1,000
290
90
2,685
(1) Includes an increase of approximately $47 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) Approximately $35 million and $20 million of forecasted annual capital expenditures are associated with the Pleasants power station
for 2017 and 2018, respectively. On February 3, 2017, AE Supply offered the Pleasants power station into MP's RFP, as discussed
above.
(4) 2018 Forecast represents the mid-point of Regulated Transmission's 2018 forecasted capital expenditures of $800 million to $1,200
million.
34
Capital expenditures for 2016 and anticipated expenditures for 2017 by subsidiary are included in the following table (anticipated
capital expenditures by subsidiary for 2018 are not finalized):
Operating
Company
2016 Actual(1)
2016
Pension/OPEB
Mark-to-Market
Capital Costs
2016 Actual
Excluding
Pension/OPEB
Mark-to-Market
Capital Costs
2017 Forecast(2)
$
OE
Penn
CEI
TE
JCP&L
ME
PN
MP
PE
WP
ATSI
TrAIL
FES
AE Supply(3)
MAIT
Other
subsidiaries
Total
$
163 $
50
158
46
399
139
184
242
103
166
487
217
470
63
—
(In millions)
7 $
3
25
2
17
6
1
(6 )
(5 )
—
—
—
(3 )
—
—
156 $
47
133
44
382
133
183
248
108
166
487
217
473
63
—
145
45
125
45
350
135
160
250
125
205
420
60
320
45
260
85
2,972 $
—
47 $
85
2,925 $
95
2,785
(1) Includes an increase of approximately $47 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) Approximately $35 million of forecasted annual capital expenditures are associated with the Pleasants power station for 2017. On
February 3, 2017, AE Supply offered the Pleasants power station into MP's RFP, as discussed above.
FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is the Energizing the
Future transmission plan, which FirstEnergy plans to invest $4.2 to $5.8 billion in capital investments from 2017 to 2021, and began
as a $4.2 billion investment plan 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. Through 2016, FirstEnergy's capital expenditures under
this plan were $3.4 billion. In total, FirstEnergy has identified over $20 billion in transmission investment opportunities across the
24,000 mile transmission system, making this a continuing platform for investment in the years beyond 2021.
Additionally, planned capital expenditures in 2019 for Regulated Distribution are approximately $1.3 billion primarily to enhance
the Utilities' distribution systems.
In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as it
transitions to a fully regulated company, FirstEnergy is also focused on improving the balance sheet over time consistent with its
business profile and maintaining investment grade ratings at its regulated businesses and FE. Specifically, at the regulated
businesses, authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance
debt.
Any financing plans by FE or any of its subsidiaries, including the issuance of equity and debt, and the refinancing of short-term
and maturing long-term debt are subject to market conditions and other factors, such as the impact of the current energy and
capacity markets and potential credit rating changes. No assurance can be given that any such issuances, financing or refinancing,
as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or
any of its subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In particular, FES may borrow
35
under its credit facility with FE, to the extent available, to refinance debt maturities and mandatory purchase obligations, which
would impact available liquidity for FES and, FE to the extent it funds any such borrowings through its facility and/or cash. In
addition, FE and its subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to
time.
As of December 31, 2016, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part
to currently payable long-term debt and short-term borrowings. Currently payable long-term debt as of December 31, 2016,
included the following:
Currently Payable Long-Term Debt
FMBs
Unsecured notes
Unsecured PCRBs
Collateralized lease obligation bonds
Sinking fund requirements
Other notes
(In millions)
725
680
158
5
74
43
1,685
$
$
Short-Term Borrowings / Revolving Credit Facilities
On December 6, 2016, FE and certain subsidiaries entered into new five-year syndicated credit facilities available through
December 6, 2021, and concurrently terminated existing syndicated credit facilities that were to expire March 31, 2019, as follows:
• FE and the Utilities entered into a new $4 billion revolving credit facility, which represents an increase of $500 million over
the existing $3.5 billion facility it replaced,
• FET and its subsidiaries entered into a $1 billion revolving credit facility, which replaced their existing $1 billion facility,
and
• FES and AE Supply terminated their unsecured $1.5 billion credit facility (commitments of $900 million and $600 million
for FES and AE Supply, respectively) and FES entered into a new, two-year secured credit facility with FE in which FE
provided a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover
a $169 million surety bond for the benefit of the PA DEP with respect to LBR, and other bonds as designated in writing to
FE. In connection with the cancellation of the prior FES/AE Supply facility and entry into the new FES secured facility with
FE, certain commitments and amendments associated with shared services and operational matters were made including,
without limitation, as follows: (i) FE reaffirmed its obligations under the Intercompany Tax Allocation Agreement, and (ii)
amendments to the Service Agreement by and among FESC, FES, FG and NG, to prevent termination until the earlier of
December 31, 2018, or a change in control of FES or its subsidiaries.
FE, the Utilities and FET and its subsidiaries may use borrowings under their new facilities for working capital and other general
corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. FES expects to use its
new facility with FE to conduct its ordinary course of business in lieu of borrowing under the unregulated money pool. The new
facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million).
Under the terms of the new FE and FET credit facilities, each borrower is required to maintain a consolidated debt to total
capitalization ratio, as defined, of no more than 0.65 to 1.00, or in the case of FET, 0.75 to 1.00. For purposes of calculating its
ratio, FE is permitted certain adjustments to total capitalization including (i) an exclusion for certain previously incurred after-tax,
non-cash write-downs and non-cash charges of approximately $2.75 billion and (ii) a new exclusion for additional after-tax, non-
cash write-downs and 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. Additionally, under the new credit facility, FE is now also required to
maintain a minimum interest coverage ratio of 1.75 to 1.00 until December 31, 2017, 2.00 to 1.00 beginning January 1, 2018 until
December 31, 2018, 2.25 to 1.00 beginning January 1, 2019 until December 31, 2019, and 2.50 to 1.00 beginning January 1, 2020
until December 31, 2021. FE and each of the other borrowers under the new FE and FET credit facilities are currently in compliance
with these financial covenants. In the case of FE, the impairment charges recognized in the fourth quarter of 2016 described above
are excluded from FE's calculation of total capitalization pursuant to the new $5.5 billion after-tax exclusion referenced in (ii) above
consistent with the terms of the facility. Other terms of the new FE credit facility exclude FES and AE Supply from the definition of
“significant subsidiaries,” which removes them from FE’s covenants and defaults resulting from adverse judgments in excess of
$100 million and eliminates lender approvals previously required for FES and AE Supply asset sales.
36
Outstanding alternate base rate advances under the new FE and FET facilities will bear interest at a fluctuating interest rate per
annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to the applicable
borrower’s then-current senior unsecured non-credit enhanced debt ratings (reference ratings) plus the highest of (i) the “prime
rate” published by the Wall Street Journal from time to time, (ii) the sum of 1/2 of 1% per annum plus the federal funds rate in effect
from time to time and (iii) the LIBOR for a one-month interest period plus 1%. Outstanding Eurodollar rate advances will bear
interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by
reference to the applicable borrower’s reference ratings. Swing line loans under the new FE facility will bear interest at a rate per
annum equal to the sum of the alternate base rate plus an applicable margin determined by reference to the applicable borrower’s
reference ratings. Changes in reference ratings of a borrower would lower or raise its applicable margin depending on whether
ratings improved or were lowered, respectively.
FirstEnergy had $2,675 million and $1,708 million of short-term borrowings as of December 31, 2016 and 2015, respectively.
FirstEnergy’s available liquidity from external sources as of January 31, 2017 was as follows:
Borrower(s)
Type
Maturity
Commitment
Available
Liquidity
FirstEnergy(1)
FET(2)
Revolving December 2021 $
Revolving December 2021
Subtotal $
Cash
Total $
(In millions)
4,000 $
1,000
5,000 $
—
5,000 $
1,341
1,000
2,341
308
2,649
(1) FE and the Utilities.
(2)
Includes FET, ATSI and TrAIL.
FES had $101 million (payable to AE Supply) and $8 million of short-term borrowings as of December 31, 2016 and 2015,
respectively. FES' available liquidity as of January 31, 2017 was as follows:
Type
Commitment
Available
Liquidity
Two-year secured credit facility with FE
$
Cash
$
(In millions)
$
500
—
500 $
500
2
502
37
The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term
indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations,
as of December 31, 2016:
Borrower
FE
FET
OE
CEI
TE
JCP&L
ME
PN
WP
MP
PE
ATSI
Penn
TrAIL
MAIT
FirstEnergy
Revolving
Credit Facility
Sub-Limit
FET Revolving
Credit Facility
Sub-Limit
Regulatory and
Other Short-Term
Debt Limitations
(In millions)
$
$
4,000
—
500
500
500
600
300
300
200
500
150
—
50
—
—
$
—
1,000
—
—
—
—
—
—
—
—
—
500
—
400
400
— (1)
— (1)
500 (2)
500 (2)
500 (2)
500 (2)
500 (2)
300 (2)
200 (2)
500 (2)
150 (2)
500 (2)
100 (2)
400 (2)
400 (2)(3)
(1) No limitations.
(2)
(3) Pending regulatory approval, as discussed under "Outlook - FERC Matters" below.
Includes amounts which may be borrowed under the regulated companies' money pool.
The facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event
of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the
facilities is related to the credit ratings of the company borrowing the funds, other than the FET facility, which is based on its
subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions
for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of December 31, 2016, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants as well
as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective facilities. In
the case of FE, the impairment charges recognized in the fourth quarter of 2016 disclosed above are excluded from FE's calculation
of total capitalization pursuant to the new exclusion referenced in (ii) above consistent with the terms of the facility.
Term Loans
On December 6, 2016, FE terminated its existing $1 billion and $200 million term loan credit agreements and entered into a new
$1.2 billion five-year syndicated term loan credit agreement. The term loan contains covenants and other terms and conditions
substantially similar to those of the FE revolving credit facility described above, including a consolidated debt to total capitalization
ratio and minimum interest coverage ratio requirement.
The initial borrowing under the new $1.2 billion FE term loan, which took the form of a Eurodollar rate advance, may be converted
from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate
base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate
base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-
announced “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the
rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal
to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods
of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes
38
in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered,
respectively.
On February 16, 2017, FE entered into two separate $125 million three-year term loan credit agreements with Bank of America,
N.A. and The Bank of Nova Scotia, respectively, the proceeds of which were used to reduce short-term debt. The terms and
conditions of these new credit agreements are substantially similar to the December 6, 2016, $1.2 billion five-year syndicated term
loan credit agreement.
As of December 31, 2016, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants as
well as the interest coverage ratio requirement, as defined under its term loan.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding company to
meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated
companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and
unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool
agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds.
The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in 2016 was 0.69% per annum for the regulated
companies’ money pool and 2.02% per annum for the unregulated companies’ money pool.
As discussed above, FES expects to use its new $500 million secured credit facility with FE in lieu of borrowing under the
unregulated companies' money pool. In addition, a separate money pool for use by FES, its subsidiaries and FENOC is expected
to be established in the first quarter of 2017 at which time those companies will no longer have access to the unregulated
companies' money pool. As of January 31, 2017, FES, its subsidiaries and FENOC had no borrowings in the aggregate under the
unregulated companies' money pool.
Pollution Control Revenue Bonds
In 2016, as discussed below, FG remarketed $86 million of fixed rate PCRBs and retired $12 million of variable interest rate PCRBs,
which resulted in the elimination of LOCs related to $92 million of variable interest rate PCRBs that are no longer outstanding.
39
Long-Term Debt Capacity
FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities.
The following table displays FE’s and its subsidiaries’ credit ratings as of January 31, 2017:
Issuer
FE
FES
AE Supply
AGC
ATSI
CEI
FET
JCP&L
ME
MP
OE
PN
Penn
PE
TE
TrAIL
WP
Senior Secured
Senior Unsecured
S&P
Moody’s
Fitch
S&P
Moody’s
—
B
BB
—
—
—
B1
—
—
—
BBB+
Baa1
—
—
—
BBB+
BBB+
—
—
BBB+
BBB+
—
BBB+
—
—
—
A3
A2
—
A2
A3
Baa1
—
A2
—
—
BB
—
—
A-
—
—
—
BBB+
A-
—
A-
BBB+
A-
—
A-
BB+
CCC+
BB-
BB-
BBB-
BBB-
BB+
BBB-
BBB-
—
BBB-
BBB-
—
—
—
BBB-
—
Baa3
Caa1
B1
Baa3
Baa2
Baa3
Baa3
Baa2
Baa1
—
Baa1
Baa2
—
—
—
A3
—
Fitch
BBB-
C
BB-
BB
BBB+
BBB+
BBB-
BBB
BBB+
—
BBB+
BBB+
—
—
—
BBB+
—
In January 2017, Fitch initiated coverage of FE's subsidiaries and established ratings as indicated in the above table.
On February 3, 2017, Moody’s upgraded the senior secured rating of WP, to A1 from A2 and the senior unsecured ratings of ME
to A3 from Baa1 and PN to Baa1 from Baa2.
Debt capacity is subject to the consolidated debt to total capitalization limits in the credit facilities previously discussed. As of
December 31, 2016, FE and its subsidiaries could issue additional debt of approximately $4.6 billion, or incur a $2.5 billion reduction
to equity, and remain within the limitations of the financial covenants required by the credit facilities.
Changes in Cash Position
As of December 31, 2016, FirstEnergy had $199 million of cash and cash equivalents compared to $131 million of cash and cash
equivalents as of December 31, 2015. As of December 31, 2016 and 2015, FirstEnergy had approximately $61 million and $82
million, respectively, of restricted cash included in Other Current Assets on the Consolidated Balance Sheets.
Cash Flows From Operating Activities
FirstEnergy's most significant sources of cash are derived from electric service provided by its utility operating subsidiaries and
the sales of energy and related products and services by its unregulated competitive subsidiaries. The most significant use of cash
from operating activities is to buy electricity in the wholesale market and pay fuel suppliers, employees, tax authorities, lenders,
and others for a wide range of material and services.
Net cash provided from operating activities was $3,371 million during 2016, $3,447 million during 2015 and $2,713 million during
2014.
2016 compared with 2015
Cash flows from operations decreased $76 million in 2016 compared with 2015. The year over year change in cash from
operations decreased due to the following:
40
• A $239 million increase in cash contributions to the qualified pension plan, partially offset by;
• Higher distribution deliveries and the full year impact of net rate increases implemented in 2015 at certain Utilities;
• Higher transmission revenue, reflecting recovery of incremental operating expenses and a higher rate base;
• Lower disbursements for fuel and purchased power resulting from the lower sales volumes partially offset by lower
capacity revenues at CES.
2015 compared with 2014
Cash flows from operations increased $734 million in 2015 compared with 2014 due to the following:
• Distribution rate increases associated with the implementation of new rates, partially offset by a year-over-year decline
in distribution deliveries;
• Higher transmission revenue and earnings, reflecting recovery of incremental operating expenses, a higher rate base
and forward-looking rates at ATSI;
• Higher capacity revenues at CES, partially offset by a decline in sales volume;
• Lower disbursements for fuel and purchased power resulting from lower sales volumes; and
• Lower posted collateral; partially offset by,
• A $143 million contribution to the qualified pension plan in 2015.
Cash Flows From Financing Activities
In 2016, cash used for financing activities was $22 million compared to $279 million in 2015 and $513 million of net cash provided
from financing activities in 2014. The following table summarizes new debt financing (net of any discounts), redemptions and
common stock dividend payments:
Securities Issued or Redeemed / Repaid
2016
2015
2014
For the Years Ended December 31
New Issues
Unsecured notes
PCRBs
FMBs
Term loan
Senior secured notes
Redemptions / Repayments
Unsecured notes
PCRBs
FMBs
Term loan
Senior secured notes
Short-term borrowings, net
Common stock dividend payments
(In millions)
$
$
$
— $
471
305
1,200
—
1,976 $
(300 ) $
(483 )
(246 )
(1,200 )
(102 )
475 $
339
295
200
2
1,311 $
— $
(313 )
(215 )
(200 )
(151 )
2,400
878
200
1,050
—
4,528
(600 )
(793 )
(175 )
—
(191 )
$
(2,331 ) $
(879 ) $
(1,759 )
$
$
975 $
(91 ) $
(1,605 )
(611 ) $
(607 ) $
(604 )
On May 1, 2016, JCP&L repaid $300 million of 5.625% senior unsecured notes at maturity.
On June 1 and July 1 of 2016, NG repurchased approximately $225 million and $60 million, respectively of PCRBs, which were
subject to a mandatory put on such date. On August 15, 2016, NG remarketed the approximately $285 million of PCRBs secured
by FMBs with a fixed interest rate of 4.375% and mandatory put dates ranging from June 1, 2022 to July 1, 2022.
41
On July 11, 2016, Penn issued $50 million of 4.24% FMBs due 2056. Proceeds received from the issuance of the FMBs were
used: (i) to fund capital expenditures; (ii) for working capital needs and other general business purposes; and (iii) to repay
borrowings under the FirstEnergy regulated companies' money pool.
On August 15, 2016, WP repaid $145 million of 5.875% FMBs at maturity. Also, on September 23, 2016, WP agreed to sell $475
million of new 3.84% FMBs due 2046 ($100 million), 4.09% FMBs due 2047 ($100 million) and 4.14% FMBs due 2047 ($275
million). On December 15, 2016, WP issued the $100 million of 3.84% FMBs due 2046. The remaining sales are expected to settle
on September 15, 2017 and December 15, 2017, respectively. Proceeds to be received from the issuances of the FMBs were or
are, as the case may be, expected to be used: (i) for general corporate purposes; and (ii) to repay a portion of WP's $275 million
of 5.95% FMBs that mature on December 15, 2017.
On August 15, 2016, FG remarketed approximately $86 million of PCRBs secured by FMBs with fixed interest rates ranging from
4.25% to 4.50% and mandatory put dates ranging from May 1, 2021 to June 1, 2021.
On September 15, 2016, FG remarketed $100 million of PCRBs secured by FMBs with a fixed interest rate of 4.25% and a
mandatory put of September 15, 2021.
On September 15 and 30, 2016, respectively, FG retired an aggregate of $12 million of PCRBs with original maturity dates in 2018
and 2029.
On October 17, 2016, PE issued $155 million of 3.89% FMBs due 2046. Proceeds received from the issuance were used: (i) to
repay short-term borrowings incurred to repay PE's $100 million of 5.80% FMBs that matured on October 15, 2016; and (ii) for
general corporate purposes.
Cash Flows From Investing Activities
Cash used for investing activities in 2016 principally represented cash used for property additions. The following table summarizes
investing activities for 2016, 2015 and 2014:
Cash Used for Investing Activities
2016
2015
2014
For the Years Ended December 31
Property Additions:
Regulated distribution
Regulated transmission
Competitive energy services
Corporate / other
Nuclear fuel
Proceeds from asset sales
Investments
Asset removal costs
Other
2016 compared with 2015
(In millions)
1,063 $
1,101
619
52
232
(15 )
111
145
(27 )
3,281 $
1,040 $
1,020
588
56
190
(20 )
114
142
(8 )
3,122 $
$
$
855
1,446
939
72
233
(394 )
103
153
(48 )
3,359
Cash used for investing activity in 2016 increased $159 million, compared to the same period of 2015, primarily due to increases
in nuclear fuel purchases and property additions. Property additions increased primarily due to higher transmission investment and
CES' purchase of the remaining non-affiliated leasehold interest in Perry Unit 1. The increase in nuclear fuel was due to the
scheduled Davis-Besse refueling and maintenance outage in 2016.
42
2015 compared with 2014
Cash used for investing activity in 2015 as compared to 2014 were impacted by lower property additions of $608 million, partially
offset by a $374 million reduction in proceeds received from asset sales, as 2014 included proceeds from the sale of certain
hydroelectric assets. The decline in property additions were due to the following:
• a decrease of $351 million at CES, resulting from the absence of capital investments associated with the Davis-Besse
steam generators that were placed into service in May 2014,
• a decrease of $426 million at Regulated Transmission primarily relating to the timing of capital investments associated
with its Energizing the Future investment program, partially offset by
• an increase of $185 million at Regulated Distribution relating to utility specific project investments and costs associated
with the Pennsylvania smart meter program.
CONTRACTUAL OBLIGATIONS
As of December 31, 2016, our estimated cash payments under existing contractual obligations that we consider firm obligations
are as follows:
Contractual Obligations
Total
2017
2018-2019 2020-2021 Thereafter
Long-term debt(1)
Short-term borrowings
Interest on long-term debt(2)
Operating leases(3)
Capital leases(3)
Fuel and purchased power(4)
Capital expenditures (5)
Pension funding
Total
(In millions)
$
$
19,881 $
2,675
12,539
1,957
117
10,438
1,668
2,565
51,840 $
1,641 $
2,675
986
125
32
1,368
647
—
7,474 $
3,968 $
—
1,736
265
44
2,180
762
827
9,782 $
2,063 $
—
1,556
216
26
1,629
259
1,032
6,781 $
12,209
—
8,261
1,351
15
5,261
—
706
27,803
Interest on variable-rate debt based on rates as of December 31, 2016.
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and capital leases.
(2)
(3) See Note 7, Leases, of the Combined Notes to Consolidated Financial Statements.
(4) Amounts under contract with fixed or minimum quantities based on estimated annual requirements.
(5) Amounts represent committed capital expenditures as of December 31, 2016.
Excluded from the table above are estimates for the cash outlays from power purchase contracts entered into by most of the
Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not
choose an alternative supplier. Although actual amounts will be determined by future customer behavior and consumption levels,
management currently estimates these cash outlays will be approximately $2.9 billion in 2017, of which $0.4 billion are expected
to relate to the Utilities' contracts with FES.
The table above also excludes regulatory liabilities (see Note 15, Regulatory Matters), AROs (see Note 14, Asset Retirement
Obligations), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including
nuclear insurance (see Note 16, Commitments, Guarantees and Contingencies) since the amount and timing of the cash payments
are uncertain. The table also excludes accumulated deferred income taxes and investment tax credits since cash payments for
income taxes are determined based primarily on taxable income for each applicable fiscal year.
NUCLEAR INSURANCE
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.3 billion
(assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting
to $375 million; and (ii) $13 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 maximum potential assessment under
43
these provisions would be $509 million (NG-$506 million) per incident but not more than $76 million (NG-$75 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 annually, corresponding to their
respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.40 billion (NG-$1.39 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
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.
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of
business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing
the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy could be required to
make under these guarantees as of December 31, 2016, was approximately $3.3 billion, as summarized below:
44
Guarantees and Other Assurances
Maximum
Exposure
(In millions)
FE's Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts(1)
Deferred compensation arrangements(2)
Other(3)
$
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts(4)
FES' guarantee of nuclear decommissioning costs(5)(6)
FES’ guarantee of FG’s sale and leaseback obligations
FE's Guarantees on Behalf of Business Ventures
Global Holding Facility
Other Assurances
Surety Bonds - Wholly Owned Subsidiaries(7)
Surety Bonds
Sale leaseback indemnity
LOCs(8)
Total Guarantees and Other Assurances
$
12
559
10
581
265
21
1,647
1,933
300
373
22
58
12
465
3,279
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
(1)
(2) CES related portion is $139 million, including $53 million and $86 million at FES and FENOC, respectively.
(3)
Includes guarantees of $4 million for nuclear decommissioning funding assurances, $3 million for railcar leases, and $3 million for various
leases.
Includes energy and energy-related contracts associated with FES.
(4)
(5) NG funded a $10 million supplemental trust in December 2016 to replace this guarantee, which will terminate in April 2017.
(6) FES provides a parental support agreement to NG of up to $400 million that may be required in the event of extraordinary circumstances. FE
is working with FES to establish conditional credit support on terms and conditions to be agreed upon for the $400 million FES parental
support agreement that is currently in place for the benefit of NG in the event that FES is unable to provide the necessary support to NG.
(7) Effective January 2017, FE is an indemnitor for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.
(8)
Includes $9 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facilities and $3 million
pledged in connection with the sale and leaseback of the Beaver Valley Unit 2 by OE.
FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each
of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG, and NG would have claims against each of
FES, FG, and NG, regardless of whether their primary obligor is FES, FG, or NG.
Collateral and Contingent-Related Features
In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale
and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments
contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit
support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The
collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for
the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable
master netting agreements.
Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require
posting of collateral. Based on FES' power portfolio exposure as of December 31, 2016, FES has posted collateral of $190 million
and AE Supply has posted collateral of $4 million. The Regulated Distribution Segment has posted collateral of $3 million.
45
These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary
were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required
to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for
margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the
potential additional credit rating contingent contractual collateral obligations as of December 31, 2016:
Potential Additional Collateral Obligations
FES
AE Supply Regulated
Total
Contractual Obligations for Additional Collateral
At Current Credit Rating
Upon Further Downgrade
Surety Bonds (Collateralized Amount)(1)
Total Exposure from Contractual Obligations
(In millions)
$
$
7 $
—
240
247 $
3 $
—
25
28 $
— $
48
102
150 $
10
48
367
425
(1) Effective January 2017, FE is a guarantor for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.
Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated
Distribution segment and CES segment. As of December 31, 2016, neither FES nor AE Supply had any collateral posted with their
affiliates. Moreover, a further downgrade for either FES or AE Supply would not trigger any obligations to post any such collateral.
Other Commitments, Contingencies and Assurances
FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed
$300 million. In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC,
each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations
of Global Holding under the facility.
In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and
their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding,
are pledged to the lenders under the current facility as collateral.
OFF-BALANCE SHEET ARRANGEMENTS
FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to
the Perry Unit 1, Beaver Valley Unit 2, and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, which are satisfied
through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust
investments, was $879 million as of December 31, 2016 and primarily relates to the 2007 Bruce Mansfield Unit 1 sale and
leaseback arrangement expiring in 2040.
On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in
Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Upon the
completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2. Therefore, upon the
expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100% of the unit's
output. As of December 31, 2016, OE's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was
93.83% of Bruce Mansfield Unit 1.
On May 23, 2016, NG completed the purchase of the 3.75% lessor equity interests of the remaining non-affiliated leasehold interest
in Perry Unit 1 for $50 million. In addition, the Perry Unit 1 leases expired in accordance with their terms on May 30, 2016, resulting
in NG being the sole owner of Perry Unit 1 and entitled to 100% of the unit's output.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and
interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general
oversight for risk management activities throughout the company.
46
Commodity Price Risk
FirstEnergy is exposed to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas,
coal and energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and
implementation of sound risk management programs and oversees compliance with corporate risk management policies and
established risk management practice. FirstEnergy uses a variety of derivative instruments for risk management purposes
including forward contracts, options, futures contracts and swaps.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In
cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of
future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates
of fair value for financial reporting purposes and for internal management decision making (see "Note 10, Fair Value
Measurements", of the Combined Notes to Consolidated Financial Statements). Sources of information for the valuation of net
commodity derivative assets and liabilities as of December 31, 2016 are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
2017
2018
2019
2020
2021
Thereafter
Total
Prices actively quoted(1)
Other external sources(2)
Prices based on models
Total(3)
$
$
4 $
27
(1 )
30 $
(In millions)
— $
(8 )
—
(8 ) $
— $
(31 )
—
(31 ) $
— $
(11 )
—
(11 ) $
— $
—
—
— $
— $
—
—
— $
4
(23 )
(1 )
(20 )
(1) Represents exchange traded New York Mercantile Exchange futures and options.
(2) Primarily represents contracts based on broker and ICE quotes.
(3)
Includes $(107) million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts
are subject to regulatory accounting and do not impact earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative
contracts as of December 31, 2016, not subject to regulatory accounting, an increase in commodity prices of 10% would decrease
net income by approximately $29 million during the next twelve months.
Equity Price Risk
As of December 31, 2016, the FirstEnergy pension plan assets were allocated approximately as follows: 46% in equity securities,
31% in fixed income securities, 8% in absolute return strategies, 10% in real estate, 1% in private equity, and 4% in cash and
short-term securities. A decline in the value of plan assets could result in additional funding requirements. FirstEnergy’s funding
policy is based on actuarial computations using the projected unit credit method. In 2016, FirstEnergy satisfied its minimum
required funding obligations of $382 million and addressed funding obligations for future years 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 2017, FirstEnergy does not have a minimum required
funding obligation to its qualified pension plan due to the equity contribution. See "Note 4, Pension and Other Postemployment
Benefits", of the Combined Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension plans and
OPEB. In 2016, FirstEnergy's pension plan assets earned approximately 8.6%, as compared to an expected return on plan assets
of 7.5%.
As of December 31, 2016, FirstEnergy's OPEB plans were invested in fixed income and equity securities. In 2016 FirstEnergy's
OPEB plans have earned approximately 7.0% as compared to an annual expected return on plan assets of 7.5%.
NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of
December 31, 2016, approximately 61% of the funds were invested in fixed income securities, 37% of the funds were invested in
equity securities and 2% were invested in short-term investments, with limitations related to concentration and investment grade
ratings. The investments are carried at their market values of approximately $1,531 million, $925 million and $60 million for fixed
income securities, equity securities and short-term investments, respectively, as of December 31, 2016, excluding $(2) million of
net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in
a $93 million reduction in fair value as of December 31, 2016. Certain FirstEnergy subsidiaries recognize in earnings the unrealized
47
losses on AFS securities held in its NDT as OTTI. A decline in the value of FirstEnergy’s NDT funds or a significant escalation in
estimated decommissioning costs could result in additional funding requirements. During 2016, FirstEnergy contributed
approximately $2 million to the NDT.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates,
as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing
new debt securities. As discussed in "Note 7, Leases" of the Combined Notes to Consolidated Financial Statements, FirstEnergy’s
investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.
Comparison of Carrying Value to Fair Value
Year of Maturity
2017
2018
2019
2020
2021
There-
after
Total
Fair
Value
(In millions)
Assets:
Investments Other Than Cash
and Cash Equivalents:
Fixed Income
Average interest rate
Liabilities:
Long-term Debt:
Fixed rate
Average interest rate
Variable rate
Average interest rate
CREDIT RISK
$
$
2
8.9 %
$
—
— %
$
—
— %
$
—
— %
—
— %
$ 1,768
$ 1,770
$ 1,771
3.8 %
3.8 %
$ 1,517
$ 1,329
$ 1,035
$
$
6.2 %
2
— %
$
6.0 %
—
— %
$
6.9 %
—
— %
$
541
5.6 %
—
— %
$
58
4.9 %
$ 1,200
2.4 %
$ 14,203
$ 18,683
$ 18,627
$
5.3 %
—
— %
5.53 %
$ 1,202
$ 1,202
2.43 %
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy
evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy
may impose specific collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy
monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees
credit risk.
Wholesale Credit Risk
FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission
allowances, adjusted for amounts owed to, or due from, counterparties for settled transactions. The replacement cost of open
positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of offset.
FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations
through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty
credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. The
majority of FirstEnergy's energy contract counterparties maintain investment-grade credit ratings.
Retail Credit Risk
FirstEnergy's principal retail credit risk exposure relates to its competitive electricity activities, which serve residential, commercial
and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service
rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances,
as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit
mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.
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Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and
other market changes. If the business environment were to be negatively affected by changes in economic or other market
conditions, FirstEnergy's retail credit risk may be adversely impacted.
OUTLOOK
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, Illinois, Michigan, New Jersey and
Maryland, 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.
MARYLAND
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. PE's current plan, covering the three-year period 2015-
2017, was approved by the MDPSC on December 23, 2014. 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 set in PE's plan for 2016, and increasing
0.2% per year thereafter to reach 2%. The costs of the 2015-2017 plan are expected to be approximately $70 million, of which
$43 million was incurred through December 31, 2016. PE continues to recover 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 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 yet 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. Initial comments in the proceeding were
filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 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.
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NEW JERSEY
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.
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 include
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 (Generic CTA proceeding), 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 New Jersey Superior Court and JCP&L filed to
participate as a respondent in that proceeding. Briefing has been completed. The oral argument was held on October 25, 2016.
On April 28, 2016, JCP&L filed tariffs with the NJBPU proposing a general rate increase associated with its distribution operations
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. The filing requested approval to increase
annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30,
2016. On November 30, 2016, JCP&L submitted to the ALJ a Stipulation of Settlement achieved with all the intervening parties
providing for an annual $80 million distribution revenue increase, effective January 1, 2017. The ALJ filed an Initial Decision
concluding that the Stipulation of Settlement should be approved, and the NJBPU approved the Stipulation of Settlement on
December 12, 2016. As part of the Stipulation of Settlement the intervening parties agreed that JCP&L can accelerate the
amortization of the 2012 major storm expenses (approximately $19 million annually) that are recovered through the SRC to achieve
full recovery by December 31, 2019. On November 23, 2016, JCP&L filed an Amendment to its January 15, 2016 SRC Filing with
the NJBPU, requesting that JCP&L be able to accelerate the amortization of the 2012 major storm expenses as agreed to in the
Stipulation of Settlement, and a Stipulation of Settlement with NJBPU Staff and the Division of Rate Counsel regarding the SRC
Filing was filed on December 27, 2016. The NJBPU approved this Stipulation of Settlement at the January 25, 2017 public meeting.
OHIO
The Ohio Companies currently operate under an ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material
terms of ESP IV, as approved in the PUCO’s Opinions and Orders issued on March 31, 2016 and 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. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually.
Revenues from the 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 approximately $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 the collection of lost distribution revenues associated with energy efficiency and peak demand
reduction programs, an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing
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was made on February 29, 2016), a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045, and
contributions, totaling $51 million, to fund energy conservation programs, economic development and job retention in the Ohio
Companies’ service territory, and a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers,
and to establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.
On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications for rehearing on the Ohio
Companies’ ESP IV with the PUCO. On September 6, 2016, while the applications for rehearing were still pending before the
PUCO, the OCC and NOAC filed a notice of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner
Entries on the parties’ applications for rehearing. On September 16, 2016, the Ohio Companies intervened and filed a motion to
dismiss the appeal. The PUCO resolved such applications for rehearing in the October 12, 2016 Opinion and Order. The OCC and
NOAC appeal remains pending before the Ohio Supreme Court.
On November 10, 2016 and November 14, 2016, several parties, including the Ohio Companies, filed additional applications for
rehearing on 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 December 7, 2016, the PUCO granted the applications for rehearing for further consideration of the matters
specified in the applications for rehearing. The matter remains pending before the PUCO. For additional information, see “FERC
Matters - Ohio ESP IV PPA,” below.
Under ORC 4928.66, the Ohio Companies were required to implement energy efficiency programs that achieved a total annual
energy savings of 1,990 GWHs and total peak demand reduction of 486 MWs in 2015. On May 12, 2016, the Ohio Companies
filed their Energy Efficiency and Peak Demand Reduction Program Status Report indicating compliance with their 2015 statutory
benchmarks. In 2016, the Ohio Companies estimated the annual energy savings target and peak demand reduction target will be
comparable to the 2015 targets due to the energy efficiency requirements under SB310, which amended ORC 4928.66 to freeze
the energy efficiency and peak demand reduction benchmarks for 2015 and 2016. 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.
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. The hearings were held in January 2017.
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 2015 and 2016 that remain at the 2014
level. 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. On February 18, 2014, the OCC
and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of
Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument.
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
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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. The matter remains pending before the PUCO.
PENNSYLVANIA
The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive
procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that
fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-
term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-
month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn.
Following the expiration of the current DSPs, the Pennsylvania Companies will operate under new 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 new
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. In addition, the new DSPs include modifications to the Pennsylvania Companies’
existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated
with alternative EGS charges.
Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency
and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans were effective through May 31, 2016.
Total Phase II costs of these plans were $174 million and are recoverable through the Pennsylvania Companies' reconcilable
EE&C riders. 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 October 19, 2015, each of the Pennsylvania
Companies filed LTIIPs with the PPUC for infrastructure improvement over the five-year period of 2016 to 2020 for the following
costs: WP- $88.34 million; PN- $56.74 million; Penn- $56.35 million; and ME- $43.44 million. On February 11, 2016, the PPUC
approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC
approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. On June 9, 2016, the PPUC
approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation
among customers. The four proceedings were consolidated by the ALJ. On January 19, 2017, in the PPUC’s order approving the
Pennsylvania Companies’ general rate cases, discussed below, the PPUC referred the issue of whether ADIT should be included
in DSIC calculations to the consolidated DSIC proceeding. On February 2, 2017, the parties to the consolidated DSIC proceeding
submitted a Joint Settlement to the ALJ to resolve issues referred to by the ALJ in its June 9, 2016 Order, subject to PPUC approval,
and would not result in any refund or reallocation among customers. The ADIT issue will be considered separately from the issues
resolved in the Joint Settlement Petition of February 2, 2017, and is the sole issue to be litigated in the consolidated DSIC
proceeding through a procedural schedule to be determined by the ALJ.
On April 28, 2016, each of the Pennsylvania Companies filed tariffs with the PPUC proposing general rate increases associated
with their distribution operations to benefit customers by modernizing the grid with smart technologies, increasing vegetation
management activities, and continuing other customer service enhancements. The filings requested approval to increase annual
operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP,
based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania
Companies. As a result of the enactment of Act 40 of 2016 that terminated the practice of making a CTA when calculating a utility’s
federal income taxes for ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7, 2016,
that quantified the value of the elimination of the CTA and outlined their plan for investing 50 percent of that amount in rate base
eligible equipment as required by the new law. Formal settlement agreements for each of the Pennsylvania Companies were filed
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on October 14, 2016, which proposed increases in annual operating revenues of approximately $96 million at ME, $100 million at
PN, $29 million at Penn, and $66 million at WP. One item related to the calculation of DSIC rates was reserved for briefing, with
briefs filed by two parties. On November 21, 2016, the ALJ issued a Recommended Decision recommending approval of the
settlement agreements and dismissal of the one issue reserved for briefing. Exceptions to that Recommended Decision were filed
by one party on December 1, 2016, and reply exceptions were filed by the Pennsylvania Companies on December 8, 2016. On
January 19, 2017, the PPUC issued an order approving the settlements and referring the reserved issue to the Pennsylvania
Companies’ consolidated DSIC proceeding. On February 3, 2017, one party filed a Petition for Reconsideration or Clarification
relating to the limited issue of the scope of the record to be transferred to the DSIC proceeding, discussed above. The outcome of
this request will not affect the new rates which took effect on January 27, 2017.
WEST VIRGINIA
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 March 31, 2016, MP and PE filed with the WVPSC seeking approval of their Phase II energy efficiency program including three
MP and PE energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of 0.5% of 2013
distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC
in the 2012 proceeding approving the transfer of ownership of the 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. A unanimous settlement was reached by the parties on all issues and presented to the WVPSC on
August 18, 2016. An order approving the settlement in full without modification was issued by the WVPSC on September 23,
2016. The Phase II program began initial implementation in November 2016.
The Staff of the WVPSC and the Consumer Advocate Division filed a Show Cause petition on August 5, 2016, requesting that the
WVPSC order MP and PE to file and implement RFPs for all future capacity and energy requirements above 100 MWs and that
they comply with an RFP settlement provision from the Harrison power station acquisition. MP and PE filed a timely response to
the petition arguing for dismissal on September 7, 2016. On October 17, 2016, the WVPSC denied the petition filed by the Staff
of the WVPSC and the Consumer Advocate Division and dismissed the case.
On August 16, 2016, MP and PE filed their annual ENEC case proposing an annual increase in rates of approximately $65 million
effective January 1, 2017, which is a 4.7% increase over existing rates. The increase is comprised of a $119 million under-
recovered balance as of June 30, 2016, and a projected $54 million over-recovery for the 2017 rate effective period. The parties
reached a unanimous settlement providing for a $25 million increase beginning January 1, 2017 and keeping ENEC rates at the
same level for a two year period. The settlement was presented to the WVPSC at a hearing on November 9, 2016. On December
9, 2016, the WVPSC approved the settlement as submitted.
On August 22, 2016, MP and PE filed an application for approval of a modernization and improvement plan for coal-fired boilers
at electric power plants and cost-recovery surcharge proposing an approximate $6.9 million annual increase in rates to be effective
May 1, 2017, which is a 0.5% increase over existing rates. The filing is in response to recent legislation by the West Virginia
Legislature permitting accelerated recovery of costs related to modernizing and improving coal-fired boilers, including costs related
to meeting environmental requirements and reducing emissions. The filing was supplemented on September 28, 2016, to add two
additional projects, resulting in an approximate $7.4 million annual increase in rates. The Staff of the WVPSC filed a motion to
dismiss the case arguing the new statute was not meant to recover these types of projects, but the WVPSC set the case for
hearing for February 21-23, 2017. As part of the annual ENEC settlement described above, the parties agreed that MP and PE
will increase ENEC rates to provide for a return of and on MATS/CSPR capital costs incurred during 2016-2017. Accordingly, MP
and PE withdrew this case as part of the ENEC approval.
On December 30, 2015, MP 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 finding that IRPs are informational and that it
must not approve or disapprove the IRP. MP issued a RFP to address its generation shortfall identified in the IRP on December
16, 2016 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. MP expects to execute definitive agreements with selected respondent(s) and file the appropriate
applications with the WVPSC and FERC by March 15, 2017.
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RELIABILITY MATTERS
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 its subsidiaries, AE Supply, FENOC, ATSI 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.
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.
On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review
the ESP IV PPA under Section 205 of the FPA. On April 27, 2016, FERC issued an order granting the complaint, prohibiting any
transactions under the ESP IV PPA pending authorization by FERC, and directing FES to submit the ESP IV PPA for FERC review
if the parties desired to transact under the agreement. FES and the Ohio Companies did not file the ESP IV PPA for FERC review
but rather agreed to suspend the ESP IV PPA. FES and the Ohio Companies subsequently advised FERC of this course of action.
On January 19, 2017, FERC issued an order accepting compliance filings by FES, its subsidiaries, and the Ohio Companies
updating their respective market-based rate tariffs to clarify that affiliate sales restrictions under the tariffs apply to the ESP IV PPA,
and also that the ESP IV PPA does not affect certain other waivers of its affiliate restrictions rules FERC previously granted these
entities.
On May 2, 2016, the Ohio Companies filed an Application for Rehearing with the PUCO that included a modified Rider RRS
proposal that did not involve a FERC-jurisdictional PPA. Several parties subsequently filed protests and comments with FERC
alleging, among other things, that the modified Rider RRS constituted a "virtual PPA". FERC rejected these protests in its January
19, 2017 order accepting the updated market-based rate tariffs of FES, its subsidiaries, and the Ohio Companies discussed below.
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. This proceeding remains pending before FERC.
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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. The PJM TOs responded to the protesting parties' various pleadings and motions. 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
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, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be
disputed. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC
and certain United States 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. On July 15, 2016, the MISO TOs filed an appeal of FERC's orders with the Sixth
Circuit. On November 16, 2016, the Sixth Circuit granted FirstEnergy's intervention on behalf of ATSI, the Ohio Companies, and
PP, and a procedural schedule has been established. 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 costs for the "Michigan Thumb" transmission
project and "legacy RTEP" transmission projects cannot be predicted at this time.
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Transfer of Transmission Assets to MAIT
On June 10, 2015, MAIT, a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the
purposes of owning and operating all FERC-jurisdictional transmission assets of JCP&L, ME and PN following the receipt of all
necessary state and federal regulatory approvals. In February and August 2016, respectively, FERC and the PPUC granted the
authorization for PN and ME to contribute their transmission assets to MAIT at book value, together with the approval of related
intercompany agreements, including MAIT’s participation in FirstEnergy’s regulated companies' money pool. FirstEnergy
subsequently withdrew its request for authorization before the NJBPU to also transfer JCP&L's transmission assets to MAIT.
On October 28, 2016, MAIT and PJM submitted joint applications to FERC requesting authorization for (i) PJM to update its Tariff
and other agreements to reflect the withdrawal of ME and PN as TOs, and (ii) MAIT to become a participating PJM TO. FERC
approval would authorize MAIT to be a PJM TO, and would permit PJM to implement MAIT’s formula rate on MAIT’s behalf. On
January 26, 2017, FERC issued an order granting the requested authorization and MAIT now owns and operates the transmission
assets of ME and PN. On January 31, 2017, MAIT issued membership interests to FET, PN and ME in exchange for their respective
cash and asset contributions.
On October 14 and 28, 2016, MAIT submitted applications to FERC requesting authorization to issue equity, short-term debt, and
long-term debt. On December 8, 2016, FERC issued an order authorizing the application to issue equity as requested. MAIT is
expected to issue short-term debt and participate in the FirstEnergy regulated companies' money pool for working capital, to fund
day-to-day operations, and for other general corporate purposes. Over the long-term, MAIT is expected to issue long-term debt to
support capital investment and to establish an actual capital structure for ratemaking purposes. On February 3, 2017, MAIT
amended its debt authorization application to provide additional information regarding recovery of its investment and debt costs.
MAIT requested an order from FERC on the debt authorization by February 28, 2017. FERC’s order remains pending.
MAIT Transmission Formula Rate
On October 28, 2016, 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 January 1, 2017. On November 30, 2016, 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. MAIT filed a response to the protests on December 12, 2016. On
December 28, 2016, FERC Staff issued a deficiency letter with respect to the PJM-related application, which also requested
additional information regarding MAIT’s proposed formula rate. As a result of the deficiency letter, FERC’s order on the formula
rate remains pending. MAIT responded to FERC Staff’s request on January 10, 2017, and requested that FERC issue an order
approving the formula rate immediately after consummation of the transaction, which occurred on January 31, 2017. On February
15, 2017, MAIT filed a further answer to certain protesting parties' comments on its January 10th deficiency letter response.
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. On November 18, 2016, 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 December 5, 2016, JCP&L filed a
response to the protest. On December 28, 2016, FERC Staff issued a deficiency letter requesting additional information regarding
JCP&L’s proposed transmission rate. As a result of the deficiency letter, FERC’s order on the rate remains pending. JCP&L
responded to FERC Staff’s request on January 10, 2017, and requested that FERC issue an order approving the formula rate
effective January 1, 2017. On February 15, 2017, JCP&L filed a further answer to certain protesting parties' comments on its
January 10th deficiency letter response.
Competitive Generation Asset Sale
On February 17, 2017, AE Supply and AGC submitted filings with FERC for authorization to sell four natural gas generating plants
and an undivided ownership interest in Bath County to Aspen for approximately $925 million, in an all cash transaction. The four
natural gas plants are: Springdale Generating Facility (638 MWs), Chambersburg Generating Facility (88 MWs), Gans Generating
Facility (88 MWs), and Hunlock Creek (45 MWs). The 713 MW ownership interest in Bath County represents AE Supply’s indirect
ownership interest in the power station. The FERC applications include a request for authorization to transfer the hydroelectric
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license under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the
hydroelectric projects under Part II of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected
FERC-jurisdictional rates and implementing the transaction once regulatory approval is obtained. The VSCC also must approve
the sale of the Bath County Hydro interest. The parties expect to close the transaction in the third quarter of 2017, subject to
satisfaction of various customary and other closing conditions, including without limitation, receipt of regulatory approvals and third
party consents. See "Executive Summary" above for additional information regarding the transaction.
California Claims Litigation
Since 2002, AE Supply has been involved in litigation and claims based on its power sales to the California Energy Resource
Scheduling division of the CDWR during 2001-2003. This litigation and claims are related to litigation and claims advanced by the
California Attorney General and certain California utilities regarding alleged market manipulation of the wholesale energy markets
in California during the 2000-2001 period. AE Supply negotiated a settlement with the California Attorney General and the California
utilities and, on August 24, 2016, filed the settlement agreement for FERC approval. The settlement calls for AE Supply to pay,
without admission of any liability, $3.6 million in settlement in principle of all remaining claims that are based on AE Supply’s power
sales in the western energy markets during the 2001-2003 time period. On October 27, 2016 FERC approved this settlement, and
AE Supply paid the settlement shortly thereafter.
PATH Transmission Project
On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia
through Virginia and into Maryland which PJM had previously suspended in February 2011. 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 settlement
proceedings and a hearing if the parties could not agree to a settlement. On March 24, 2014, the FERC Chief ALJ terminated
settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional
pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531,
discussed below, to the PATH proceeding. On September 14, 2015, the ALJ issued his initial decision, disallowing recovery of
certain costs. On January 19, 2017, FERC issued an order accepting the initial decision in part and denying it in part. Relying on
its revised ROE methodology described in FERC Opinion No. 531, FERC reduced the PATH formula rate ROE from 10.4% to
8.11% effective January 19, 2017. Additionally, FERC allowed recovery of costs related to land acquisitions and dispositions and
legal expenses, but disallowed certain costs related to advertising and outreach. PATH filed a request for rehearing with FERC on
February 20, 2017, seeking recovery of the advertising and outreach costs and requesting that the ROE be reset to 10.4%.
Market-Based Rate Authority, Triennial Update
The Utilities, AE Supply, FES and its subsidiaries, Buchanan Generation, LLC, and Green Valley Hydro, LLC 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 the 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. The filings remain pending before FERC.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental
matters. 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.
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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 U.S. Court of Appeals for 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 EPA’s regulatory approach under CSAPR, but questioning whether EPA
required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. 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. Depending on the outcome of the appeals and on how
the EPA and the states 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. States will then have roughly three years to develop implementation plans to attain 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. 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. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.
MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective
in April 2015 with averaging of emissions from multiple units located at a single plant. FirstEnergy's total capital cost for compliance
(over the 2012 to 2018 time period) is currently expected to be approximately $345 million (CES segment of $168 million and
Regulated Distribution segment of $177 million), of which $286 million has been spent through December 31, 2016 ($125 million
at CES and $161 million at Regulated Distribution).
On August 3, 2015, FG, a 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 arises 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. In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that
excused FG’s further performance. 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 liability hearing from
November 28, 2016, through December 9, 2016, and, if necessary, a damages hearing is scheduled to begin on May 8, 2017. The
decision on liability is expected to be issued within sixty days from the end of the liability hearing proceedings, which are scheduled
to conclude February 24, 2017. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the
contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused. FG intends to
vigorously assert its position in the arbitration proceedings. If, however, the arbitration panel rules in favor of BNSF and CSX, the
results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. Refer to the
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"Executive Summary" above for possible actions that may be taken by FES in the event of an adverse outcome, including, without
limitation, seeking protection under U.S. bankruptcy laws. FirstEnergy and FES are unable to estimate the loss or range of loss.
On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from
BNSF and NS who 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 Plant. 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, among other things, damages, including lost profits through 2025, and a declaratory judgment that
FG's claim of force majeure is invalid. FG intends to vigorously assert its position in this arbitration proceeding. 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. Refer to the "Executive Summary" above
for possible actions that may be taken by FES in the event of an adverse outcome, including, without limitation, seeking protection
under U.S. bankruptcy laws. FirstEnergy and FES are unable to estimate the loss or range of loss.
As to both coal transportation agreements referenced in the above arbitration proceedings, FG paid approximately $70 million in
the aggregate in liquidated damages to settle delivery shortfalls in 2014 related to its deactivated plants, which approximated full
liquidated damages under the agreements for such year related to the plant deactivations. Liquidated damages for the period
2015-2025 remain in dispute under both coal transportation agreements.
As to a specific coal supply agreement, AE Supply asserted termination rights effective in 2015 as a result of MATS. In response
to notification of the termination, the coal supplier commenced litigation alleging AE Supply does not have sufficient justification to
terminate the agreement. AE Supply has filed an answer denying any liability related to the termination. This matter is currently in
the discovery phase of litigation and no trial date has been established. There are approximately 5.5 million tons remaining under
the contract for delivery. At this time, AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with
respect to this agreement.
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, 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, 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 United States 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 regulations in August 2015
(which have been stayed by the U.S. Supreme Court), to reduce CO2 emissions from existing fossil fuel fired electric generating
units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO2 emission rate
goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop
SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions
trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO2 emission limits
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for new, modified, and reconstructed fossil fuel fired electric generating units. Numerous states and private parties filed appeals
and motions to stay the CPP with the U.S. Court of Appeals for 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. Depending
on the outcome 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 greenhouse
gas emissions by 26 to 28 percent below 2005 levels by 2025 and 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 are effective on November 4, 2016. It
remains unclear whether and how the results of the 2016 United States election could impact the regulation of GHG emissions at
the federal and state level. 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. FirstEnergy is studying various control options and their costs and effectiveness,
including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from
the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based
on those studies, 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 will 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. 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.
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.
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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 coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal
requirements pending the EPA's evaluation of the need for future regulation.
In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards
regarding 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of
spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected,
any 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. On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices
of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit
for the Hatfield’s Ferry CCR disposal facility.
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, 2016 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 $137 million have been accrued through December 31, 2016. Included in the total are accrued liabilities of
approximately $89 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 loss cannot be determined or reasonably estimated
at this time.
OTHER LEGAL PROCEEDINGS
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As
of December 31, 2016, FirstEnergy had approximately $2.5 billion invested in external trusts to be used for the decommissioning
and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based
on market conditions. If the value 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. FE and FES have also entered into a total of $24.5 million in parental guarantees in support of the decommissioning
of the spent fuel storage facilities located at the nuclear facilities. As FES no longer maintains investment grade credit ratings from
either S&P or Moody’s, NG funded a $10 million supplemental trust in 2016 in lieu of the FES parental guarantee that would be
required to support the decommissioning of the spent fuel storage facilities. The termination of the FES parental guarantee is
subject to NRC review. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental
guarantees, as appropriate.
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
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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. FENOC plans to submit a license amendment application to the NRC related to the laminar cracking in the Shield
Building.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the
lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require
additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in
spent fuel pools. The NRC also requested that licensees including FENOC re-analyze earthquake and flooding risks using the
latest information available, conduct earthquake and flooding hazard walkdowns at their nuclear plants, assess the ability of current
communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power and assess plant
staffing levels needed to fill emergency positions. Although a majority of the necessary modifications and upgrades at FirstEnergy’s
nuclear facilities have been implemented, the improvements still remain subject to regulatory approval.
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. In addition to the $500
million credit facility with FE discussed above, FE is working with FES to establish conditional credit support on terms and
conditions to be agreed upon for the $400 million FES parental support agreement that is currently in place for the benefit of NG
in the event that FES is unable to provide the necessary support to NG.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal
business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected
to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described
under Note 15, Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can
reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably
possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can
be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to
liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a
high degree of judgment, estimates and assumptions that affect financial results. FirstEnergy's accounting policies require
significant judgment regarding estimates and assumptions underlying the amounts included in the financial statements. Additional
information regarding the application of accounting policies is included in the Combined Notes to Consolidated Financial
Statements.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to
customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers
is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered
to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The
determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail
load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts,
number of days unbilled and tariff rates in effect within each customer class. See Note 1, Organization and Basis of Presentation
for additional details.
62
Regulatory Accounting
FirstEnergy’s regulated distribution and regulated transmission segments are subject to regulations that set the prices (rates) the
Utilities, ATSI, TrAIL and PATH are permitted to charge customers based on costs that the regulatory agencies determine are
permitted to be recovered. At times, regulators permit the future recovery through rates of costs that would be currently charged
to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets and liabilities based
on anticipated future cash inflows and outflows. FirstEnergy regularly reviews these assets to assess their ultimate recoverability
within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative,
judicial or regulatory actions in the future. See Note 15, Regulatory Matters for additional information.
FirstEnergy reviews the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur.
Similarly, FirstEnergy records regulatory liabilities when a determination is made that a refund is probable or when ordered by a
commission. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory
commission order or passage of new legislation. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off
that regulatory asset as a charge against earnings.
Pension and OPEB Accounting
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-
qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and
compensation levels.
FirstEnergy provides some non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health
care benefits and/or subsidies to purchase health insurance, which include certain employee contributions, deductibles and co-
payments, may also be available upon retirement to certain employees, their dependents and, under certain circumstances, their
survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-
related benefits.
In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed funding obligations for future
years 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. The independent
fiduciary representing the pension plan with respect to the equity contribution fully liquidated the FE common stock by January 31,
2017.
FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net
actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a
remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations,
assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market
adjustment for the years ended December 31, 2016, 2015, and 2014 were $194 million ($147 million net of amounts capitalized),
$369 million ($242 million net of amounts capitalized), and $1,243 million ($835 million net of amounts capitalized), respectively.
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income
investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed discount
rates for pension were 4.25%, 4.50% and 4.25% as of December 31, 2016, 2015 and 2014, respectively. The assumed discount
rates for OPEB were 4.00%, 4.25% and 4.00% as of December 31, 2016, 2015 and 2014, respectively.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the
types of investments held by the pension trusts. In 2016, FirstEnergy’s qualified pension and OPEB plan assets experienced
earnings of $472 million or 8.2% compared to losses of $(172) million, or (2.7)% in 2015 and earnings of $387 million, or 6.2% in
2014 and assumed a 7.50% rate of return on plan assets in 2016 and a 7.75% expected rate of return in 2015 and 2014 which
generated $429 million, $476 million and $496 million of expected returns on plan assets, respectively. The expected return on
pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed
income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets
will increase or decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter
of each fiscal year or whenever a plan is determined to qualify for remeasurement. The expected return on plan assets for 2017
is 7.5%.
63
During 2016, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2016, incorporating
three additional years of SSA data on U.S. population mortality. MP-2016 incorporates SSA mortality data from 2012 to 2014 and
a slight modification of two input values designed to improve the model’s year-over-year stability. The updated improvement scale
indicates a slight decline in life expectancy as a result of the slower average rate of mortality improvement. Due to the additional
years of data on population mortality, the RP2014 mortality table with the projection scale MP-2016 was utilized to determine the
2016 benefit cost and obligation as of December 31, 2016 for the FirstEnergy pension and OPEB plans.The impact of using the
projection scale MP-2016 resulted in a decrease in the projected benefit obligation of $141 million and $8 million for the pension
and OPEB plans, respectively, and was included in the 2016 pension and OPEB mark-to-market adjustment.
Based on discount rates of 4.25% for pension, 4.00% for OPEB and an estimated return on assets of 7.5%, FirstEnergy expects
its 2017 pre-tax net periodic benefit cost (including amounts capitalized) to be approximately $78 million (excluding any actuarial
mark-to-market adjustments that would be recognized in 2017). The following table reflects the portion of pension and OPEB costs
that were charged to expense, including any pension and OPEB mark-to-market adjustments, in the three years ended
December 31, 2016.
Postemployment Benefits Expense (Credits)
2016
2015
2014
Pension
OPEB
Total
$
$
(In millions)
277 $
(40 )
237 $
316 $
(61 )
255 $
939
(101 )
838
Health care cost trends continue to increase and will affect future OPEB costs. The 2016 composite health care trend rate
assumptions were approximately 6.0-5.5%, compared to 6.0-5.5% in 2015, gradually decreasing to 4.5% in later years. In
determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the
demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and
projections of future medical trend rates. The effects on 2017 pension and OPEB net periodic benefit costs from changes in key
assumptions are as follows:
Increase in Net Periodic Benefit Costs from Adverse Changes in Key Assumptions
Assumption
Adverse Change
Pension
OPEB
Total
Discount rate
Long-term return on assets
Health care trend rate
Decrease by .25%
Decrease by .25%
Increase by 1.0%
(In millions)
288
15
N/A
19 $
1 $
22 $
307
16
22
See Note 4, Pension and Other Postemployment Benefits for additional information
Long-Lived Assets
FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances
indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows
attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted
future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated
fair value. See Note 1, Organization and Basis of Presentation.
See Note 2, Asset Impairments for impairments recognized during 2016 and 2015.
64
Asset Retirement Obligations
FE recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental
liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FE's current
obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair
value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FE uses an expected
cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach
applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios
consider settlement of the ARO at the expiration of the nuclear power plant's current license, settlement based on an extended
license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the
life of the related asset.
Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which
they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of
settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the
timing of the liability recognition.
AROs as of December 31, 2016, are described further in "Note 14, Asset Retirement Obligations".
Income Taxes
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax
effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the
amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences
and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be
paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. We account for uncertain income tax
positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a
measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being
ultimately realized upon settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no
benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered
to have met the recognition threshold. FirstEnergy recognizes interest expense or income related to uncertain tax positions. That
amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and
the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the
provision for income taxes. See Note 6, Taxes for additional information.
Goodwill
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities
assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if
indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether
it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value
(including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its
carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value
of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the two-step quantitative goodwill
impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized,
if any.
As of July 31, 2016, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission
reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial
performance. It was determined that the fair value of these reporting units were, more likely than not, greater than their carrying
value and a quantitative analysis was not necessary.
See Note 2, Asset Impairments for further discussion of CES goodwill impairment charge recognized during 2016.
65
NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards
updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is
that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also
be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash
flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective
for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim
reporting periods beginning after December 15, 2016. FirstEnergy will not early adopt the standards. The standards shall be
applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy has
evaluated a significant portion of its revenues and preliminarily expects limited impacts to current revenue recognition practices,
dependent on the resolution of industry issues including accounting for contributions in aid of construction and the ability to
recognize revenue for contracts where collectibility is in question. FirstEnergy continues to assess the remainder of its revenue
streams and the impact on its financial statements and disclosures as well as which transition method it will select to adopt the
guidance.
On August 27, 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity's Ability to Continue as a Going
Concern." In connection with preparing financial statements for each annual and interim reporting period, the ASU requires an
entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt
about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued.
Disclosures are required when management identifies conditions or events that raise substantial doubt. The new requirements
were effective for the annual period ended December 31, 2016.
In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial
Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair
value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance
related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-
for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods
within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim
periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating
the impact on its financial statements of adopting this standard.
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with
lease terms of more than twelve months to recognize assets and liabilities for the rights and obligations created by those leases
on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash
flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years,
beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified
retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest
comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date
will not require any accounting adjustment. FirstEnergy is currently evaluating the impact on its financial statements of adopting
this standard.
In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which
simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax
effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability
accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective
for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted.
Upon adoption, January 1, 2017, FirstEnergy elected to account for forfeitures as they occur. The adoption of the ASU did not
have a material impact on FirstEnergy’s financial statements.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses
on Financial Instruments”, which removes all recognition thresholds and will require companies to recognize an allowance for
credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that
the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods
66
within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December
15, 2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.
In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts
and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments
are presented and classified in the statement of cash flows, including the presentation of debt prepayment or debt extinguishment
costs, all of which will be classified as financing activities. The guidance is effective for fiscal years, and for interim periods within
those fiscal years, beginning after December 15, 2017. Early adoption is permitted for all entities. FirstEnergy expects to adopt
this ASU in 2017 and does not expect this ASU to have a material effect on its financial statements.
In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than
Inventory". ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies
to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale
of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction
are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time
of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December
15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance,
with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy is
currently evaluating the impact on its financial statements of adopting this standard.
In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" that will require entities to show the changes in the total of
cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no
longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement
of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line
item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related
captions in the balance sheet. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning
after December 15, 2019. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the
beginning of the fiscal year that includes that interim period. FirstEnergy does not expect this ASU to have a material effect on its
financial statements.
Additionally, during 2016, the FASB issued the following ASUs:
• ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,”
• ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task
Force),"
• ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and
• ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.”
FirstEnergy does not expect these ASUs to have a material effect on its financial statements
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A relating to market risk is set forth in Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
67
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT REPORT
Management’s Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Corp. (Company) were prepared by management, who takes responsibility
for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the
United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP,
an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2016 consolidated
financial statements as stated in their audit report included herein. As discussed in Note 1 to the consolidated financial statements,
FirstEnergy Corp. is engaged in a strategic review of its competitive operations and its wholly-owned subsidiary, FirstEnergy
Solutions Corp. (FES), is facing challenging market conditions impacting FES' liquidity.
The Company’s internal auditors, who are responsible to the Audit Committee of the Company’s Board of Directors, review the
results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and
reporting systems, as well as managerial and operating controls.
The Company’s Audit Committee consists of five independent directors whose duties include: consideration of the adequacy of
the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity
of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors
the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The
Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the independent registered public accounting firm and for
reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on
internal quality control and reviews all relationships between the independent registered public accounting firm and the Company,
in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s
programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes
procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held
eight meetings in 2016.
68
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of FirstEnergy Corp.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss),
comprehensive income (loss), common stockholders’ equity, and of cash flows, present fairly, in all material respects, the financial
position of FirstEnergy Corp. and its subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing
under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management
is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on
these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting
based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance
about whether the financial statements are free of material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on
the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances.
We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 1 to the consolidated financial statements, FirstEnergy Corp. is engaged in a strategic review of its
competitive operations and its wholly-owned subsidiary, FirstEnergy Solutions Corp. (FES), is facing challenging market conditions
impacting FES' liquidity.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Cleveland, Ohio
February 21, 2017
69
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In millions)
REVENUES:
Regulated Distribution
Regulated Transmission
Unregulated businesses
Total revenues*
OPERATING EXPENSES:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of assets (Note 2)
Total operating expenses
OPERATING INCOME (LOSS)
OTHER INCOME (EXPENSE):
Investment income (loss)
Impairment of equity method investment (Note 2)
Interest expense
Capitalized financing costs
Total other expense
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(BENEFITS)
INCOME TAXES (BENEFITS)
INCOME (LOSS) FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of $69) (Note 20)
NET INCOME (LOSS)
EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 20)
Basic - Net Income (Loss)
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 20)
Diluted - Net Income (Loss)
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic
Diluted
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
$
$
$
$
$
$
For the Years Ended December 31
2014
2015
2016
$
9,629 $
1,151
3,782
14,562
9,625 $
1,011
4,390
15,026
9,102
769
5,178
15,049
2,280
4,716
3,962
835
1,220
12
962
—
13,987
1,062
72
—
(1,081 )
118
(891 )
171
(42 )
213
86
299
0.51
0.20
0.71
0.51
0.20
0.71
420
421
1.44
1,666
3,813
3,858
147
1,313
320
1,042
10,665
22,824
(8,262 )
84
—
(1,157 )
103
(970 )
(9,232 )
(3,055 )
(6,177 )
—
(6,177 ) $
(14.49 ) $
—
(14.49 ) $
(14.49 ) $
—
(14.49 ) $
426
426
1.44 $
1,855
4,318
3,749
242
1,282
268
978
42
12,734
2,292
(22 )
(362 )
(1,132 )
117
(1,399 )
893
315
578
—
578 $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
422
424
1.44 $
* Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively.
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
70
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions)
NET INCOME (LOSS)
For the Years Ended December 31
2016
2015
2014
$
(6,177 ) $
578 $
299
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs
Amortized losses (gains) on derivative hedges
Change in unrealized gain on available-for-sale securities
Other comprehensive income (loss)
Income taxes (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
(59 )
8
55
4
1
3
(116 )
5
(11 )
(122 )
(47 )
(75 )
(76 )
(2 )
26
(52 )
(14 )
(38 )
COMPREHENSIVE INCOME (LOSS)
$
(6,174 ) $
503 $
261
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
71
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
Customers, net of allowance for uncollectible accounts of $53 in 2016 and $69 in 2015
Other, net of allowance for uncollectible accounts of $1 in 2016 and $5 in 2015
Materials and supplies, at average cost
Prepaid taxes
Derivatives
Collateral
Other
PROPERTY, PLANT AND EQUIPMENT:
In service
Less — Accumulated provision for depreciation
Construction work in progress
INVESTMENTS:
Nuclear plant decommissioning trusts
Other
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill
Regulatory assets
Other
$
$
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
Short-term borrowings
Accounts payable
Accrued taxes
Accrued compensation and benefits
Derivatives
Collateral
Other
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 442,344,218 and 423,560,397
shares outstanding as of December 31, 2016 and December 31, 2015, respectively
Other paid-in capital
Accumulated other comprehensive income
Retained earnings (Accumulated deficit)
Total common stockholders’ equity
Noncontrolling interest
Total equity
Long-term debt and other long-term obligations
NONCURRENT LIABILITIES:
Accumulated deferred income taxes
Retirement benefits
Asset retirement obligations
Deferred gain on sale and leaseback transaction
Adverse power contract liability
Other
December 31,
2016
December 31,
2015
$
199 $
1,440
175
564
98
140
176
158
2,950
43,767
15,731
28,036
1,351
29,387
2,514
512
3,026
5,618
1,014
1,153
7,785
43,148 $
1,685 $
2,675
1,043
580
363
78
42
660
7,126
44
10,555
174
(4,532 )
6,241
—
6,241
18,192
24,433
3,765
3,719
1,482
757
162
1,704
11,589
131
1,415
180
785
135
157
70
167
3,040
49,952
15,160
34,792
2,422
37,214
2,282
506
2,788
6,418
1,348
1,286
9,052
52,094
1,166
1,708
1,075
519
334
106
52
642
5,602
42
9,952
171
2,256
12,421
1
12,422
19,099
31,521
6,773
4,245
1,410
791
197
1,555
14,971
52,094
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16)
$
43,148 $
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
72
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
FIRSTENERGY CORP.
Common Stock
Number of
Shares
418,628,559 $
Par Value
Other
Paid-In
Capital
Accumulated
Other
Comprehensive
Income
Retained
Earnings
(Accumulated
Deficit)
42 $
9,776 $
284 $
(In millions, except share amounts)
Balance, January 1, 2014
Net income
Amortized gains on derivative hedges, net of
$1 million of income tax benefits
Change in unrealized gain on investments,
net of $10 million of income taxes
Pension and OPEB, net of $23 million of
income tax benefits (Note 4)
Stock-based compensation
Cash dividends declared on common stock
Stock Investment Plan and certain share-
based benefit plans
Balance, December 31, 2014
Net income
Amortized gains on derivative hedges, net of
$1 million of income taxes
Change in unrealized gain on investments,
net of $4 million of income tax benefits
Pension and OPEB, net of $44 million of
income tax benefits (Note 4)
Stock-based compensation
Cash dividends declared on common stock
Stock Investment Plan and certain share-
based benefit plans
Balance, December 31, 2015
Net loss
Amortized gains on derivative hedges, net of
$3 million of income taxes
Change in unrealized gain on investments,
net of $21 million of income taxes
Pension and OPEB, net of $23 million of
income tax benefits (Note 4)
Stock-based compensation
Cash dividends declared on common stock
Stock Investment Plan and certain share-
based benefit plans
Stock issuance (Note 12)
Balance, December 31, 2016
20
2,474,011
421,102,570
42
51
9,847
45
2,457,827
423,560,397
42
60
9,952
49
(1 )
16
(53 )
246
4
(7 )
(72 )
171
5
34
(36 )
2,590
299
(604 )
2,285
578
(607 )
2,256
(6,177 )
(611 )
2,685,946
16,097,875
442,344,218 $
2
44 $
56
498
10,555 $
174 $
(4,532 )
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
73
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (loss)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-
related costs
Impairment of assets
Investment impairment, including equity method investments
Pension and OPEB mark-to-market adjustment
Deferred income taxes and investment tax credits, net
Deferred costs on sale leaseback transaction, net
Deferred purchased power and fuel costs
Asset removal costs charged to income
Retirement benefits
Commodity derivative transactions, net (Note 11)
Pension trust contributions
Gain on sale of investment securities held in trusts
Lease payments on sale and leaseback transaction
Income from discontinued operations (Note 20)
Changes in current assets and liabilities-
Receivables
Materials and supplies
Prepayments and other current assets
Accounts payable
Accrued taxes
Accrued compensation and benefits
Other current liabilities
Cash collateral, net
Other
Net cash provided from operating activities
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt
Short-term borrowings, net
Redemptions and Repayments-
Long-term debt
Short-term borrowings, net
Common stock dividend payments
Other
Net cash (used for) provided from financing activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
Nuclear fuel
Proceeds from asset sales
Sales of investment securities held in trusts
Purchases of investment securities held in trusts
Asset removal costs
Other
Net cash used for investing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: stock contribution to pension plan
Cash paid (received) during the year -
Interest (net of amounts capitalized)
Income taxes (received), net of refunds
For the Years Ended December 31
2016
2015
2014
$
(6,177 ) $
578 $
299
1,997
10,665
21
147
(3,063 )
49
(30 )
54
64
9
(382 )
(50 )
(120 )
—
(11 )
41
27
(37 )
61
29
56
(116 )
137
3,371
1,976
975
(2,331 )
—
(611 )
(31 )
(22 )
(2,835 )
(232 )
15
1,678
(1,789 )
(145 )
27
(3,281 )
68
131
199 $
1,922
42
464
242
284
48
(105 )
55
(20 )
(73 )
(143 )
(23 )
(131 )
—
184
(15 )
(10 )
(243 )
29
5
69
140
148
3,447
1,311
—
(879 )
(91 )
(607 )
(13 )
(279 )
(2,704 )
(190 )
20
1,534
(1,648 )
(142 )
8
(3,122 )
46
85
131 $
500 $
1,050 $
(16 ) $
— $
1,028 $
37 $
1,592
—
37
835
162
48
(115 )
28
(53 )
64
—
(64 )
(137 )
(86 )
139
(65 )
126
42
(165 )
(22 )
54
(54 )
48
2,713
4,528
—
(1,759 )
(1,605 )
(604 )
(47 )
513
(3,312 )
(233 )
394
2,133
(2,236 )
(153 )
48
(3,359 )
(133 )
218
85
—
931
(103 )
$
$
$
$
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
74
FIRSTENERGY CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note
Number
Page
Number
1
Organization and Basis of Presentation ...........................................................................................
76
2
Asset Impairments ...........................................................................................................................
86
3
4
5
6
7
8
9
Accumulated Other Comprehensive Income ...................................................................................
88
Pension and Other Postemployment Benefits .................................................................................
91
Stock-Based Compensation Plans ..................................................................................................
98
Taxes ...............................................................................................................................................
102
Leases .............................................................................................................................................
107
Intangible Assets .............................................................................................................................
109
Variable Interest Entities ..................................................................................................................
109
10
Fair Value Measurements ................................................................................................................
112
11
Derivative Instruments .....................................................................................................................
118
12
Capitalization ...................................................................................................................................
125
13
Short-Term Borrowings and Bank Lines of Credit ............................................................................
129
14
Asset Retirement Obligations ..........................................................................................................
133
15
Regulatory Matters ..........................................................................................................................
134
16
Commitments, Guarantees and Contingencies ...............................................................................
142
17
Transactions with Affiliated Companies ...........................................................................................
149
18
Supplemental Guarantor Information ...............................................................................................
151
19
Segment Information .......................................................................................................................
160
20
Discontinued Operations .................................................................................................................
162
21
Summary of Quarterly Financial Data (Unaudited) ..........................................................................
162
22
Subsequent Events .........................................................................................................................
163
75
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying
Glossary of Terms.
FE was organized under the laws of the State of Ohio 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 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 six million customers
in the Midwest and Mid-Atlantic regions. Its regulated and unregulated generation subsidiaries control nearly 17,000 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 24,000 miles of lines and two regional transmission operation centers.
FES, a subsidiary of FE, was organized under the laws of the State of Ohio 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. FES purchases the entire output of the generation facilities owned
by FG and NG, and purchases the uncommitted output of AE Supply, as well as the output relating to leasehold interests of OE
and TE in certain of those facilities that are subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service
PSAs. FES complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NRC and applicable state
regulatory authorities.
FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC,
FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The
preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities.
Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of
operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or
disclosure through the date the financial statements were issued.
FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities
for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as
appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 9, Variable
Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but
do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the
entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s
earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). These Notes to the
Consolidated Financial Statements are combined for FirstEnergy and FES.
Certain prior year amounts have been reclassified to conform to the current year presentation.
Strategic Review of Competitive Operations
FirstEnergy believes having a combination of distribution, transmission and generation assets in a regulated or regulated-like
construct is the best way to serve customers. FirstEnergy’s strategy is to be a fully regulated utility, focusing on stable and
predictable earnings and cash flow from its regulated business units.
Over the past several years, CES has been impacted by a prolonged decrease in demand and excess generation supply in the
PJM Region, which has resulted in a period of protracted low power and capacity prices. To address this, CES sold or deactivated
more than 6,770 MWs of competitive generation from 2012 to 2015. Additionally, CES has continued to focus on cost reductions,
including those identified as part of FirstEnergy’s previously disclosed cash flow improvement plan.
76
However, the energy and capacity markets continue to be weak, as evidenced by the significantly depressed capacity prices from
the 2019/2020 PJM Base Residual Auction in May of 2016 as well as the current forward pricing and the long-term fundamental
view on energy and capacity prices, which resulted in a non-cash pre-tax impairment charge of $800 million ($23 million at FES)
recognized in the second quarter of 2016 representing the total amount of goodwill at CES.
As part of a continual process to evaluate its overall generation business, on July 22, 2016, FirstEnergy announced its intent to
exit the 136 MW Bay Shore Unit 1 generating station by October 2020 and to deactivate Units 1-4 of the W.H. Sammis generating
station totaling 720 MWs by May 2020, resulting in a $647 million ($517 million at FES) non-cash pre-tax impairment charge in
the second quarter of 2016. Furthermore, in November of 2016, FirstEnergy announced that it had begun a strategic review of its
competitive operations as it transitions to a fully regulated utility with a target to implement its exit from competitive operations by
mid-2018.
As a result of this strategic review, FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset
purchase agreement to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in Bath
County (1,572 MWs of combined capacity) for an all-cash purchase price of $925 million, subject to customary and other closing
conditions as further discussed in Note 22, Subsequent Events, including the satisfaction and discharge of $305 million of AE
Supply’s senior notes, which is expected to require the payment of a “make-whole” premium currently estimated to be
approximately $100 million based on current interest rates. Additionally, in connection with MP's RFP seeking additional generation
capacity, AE Supply offered the Pleasants power station (1,300 MWs) for approximately $195 million.
Although FirstEnergy is targeting mid-2018 to exit from competitive operations, the options for the remaining portion of CES'
generation are still uncertain, but could include one or more of the following:
• Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,
• Additional asset sales and/or plant deactivations,
• Restructuring FES debt with its creditors, and/or
• Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.
Furthermore, adverse outcomes in previously disclosed disputes regarding long-term coal transportation contracts and/or the
inability to extend or refinance debt maturities at FES subsidiaries, could accelerate management’s targeted timeline and limit its
options to fully exit competitive operations to either restructuring debt with its creditors or seeking protection under U.S. bankruptcy
laws for FES and possibly FENOC.
As part of assessing the viability of strategic alternatives, FirstEnergy determined that the carrying value of long-lived assets of
the competitive business were not recoverable, specifically given FirstEnergy’s target to implement its exit from competitive
operations by mid-2018, significantly before the end of the original useful lives, and the anticipated cash flows over this shortened
period. As a result, CES recorded a non-cash pre-tax impairment charge of $9,218 million ($8,082 million at FES) in the fourth
quarter of 2016 to reduce the carrying value of certain assets to their estimated fair value, including long-lived assets such as
generating plants and nuclear fuel, as well as other assets such as materials and supplies.
Today, the competitive generation portfolio is comprised of more than 13,000 MWs of generation, primarily from coal, nuclear and
natural gas and oil fuel sources. The assets can generate approximately 70-75 million MWHs annually, with up to an additional
five million MWHs available from purchased power agreements for wind, solar, and CES' entitlement in OVEC, of which a portion
is sold through various retail channels and the remainder targeting forward wholesale or spot sales. Subject to the completion of
the sale of the AE Supply natural gas generating plants and AGC’s interest in Bath County and, if accepted in the MP RFP process
as the winning bidder, the transfer of the Pleasants Power station to MP, the size and generation capacity of CES’ current portfolio
will reduce to approximately 10,000 MWs with approximately 60-65 million MWHs produced annually.
The competitive business continues to be managed conservatively due to the stress of weak energy prices, insufficient results
from recent capacity auctions and anemic demand forecasts that have lowered the value of the business. Furthermore, the credit
quality of CES, specifically FES' unsecured debt rating of Caa1 at Moody’s, CCC+ at S&P and C at Fitch and negative outlook
from each of the rating agencies has challenged its ability to hedge generation with retail and forward wholesale sales due to
collateral requirements that otherwise would reduce available liquidity. A lack of viable alternative strategies for its competitive
portfolio has and would further stress the financial condition of FES. As a result, CES' contract sales are expected to decline from
53 million MWHs in 2016 to 40-45 million MWHs in 2017, and to 35-40 million MWHs in 2018. While the reduced contract sales
will decrease potential collateral requirements, market price volatility may significantly impact CES' financial results due to the
increased exposure to the wholesale spot market.
77
Going Concern at FES
Although FES has access to a $500 million credit facility with FE, in lieu of access to the unregulated money pool, all of which is
available as of January 31, 2017, its current credit rating and the current forward wholesale pricing environment are a significant
challenge to FES. Furthermore, a lack of viable alternative strategies for its competitive portfolio would further stress the liquidity
and financial condition of FES.
As previously disclosed, FES has $130 million of debt maturities that need to be refinanced in 2017 (and $515 million of maturing
debt in 2018 beginning in the second quarter). Based on its current senior unsecured debt rating and current capital structure,
reflecting the impact of the impairment charges discussed above, as well as the forecasted decline in wholesale forward market
prices over the next few years, these debt maturities will be difficult to refinance, even on a secured basis, which would further
stress FES' anticipated liquidity. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including
additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like
construct in a way that provides FES with the means to satisfy its obligations over the long-term, may require FES to restructure
debt and other financial obligations with its creditors or seek protection under U.S bankruptcy laws. In the event FES seeks
protection under U.S. bankruptcy laws, FENOC may similarly seek such protection. Although management is exploring capital and
other cost reductions, asset sales, and other options to improve cash flow as well as continuing with legislative efforts to explore
a regulatory solution, these obligations and their impact on 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.
ACCOUNTING FOR THE EFFECTS OF REGULATION
FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, PATH
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.
FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded
under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income
concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets
and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy and the Utilities net their regulatory
assets and liabilities based on federal and state jurisdictions.
The following table provides information about the composition of net regulatory assets as of December 31, 2016 and
December 31, 2015, and the changes during the year ended December 31, 2016:
Regulatory Assets by Source
December 31,
2016
December 31,
2015
Increase
(Decrease)
(In millions)
Regulatory transition costs
$
Customer receivables for future income taxes
Nuclear decommissioning and spent fuel disposal costs
Asset removal costs
Deferred transmission costs
Deferred generation costs
Deferred distribution costs
Contract valuations
Storm-related costs
Other
Net Regulatory Assets included on the Consolidated Balance Sheets
$
90 $
444
(304 )
(470 )
127
215
296
153
353
110
1,014 $
185 $
355
(272 )
(372 )
115
243
335
186
403
170
1,348 $
(95 )
89
(32 )
(98 )
12
(28 )
(39 )
(33 )
(50 )
(60 )
(334 )
Regulatory assets that do not earn a current return totaled approximately $153 million and $148 million as of December 31, 2016
and 2015, respectively, primarily related to storm damage costs, and are currently being recovered through rates.
78
As of December 31, 2016 and December 31, 2015, FirstEnergy had approximately $157 million and $116 million of net regulatory
liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified within other noncurrent liabilities
on the Consolidated Balance Sheets.
REVENUES AND RECEIVABLES
The Utilities' principal business is providing electric service to customers in Ohio, Pennsylvania, West Virginia, New Jersey and
Maryland. FES' principal business is supplying electric power to end-use customers through retail and wholesale arrangements,
including affiliated company power sales to meet a portion of the POLR and default service requirements, and competitive retail
sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. Retail customers are metered
on a cycle basis.
Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues
is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes
many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity
and prices in effect for each class of customer. In each accounting period, FirstEnergy accrues the estimated unbilled amount as
revenue and reverses the related prior period estimate.
Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial
customers for the Utilities, and retail and wholesale sales to customers for FES. There was no material concentration of receivables
as of December 31, 2016 and 2015 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer
receivables as of December 31, 2016 and 2015 are included below.
Customer Receivables
FirstEnergy
FES
December 31, 2016
Billed
Unbilled
Total
December 31, 2015
Billed
Unbilled
Total
(In millions)
833 $
607
1,440 $
836 $
579
1,415 $
123
90
213
165
110
275
$
$
$
$
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Basic earnings (loss) per share of common stock are computed using the weighted average number of common shares
outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock
reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if
dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted
earnings (loss) per share of common stock:
79
Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common
Stock
2016
2015
2014
Income (loss) from continuing operations available to common shareholders
Discontinued operations (Note 20)
Net income (loss)
$
(In millions, except per share amounts)
213
86
299
(6,177 ) $
—
(6,177 ) $
578 $
—
578 $
$
Weighted average number of basic shares outstanding
Assumed exercise of dilutive stock options and awards(1)
Weighted average number of diluted shares outstanding
426
—
426
422
2
424
Earnings (loss) per share:
Basic earnings (loss) per share:
Continuing operations
Discontinued operations (Note 20)
Earnings (loss) per basic share
Diluted earnings (loss) per share:
Continuing operations
Discontinued operations (Note 20)
Earnings (loss) per diluted share
$
$
$
$
(14.49 ) $
—
(14.49 ) $
(14.49 ) $
—
(14.49 ) $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
420
1
421
0.51
0.20
0.71
0.51
0.20
0.71
(1) For the year ended December 31, 2016, approximately three million shares were excluded from the calculation of diluted shares outstanding,
as their inclusion would be antidilutive as a result of the net loss for the period. For the years ended December 31, 2015 and 2014,
approximately one million and two million shares were excluded from the calculation of diluted shares outstanding, respectively, as their
inclusion would be antidilutive.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such
as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs
of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned
major maintenance projects as they are incurred. The cost of nuclear fuel is capitalized within the CES segment's Property, plant
and equipment and charged to fuel expense using the specific identification method. Property, plant and equipment balances by
segment as of December 31, 2016 and 2015 were as follows:
December 31, 2016
Property, Plant and Equipment
In Service(1)
Accum. Depr.
Net Plant
CWIP
Total PP&E
Regulated Distribution(2)
Regulated Transmission(2)
Competitive Energy Services(3)
Corporate/Other
Total
$
$
(In millions)
24,979 $
9,342
8,680
766
43,767 $
(7,169 ) $
(1,948 )
(6,267 )
(347 )
(15,731 ) $
17,810 $
7,394
2,413
419
28,036 $
472 $
383
453
43
1,351 $
18,282
7,777
2,866
462
29,387
80
December 31, 2015
Property, Plant and Equipment
In Service(1)
Accum. Depr.
Net Plant
CWIP
Total PP&E
Regulated Distribution(2)
Regulated Transmission(2)
Competitive Energy Services(3)
Corporate/Other
Total
$
$
(In millions)
24,034 $
8,222
17,214
482
49,952 $
(6,865 ) $
(1,840 )
(6,213 )
(242 )
(15,160 ) $
17,169 $
6,382
11,001
240
34,792 $
530 $
484
1,304
104
2,422 $
17,699
6,866
12,305
344
37,214
(1) Includes capital leases of $244 million and $253 million at December 31, 2016 and 2015, respectively.
(2) Net plant in service of $326 million as of December 31, 2015 was reclassified to conform to the current presentation reflecting
the transfer of certain transmission assets from Regulated Distribution to Regulated Transmission during the fourth quarter of
2016. See "Note 19, Segment Information", for more information.
(3) Primarily consists of generating assets and nuclear fuel as discussed above.
The major classes of Property, plant and equipment are largely consistent with the segment disclosures above, with the exception
of Regulated Distribution, which has approximately $2.1 billion of regulated generation property, plant and equipment.
Property, plant and equipment balances for FES as of December 31, 2016 and 2015 were as follows:
December 31, 2016
Property, Plant and Equipment
In Service
Accum. Depr.
Net Plant
CWIP
Total PP&E
Fossil Generation
Nuclear Generation
Nuclear Fuel
Other
Total
$
$
(In millions)
2,212 $
2,065
2,637
143
7,057 $
(1,720 ) $
(1,723 )
(2,418 )
(68 )
(5,929 ) $
492 $
342
219
75
1,128 $
63 $
118
241
5
427 $
555
460
460
80
1,555
December 31, 2015
Property, Plant and Equipment
In Service
Accum. Depr.
Net Plant
CWIP
Total PP&E
Fossil Generation
Nuclear Generation
Nuclear Fuel
Other
Total
(In millions)
$
$
5,911 $
5,617
2,616
167
14,311 $
(1,937 ) $
(1,574 )
(2,198 )
(56 )
(5,765 ) $
3,974 $
4,043
418
111
8,546 $
218 $
512
283
144
1,157 $
4,192
4,555
701
255
9,703
FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant
in service. The respective annual composite rates for FirstEnergy's and FES' electric plant in 2016, 2015 and 2014 are shown in
the following table:
Annual Composite Depreciation Rate
2016
2015
2014
FirstEnergy
FES
2.5 %
3.3 %
2.5 %
3.2 %
2.5 %
3.1 %
During the third quarter of 2016, FirstEnergy recorded a reduction to depreciation expense of $21 million ($19 million prior to
January 1, 2016) that related to prior periods. The out-of-period adjustment related to the utilization of an accelerated useful life
for a component of a certain power station. Management has determined this adjustment is not material to the current period or
any prior periods.
81
For the years ended December 31, 2016, 2015 and 2014, capitalized financing costs on FirstEnergy's Consolidated Statements
of Income (Loss) include $37 million, $49 million and $49 million, respectively, of allowance for equity funds used during
construction and $66 million, $68 million and $69 million, respectively, of capitalized interest.
For the years ended December 31, 2016, 2015 and 2014, capitalized financing costs on FES' Consolidated Statements of Income
(Loss) includes $34 million, $35 million and $34 million, respectively, of capitalized interest.
Jointly Owned Plants
FE, through its subsidiary, AGC, owns an undivided 40% interest (1,200 MWs) in a 3,003 MW pumped storage, hydroelectric
station in Bath County, Virginia, operated by the 60% owner, Virginia Electric and Power Company, a non-affiliated utility. Net
Property, plant and equipment includes $639 million representing AGC's share in this facility as of December 31, 2016 of which
$458 million is unregulated and included within the CES segment. AGC is obligated to pay its share of the costs of this jointly-
owned facility in the same proportion as its ownership interest using its own financing. AGC's share of direct expenses of the joint
plant is included in FE's operating expenses on the Consolidated Statements of Income (Loss). Approximately 59% of AGC is
owned by AE Supply and approximately 41% by MP. As part of FE's strategic review of its competitive operations, on January 18,
2017, AGC entered into an asset purchase agreement with Aspen to sell AE Supply's indirect interest (23.75%) in Bath County, as
discussed in "Note 22, Subsequent Events". Additionally, on December 16, 2016, MP issued an RFP for the sale of its ownership
interest in Bath County, discussed in "Note 15, Regulatory Matters".
Asset Retirement Obligations
FE recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental
liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FE's current
obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair
value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FE uses an expected
cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach
applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios
consider settlement of the ARO at the expiration of the nuclear power plant's current license, settlement based on an extended
license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the
life of the related asset.
Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which
they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of
settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the
timing of the liability recognition.
AROs as of December 31, 2016, are described further in "Note 14, Asset Retirement Obligations".
ASSET IMPAIRMENTS
Long-Lived Assets
FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances
indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows
attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted
future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated
fair value.
See Note 2, Asset Impairments, for long-lived asset impairments recognized during 2016 and 2015.
82
Goodwill
In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities
assumed is recognized as goodwill. FirstEnergy's reporting units are consistent with its reportable segments and consist of
Regulated Distribution, Regulated Transmission, and CES. The following table presents the changes in the carrying value of
goodwill for the year ended December 31, 2016:
Goodwill
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Consolidated
Balance as of December 31, 2015
Impairment
Transmission Segment (1)
Balance as of December 31, 2016
$
$
5,092 $
—
(88 )
5,004 $
(In millions)
526 $
—
88
614 $
800 $
(800 )
—
— $
6,418
(800 )
—
5,618
(1) See Note 19, Segment Information for discussion of transfer of certain transmission assets from the Regulated Distribution segment to
the Regulated Transmission segment during the fourth quarter of 2016, resulting in the transfer of $88 million of goodwill between the
segments based on the relative fair value of the transmission assets to fair value of the Regulated Distribution segment.
FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potential
impairment arise.
As of July 31, 2016, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission
reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial
performance. It was determined that the fair value of these reporting units were, more likely than not, greater than their carrying
value and a quantitative analysis was not necessary.
See Note 2, Asset Impairments, for goodwill impairment recognized during 2016 at CES.
Investments
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the
Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash
equivalents include held-to-maturity securities and AFS securities.
At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are
evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent
and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which
the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an
investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be
required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost
basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair
value.
Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE
and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability
and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with
unrealized gains and losses offset against regulatory assets. In 2016, 2015 and 2014, FirstEnergy recognized $21 million, $102
million and $37 million, respectively, of OTTI. During the same periods, FES recognized OTTI of $19 million, $90 million and $33
million, respectively. The fair values of FirstEnergy’s investments are disclosed in Note 10, Fair Value Measurements.
The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct
placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives,
securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.
83
FirstEnergy holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining
and coal transportation operations with coal sales in U.S. and international markets. In 2015, Global Holding incurred losses
primarily as a result of declines in coal prices due to weakening global and U.S. coal demand. Based on the significant decline in
coal pricing and the outlook for the coal market, including the significant decline in the market capitalization of coal companies in
2015, FirstEnergy assessed the value of its investment in Global Holding and determined there was a decline in the fair value of
the investment below its carrying value that was other than temporary, resulting in a pre-tax impairment charge of $362 million
recognized in 2015. Key assumptions incorporated into the discounted cash flow analysis utilized in the impairment analysis
included the discount rate, future long-term coal prices, production levels, sales forecasts, projected capital and operating costs.
The impairment charge is classified as a component of Other Income (Expense) in the Consolidated Statement of Income (Loss).
See Note 9, Variable Interest Entities, for further discussion of FirstEnergy's investment in Global Holding.
INVENTORY
Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of
reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased
and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost
when purchased, and recorded to fuel expense when consumed.
See Note 2, Asset Impairments, for inventory-related charges recognized during 2016.
NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards
updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is
that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also
be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash
flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective
for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim
reporting periods beginning after December 15, 2016. FirstEnergy will not early adopt the standards. The standards shall be
applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy has
evaluated a significant portion of its revenues and preliminarily expects limited impacts to current revenue recognition practices,
dependent on the resolution of industry issues including accounting for contributions in aid of construction and the ability to
recognize revenue for contracts where collectibility is in question. FirstEnergy continues to assess the remainder of its revenue
streams and the impact on its financial statements and disclosures as well as which transition method it will select to adopt the
guidance.
On August 27, 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity's Ability to Continue as a Going
Concern." In connection with preparing financial statements for each annual and interim reporting period, the ASU requires an
entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt
about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued.
Disclosures are required when management identifies conditions or events that raise substantial doubt. The new requirements
were effective for the annual period ended December 31, 2016.
In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial
Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair
value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance
related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-
for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods
within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim
periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating
the impact on its financial statements of adopting this standard.
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with
lease terms of more than twelve months to recognize assets and liabilities for the rights and obligations created by those leases
on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash
flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years,
84
beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified
retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest
comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date
will not require any accounting adjustment. FirstEnergy is currently evaluating the impact on its financial statements of adopting
this standard.
In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which
simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax
effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability
accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective
for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted.
Upon adoption, January 1, 2017, FirstEnergy elected to account for forfeitures as they occur. The adoption of the ASU did not
have a material impact on FirstEnergy’s financial statements.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses
on Financial Instruments”, which removes all recognition thresholds and will require companies to recognize an allowance for
credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that
the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods
within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December
15, 2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.
In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts
and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments
are presented and classified in the statement of cash flows, including the presentation of debt prepayment or debt extinguishment
costs, all of which will be classified as financing activities. The guidance is effective for fiscal years, and for interim periods within
those fiscal years, beginning after December 15, 2017. Early adoption is permitted for all entities. FirstEnergy expects to adopt
this ASU in 2017 and does not expect this ASU to have a material effect on its financial statements.
In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than
Inventory". ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies
to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale
of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction
are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time
of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December
15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance,
with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy is
currently evaluating the impact on its financial statements of adopting this standard.
In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" that will require entities to show the changes in the total of
cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no
longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement
of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line
item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related
captions in the balance sheet. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning
after December 15, 2019. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the
beginning of the fiscal year that includes that interim period. FirstEnergy does not expect this ASU to have a material effect on its
financial statements.
Additionally, during 2016, the FASB issued the following ASUs:
• ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,”
• ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task
Force),"
• ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and
• ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.”
FirstEnergy does not expect these ASUs to have a material effect on its financial statements.
85
2. ASSET IMPAIRMENTS
Property, Plant, and Equipment
On July 22, 2016, FirstEnergy and FES announced its intent to exit operations of the Bay Shore Unit 1 generating station (136
MWs) by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W. H. Sammis generating station
(720 MWs) by May 31, 2020. As a result, FirstEnergy recorded a non-cash pre-tax impairment charge of $647 million ($517 million
- FES) in the second quarter of 2016. PJM and the Independent Market Monitor have approved the W.H. Sammis Units 1-4 and
Bay Shore Unit 1 deactivations. In addition, FirstEnergy and FES recorded termination and settlement costs on fuel contracts of
approximately $58 million (pre-tax) in the second quarter of 2016 resulting from plant retirements and deactivations, which is
included in the caption of Fuel in the Consolidated Statement of Income (Loss).
As disclosed in Note 1, Organization and Basis of Presentation, in November 2016, FirstEnergy announced that it had begun a
strategic review of its competitive operations as it transitions to a fully regulated utility with a target to implement its exit from
competitive operations by mid-2018.
Although FirstEnergy is targeting mid-2018 to exit from competitive operations, the options for the remaining portion of CES'
generation are still uncertain, but could include one or more of the following:
• Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits,
• Additional asset sales and/or plant deactivations,
• Restructuring FES debt with its creditors, and/or
• Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC.
Once a plan is finalized, FE’s implementation of that plan may result in long-lived asset impairment charges, exit related losses
and costs, contingencies, and reserves against deferred tax assets that may not be realizable.
As part of assessing the viability of strategic alternatives, FirstEnergy determined that the carrying value of long-lived assets of
the competitive business were not recoverable, specifically given FirstEnergy’s target to implement its exit from competitive
operations by mid-2018, significantly before the end of the original useful lives, and the anticipated cash flows over this shortened
period. As a result, CES recorded a non-cash pre-tax impairment charge of $9,218 million ($8,082 million at FES) in the fourth
quarter of 2016 to reduce the carrying value of certain assets to their estimated fair value, including long-lived assets, such as
generating plants and nuclear fuel, as well as other assets, such as materials and supplies.
FE Consolidated
FES Consolidated
Impaired Asset
Net Book
Value
Fair Value
Impairment
Net Book
Value
Fair Value
Impairment
Coal generation assets
Nuclear generation assets
Gas/Hydro generation assets
Nuclear Fuel
Other assets (1)
Totals
$
$
4,672 $
4,842
1,187
703
382
11,786 $
614 $
460
921
460
113
2,568 $
(In millions)
4,058 $
4,382
266
243
269
9,218 $
3,699 $
4,825
—
703
314
9,541 $
435 $
460
—
460
104
1,459 $
3,264
4,365
—
243
210
8,082
(1) Includes the impairment of materials and supplies ($142 million), AE Supply coal contracts ($55 million) and AE Supply's investment in OVEC
($37 million).
Key assumptions used in determining the impairment charges of long-lived assets included forward power price projections, the
expected duration of ownership of the plants, environmental compliance costs and strategies, operating costs, and estimated sale
proceeds. Those same cash flow assumptions, along with a discount rate were used to estimate the fair value of each plant. These
assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was
based on a combination of the income approach, which considers discounted cash flows, and corroboration with the market
approach, which considers market comparisons for similar assets within the electric generation industry.
86
During 2015, FirstEnergy and FES recognized impairment charges of $42 million and $33 million, respectively, associated with
certain transportation equipment and facilities. In order to conform to current year presentation, the charges were reclassified from
Other operating expenses in the Consolidated Statement of Income (Loss) to Impairment of assets. The impairment charges are
included within the Regulated Distribution segment ($8 million) and the CES segment ($34 million).
Goodwill
As a result of low capacity prices associated with the 2019/2020 PJM Base Residual Auction in May 2016, as well as its annual
update to its fundamental long-term capacity and energy price forecast, FirstEnergy determined that an interim impairment analysis
of the CES reporting unit’s goodwill was necessary during the second quarter of 2016.
Consistent with FirstEnergy’s annual goodwill impairment test, a discounted cash flow analysis was used to determine the fair
value of the CES reporting unit for purposes of step one of the interim goodwill impairment test. Key assumptions incorporated
into the CES discounted cash flow analysis requiring significant management judgment included the following:
• Future Energy and Capacity Prices: Observable market information for near-term forward power prices, PJM auction
results for near term capacity pricing, and a longer-term fundamental pricing model for energy and capacity that
considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations,
and natural gas pipeline construction, as well as coal and natural gas pricing.
• Retail Sales and Margin: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical
financial results to estimate retail margins.
• Operating and Capital Costs: Estimated future operating and capital costs, including the estimated impact on costs of
pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in
the PJM market.
• Discount Rate: A discount rate of 9.50%, based on selected comparable companies' capital structure, return on debt
and return on equity.
• Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on
consideration of peer group data and analyst consensus expectations.
Based on the impairment analysis, FirstEnergy determined that the carrying value of goodwill exceeded its fair value and
recognized a non-cash pre-tax impairment charge of $800 million ($23 million - FES) in the second quarter of 2016, which is
included within the caption Impairment of assets in the Consolidated Statement of Income (Loss).
87
3. ACCUMULATED OTHER COMPREHENSIVE INCOME
The changes in AOCI for the years ended December 31, 2016, 2015 and 2014 for FirstEnergy are shown in the following table:
FirstEnergy
Gains &
Losses on
Cash Flow
Hedges
Unrealized
Gains on
AFS
Securities
Defined
Benefit
Pension &
OPEB Plans
Total
AOCI Balance, January 1, 2014
$
(36 ) $
Other comprehensive income before reclassifications
Amounts reclassified from AOCI
Other comprehensive income (loss)
Income tax (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
—
(2 )
(2 )
(1 )
(1 )
(In millions)
9 $
311 $
89
(63 )
26
10
16
92
(168 )
(76 )
(23 )
(53 )
AOCI Balance, December 31, 2014
$
(37 ) $
25 $
258 $
Other comprehensive income before reclassifications
Amounts reclassified from AOCI
Other comprehensive income (loss)
Income tax (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
—
5
5
1
4
14
(25 )
(11 )
(4 )
(7 )
10
(126 )
(116 )
(44 )
(72 )
AOCI Balance, December 31, 2015
$
(33 ) $
18 $
186 $
Other comprehensive income before reclassifications
Amounts reclassified from AOCI
Other comprehensive income (loss)
Income tax (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
—
8
8
3
5
106
(51 )
55
21
34
13
(72 )
(59 )
(23 )
(36 )
AOCI Balance, December 31, 2016
$
(28 ) $
52 $
150 $
284
181
(233 )
(52 )
(14 )
(38 )
246
24
(146 )
(122 )
(47 )
(75 )
171
119
(115 )
4
1
3
174
88
The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2016, 2015 and 2014:
FirstEnergy
Year Ended December 31
Reclassifications from AOCI (2)
2016
2015
2014
Affected Line Item in Consolidated
Statements of Income (Loss)
(In millions)
Gains & losses on cash flow hedges
Commodity contracts
Long-term debt
Unrealized gains on AFS securities
Realized gains on sales of securities
Defined benefit pension and OPEB plans
Prior-service costs
$
$
$
$
$ — $
8
8
(3 )
5 $
(3 ) $
8
5
(1 )
4 $
(10 ) Other operating expenses
8 Interest expense
(2 ) Total before taxes
1 Income taxes (benefits)
(1 ) Net of tax
(51 ) $
19
(32 ) $
(25 ) $
9
(16 ) $
(63 ) Investment income (loss)
24 Income taxes (benefits)
(39 ) Net of tax
(72 ) $
27
(126 ) $
49
(168 ) (1)
65 Income taxes (benefits)
$
(45 ) $
(77 ) $
(103 ) Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, Pension and Other
Postemployment Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
89
The changes in AOCI for the years ended December 31, 2016, 2015 and 2014 for FES are shown in the following table:
FES
Gains &
Losses on
Cash Flow
Hedges
Unrealized
Gains on
AFS
Securities
Defined
Benefit
Pension &
OPEB Plans
Total
(In millions)
AOCI Balance, January 1, 2014
$
(1 ) $
8 $
47 $
Other comprehensive income before reclassifications
Amounts reclassified from AOCI
Other comprehensive income (loss)
Income tax (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
—
(10 )
(10 )
(4 )
(6 )
80
(59 )
21
8
13
13
(19 )
(6 )
(2 )
(4 )
AOCI Balance, December 31, 2014
$
(7 ) $
21 $
43 $
Other comprehensive income before reclassifications
Amounts reclassified from AOCI
Other comprehensive loss
Income tax benefits on other comprehensive loss
Other comprehensive loss, net of tax
—
(3 )
(3 )
(1 )
(2 )
15
(24 )
(9 )
(4 )
(5 )
10
(16 )
(6 )
(2 )
(4 )
AOCI Balance, December 31, 2015
$
(9 ) $
16 $
39 $
Other comprehensive income before reclassifications
Amounts reclassified from AOCI
Other comprehensive income (loss)
Income tax (benefits) on other comprehensive income (loss)
Other comprehensive income (loss), net of tax
—
—
—
—
—
100
(48 )
52
20
32
—
(14 )
(14 )
(5 )
(9 )
AOCI Balance, December 31, 2016
$
(9 ) $
48 $
30 $
54
93
(88 )
5
2
3
57
25
(43 )
(18 )
(7 )
(11 )
46
100
(62 )
38
15
23
69
90
The following amounts were reclassified from AOCI for FES in the years ended December 31, 2016, 2015 and 2014:
FES
Year Ended December 31
Reclassifications from AOCI (2)
2016
2015
2014
(In millions)
Affected Line Item in Consolidated
Statements of Income (Loss)
Gains & losses on cash flow hedges
Commodity contracts
$ — $
—
$ — $
(3 ) $
1
(2 ) $
(10 ) Other operating expenses
4 Income taxes (benefits)
(6 ) Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities
$
(48 ) $
18
(24 ) $
9
(59 ) Investment income (loss)
22 Income taxes (benefits)
$
(30 ) $
(15 ) $
(37 ) Net of tax
Defined benefit pension and OPEB plans
Prior-service costs
$
$
(14 ) $
5
(16 ) $
6
(19 ) (1)
7 Income taxes (benefits)
(9 ) $
(10 ) $
(12 ) Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, Pension and Other Postemployment
Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
4. PENSION AND OTHER POSTEMPLOYMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-
qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and
compensation levels. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees
in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and
co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their
survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and
covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has
obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. In 2014, the
qualified pension plan was amended authorizing a voluntary cashout window program for certain eligible terminated participants
with vested benefits. Payment of benefits for participants that elected an immediate lump sum cash payment or an annuity resulted
in a $40 million reduction to the underfunded status of the pension plan. Additionally, during 2016 and 2015, certain unions ratified
their labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by
approximately $13 million and $10 million, respectively.
FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net
actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a
remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations,
assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market
adjustment for the years ended December 31, 2016, 2015, and 2014 were $194 million ($147 million net of amounts capitalized),
$369 million ($242 million net of amounts capitalized), and $1,243 million ($835 million net of amounts capitalized), respectively.
In 2016, the pension and OPEB mark-to-market adjustment primarily reflects a 25 basis point decline in the discount rate, partially
offset by changes in actuarial assumptions, including mortality assumptions and higher than expected asset returns.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In 2016,
FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed funding obligations for future years
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.
91
Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods),
the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by
changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates
used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement
date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement
date.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the
types of investments held by the pension trusts. In 2016, FirstEnergy’s qualified pension and OPEB plan assets experienced gains
of $472 million, or 8.2% compared to losses of $(172) million, or (2.7)% in 2015 and earnings of $387 million, or 6.2% in 2014,
and assumed a 7.50% rate of return for 2016 and a 7.75% rate of return for 2015 and 2014 on plan assets which generated $429
million, $476 million and $496 million of expected returns on plan assets, respectively. The expected return on pension and OPEB
assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities.
The gains or losses generated as a result of the difference between expected and actual returns on plan assets will increase or
decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal
year or whenever a plan is determined to qualify for remeasurement.
During 2016, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2016, incorporating
three additional years of SSA data on U.S. population mortality. MP-2016 incorporates SSA mortality data from 2012 to 2014 and
a slight modification of two input values designed to improve the model’s year-over-year stability. The updated improvement scale
indicates a slight decline in life expectancy as a result of the slower average rate of mortality improvement. Due to the additional
years of data on population mortality, the RP2014 mortality table with the projection scale MP-2016 was utilized to determine the
2016 benefit cost and obligation as of December 31, 2016 for the FirstEnergy pension and OPEB plans. The impact of using the
projection scale MP-2016 resulted in a decrease in the projected benefit obligation of $141 million and $8 million for the pension
and OPEB plans, respectively, and was included in the 2016 pension and OPEB mark-to-market adjustment.
92
Obligations and Funded Status - Qualified and Non-Qualified Plans
2016
2015
2016
2015
Pension
OPEB
Change in benefit obligation:
Benefit obligation as of January 1
Service cost
Interest cost
Plan participants’ contributions
Plan amendments
Medicare retiree drug subsidy
Actuarial (gain) loss
Benefits paid
Benefit obligation as of December 31
Change in fair value of plan assets:
Fair value of plan assets as of January 1
Actual return (losses) on plan assets
Company contributions
Plan participants’ contributions
Benefits paid
Fair value of plan assets as of December 31
Funded Status:
Qualified plan
Non-qualified plans
Funded Status
Accumulated benefit obligation
Amounts Recognized on the Balance Sheet:
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net liability as of December 31
Amounts Recognized in AOCI:
Prior service cost (credit)
Assumptions Used to Determine Benefit Obligations
(as of December 31)
Discount rate
Rate of compensation increase
Assumed Health Care Cost Trend Rates
(as of December 31)
Health care cost trend rate assumed (pre/post-Medicare)
Rate to which the cost trend rate is assumed to decline (the ultimate
trend rate)
Year that the rate reaches the ultimate trend rate
Allocation of Plan Assets (as of December 31)
Equity securities
Bonds
Absolute return strategies
Real estate
Cash and short-term securities
Total
(In millions)
$
9,079
$
9,249
$
724
$
191
398
—
—
—
224
(466 )
9,426
$
193
383
—
—
—
(277 )
(469 )
9,079
$
5
30
5
(13 )
1
14
(55 )
711
$
$
5,338
442
899
—
(466 )
6,213
$
$
5,824
(178 )
161
—
(469 )
5,338
$
$
431
30
9
5
(55 )
420
$
(2,821 ) $
(392 )
(3,213 ) $
(3,366 )
(375 )
(3,741 ) $
8,913
$
8,579
$
$
9
(19 )
(3,203 )
(3,213 ) $
$
—
(18 )
(3,723 )
(3,741 ) $
(291 ) $
—
$
$
—
—
(291 )
(291 ) $
$
$
$
$
$
$
$
$
$
757
5
29
6
(10 )
1
(2 )
(62 )
724
464
6
17
6
(62 )
431
(293 )
—
—
—
(293 )
(293 )
28
$
37
$
(288 ) $
(355 )
4.25 %
4.20 %
4.50 %
4.20 %
4.00 %
N/A
4.25 %
N/A
N/A
N/A
N/A
44 %
30 %
8 %
10 %
8 %
100 %
N/A
N/A
N/A
40 %
34 %
7 %
11 %
8 %
100 %
6.0-5.5%
6.0-5.5%
4.5 %
2027
53 %
41 %
— %
— %
6 %
100 %
4.5 %
2026
51 %
43 %
— %
— %
6 %
100 %
The estimated 2017 amortization of pension and OPEB prior service costs (credits) from AOCI into net periodic pension and
OPEB costs (credits) is approximately $8 million and $(81) million, respectively.
93
Components of Net Periodic Benefit Costs
2016
2015
2014
2016
Pension
OPEB
2015
2014
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost (credit)
Pension & OPEB mark-to-market adjustment
Net periodic benefit cost (credit)
$
$
191 $
398
(399 )
8
179
377 $
193 $
383
(443 )
8
344
485 $
(In millions)
167 $
402
(462 )
8
1,235
1,350 $
5 $
30
(30 )
(80 )
15
(60 ) $
5 $
29
(33 )
(134 )
25
(108 ) $
9
39
(34 )
(176 )
8
(154 )
Assumptions Used to Determine Net Periodic
Benefit Cost *
for Years Ended December 31
Weighted-average discount rate
Expected long-term return on plan assets
Rate of compensation increase
Pension
OPEB
2016
2015
2014
2016
2015
2014
4.50 %
7.50 %
4.20 %
4.25 %
7.75 %
4.20 %
5.00 %
7.75 %
4.20 %
4.25 %
7.50 %
N/A
4.00 %
7.75 %
N/A
4.75 %
7.75 %
N/A
*Excludes impact of pension and OPEB mark-to-market adjustment.
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income
investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of
return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s
pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy.
See Note 10, Fair Value Measurements, for a description of each level of the fair value hierarchy. There were no significant
transfers between levels during 2016 and 2015.
Cash and short-term securities
Equity investments
Domestic (2)
International
Fixed income
Government bonds
Corporate bonds
High yield debt
Mortgage-backed securities (non-
government)
Alternatives
Hedge funds (Absolute return)
Derivatives
Private equity funds
Real estate funds
Total (1)
December 31, 2016
Level 1
Level 2
Level 3
Total
$
— $
(In millions)
464 $
— $
464
1,048
422
—
—
—
—
—
—
—
—
1,470 $
13
1,269
106
1,245
372
112
500
(1 )
—
—
4,080 $
—
—
—
—
—
—
—
—
33
615
648 $
1,061
1,691
106
1,245
372
112
500
(1 )
33
615
6,198
$
Asset
Allocation
8 %
17 %
27 %
2 %
20 %
6 %
2 %
8 %
— %
— %
10 %
100 %
(1) Excludes $16 million as of December 31, 2016 of receivables, payables, taxes and accrued income associated with financial instruments
reflected within the fair value table.
(2) As a result of the $500 million equity contribution on December 13, 2016, there was $293 million of FE Stock included in the pension plan
assets as of December 31, 2016.
94
Cash and short-term securities
Equity investments
Domestic
International
Fixed income
Government bonds
Corporate bonds
High yield debt
Mortgage-backed securities (non-
government)
Alternatives
Hedge funds (Absolute return)
Derivatives
Private equity funds
Real estate funds
Total (1)
December 31, 2015
Level 1
Level 2
Level 3
Total
$
— $
(In millions)
427 $
— $
427
869
395
—
—
—
—
—
—
—
—
1,264 $
$
75
794
232
1,115
438
31
343
15
—
—
3,470 $
—
—
—
—
—
—
—
—
24
587
611 $
944
1,189
232
1,115
438
31
343
15
24
587
5,345
Asset
Allocation
8 %
18 %
22 %
4 %
21 %
8 %
1 %
7 %
— %
— %
11 %
100 %
(1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments
reflected within the fair value table.
The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair
value hierarchy during 2016 and 2015:
Private Equity
Funds
Real Estate
Funds
Balance as of January 1, 2015
Actual return on plan assets:
Unrealized gains
Realized gains (losses)
Transfers in
Balance as of December 31, 2015
Actual return on plan assets:
Unrealized gains
Realized gains
Transfers in (out)
Balance as of December 31, 2016
$
$
$
(In millions)
25 $
—
(1 )
—
24 $
1
1
7
33 $
421
42
16
108
587
29
14
(15 )
615
95
As of December 31, 2016 and 2015, the OPEB trust investments measured at fair value were as follows:
December 31, 2016
Level 1
Level 2
Level 3
Total
Asset
Allocation
Cash and short-term securities
$
— $
(In millions)
27 $
— $
Equity investment
Domestic
International
Fixed income
U.S. treasuries
Government bonds
Corporate bonds
High yield debt
Mortgage-backed securities (non-
government)
Alternatives
Hedge funds
Real estate funds
Total (1)
223
—
—
—
—
—
—
—
—
40
108
24
—
2
—
—
223 $
—
—
201 $
$
—
—
—
—
—
—
—
—
—
— $
27
223
—
40
108
24
—
2
—
—
424
6 %
53 %
— %
9 %
26 %
6 %
— %
— %
— %
— %
100 %
(1) Excludes $(4) million as of December 31, 2016 of receivables, payables, taxes and accrued income associated with financial instruments
reflected within the fair value table.
December 31, 2015
Level 1
Level 2
Level 3
Total
Asset
Allocation
Cash and short-term securities
$
— $
(In millions)
25 $
— $
Equity investment
Domestic
International
Fixed income
U.S. treasuries
Government bonds
Corporate bonds
High yield debt
Mortgage-backed securities (non-
government)
Alternatives
Hedge funds
Real estate funds
Total (1)
219
1
—
—
—
—
—
—
3
42
114
27
1
3
—
—
220 $
1
—
216 $
$
—
—
—
—
—
—
—
—
2
2 $
25
219
4
42
114
27
1
3
1
2
438
6 %
50 %
1 %
10 %
26 %
6 %
— %
1 %
— %
— %
100 %
(1) Excludes $(7) million as of December 31, 2015, of receivables, payables, taxes and accrued income associated with financial instruments
reflected within the fair value table.
96
The following table provides a reconciliation of changes in the fair value of OPEB trust investments classified as Level 3 in the fair
value hierarchy during 2016 and 2015:
Balance as of January 1, 2015
Transfers out
Balance as of December 31, 2015
Transfers out
Balance as of December 31, 2016
$
$
$
Real Estate
Funds
(in millions)
3
(1 )
2
(2 )
—
FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while
taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk
tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The
investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across
U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and
private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain
market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market
value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment
portfolio reviews, annual liability measurements and periodic asset/liability studies.
FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2016 and 2015 are shown in the following table:
Target Asset Allocations
Equities
Fixed income
Absolute return strategies
Real estate
Alternative investments
Cash
38 %
30 %
8 %
10 %
8 %
6 %
100 %
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-
percentage-point change in assumed health care cost trend rates would have the following effects:
Effect on total of service and interest cost
Effect on accumulated benefit obligation
1-Percentage-
Point Increase
1-Percentage-
Point Decrease
$
$
(In millions)
1 $
23 $
(1 )
(20 )
97
Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan
assets and other payments, net of participant contributions:
Pension
OPEB
Subsidy
Receipts
Benefit
Payments
(In millions)
$
2016
2017
2018
2019
2020
Years 2021-2025
505 $
523
534
552
566
2,999
52 $
52
53
53
53
251
(3 )
(3 )
(3 )
(3 )
(3 )
(7 )
FES’ share of the pension and OPEB net (liability) asset as of December 31, 2016 and 2015, was as follows:
Pension
OPEB
2016
2015
2016
2015
Net (Liability) Asset(1)
$
(158 ) $
(In millions)
(303 ) $
36 $
25
(1) Excludes $866 million and $785 million as of December 31, 2016 and 2015, respectively,
of affiliated non-current liabilities related to pension and OPEB mark-to-market costs
allocated to FES of which $570 million and $518 million, respectively, are from FENOC.
FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years
ended December 31, 2016 was as follows:
Pension
2016
2015
2014
2016
OPEB
2015
2014
Net Periodic Cost (Credit)
$
(5 ) $
10 $
(In millions)
150 $
(26 ) $
(22 ) $
(24 )
5. STOCK-BASED COMPENSATION PLANS
FirstEnergy grants stock-based awards through the ICP 2015, primarily in the form of restricted stock and performance-based
restricted stock units. Under FirstEnergy's previous incentive compensation plan, the ICP 2007, FirstEnergy also granted stock
options and performance shares. The ICP 2007 and ICP 2015 include shareholder authorization to issue 29 million shares and 10
million shares, respectively, of common stock or their equivalent. As of December 31, 2016, approximately 8.0 million shares were
available for future grants under the ICP 2015 assuming maximum performance metrics are achieved for the outstanding cycles
of restricted stock units. No shares are available for future grants under the ICP 2007. Any shares not issued due to forfeitures or
cancellations are added back to the ICP 2015. Shares used under the ICP 2007 and ICP 2015 are issued from authorized but
unissued common stock. Vesting periods range from one to ten years, with the majority of awards having a vesting period of three
years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the
compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value
on the grant date, less estimated forfeitures. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to
Employee Share-Based Payment Accounting", FE has elected to account for forfeitures as they occur. FirstEnergy adjusts the
compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award
as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or
settled. Actual income tax benefits realized during the years ended December 31, 2016, 2015 and 2014 were $13 million, $10
million and $13 million, respectively. Currently, the excess of the deductible amount over the recognized compensation cost is
recorded as a component of stockholders’ equity and reported as a financing activity on the Consolidated Statements of Cash
Flows. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment
Accounting", the income tax effects of awards will be recognized in the income statement when the awards vest or are settled.
98
Stock-based compensation costs and the amount of stock-based compensation expense capitalized related to FirstEnergy and
FES plans are included in the following tables:
FirstEnergy
Stock-based Compensation Plan
Years ended December 31
2016
2015
2014
(In millions)
Restricted Stock Units
Restricted Stock
Performance Shares
401(k) Savings Plan
EDCP & DCPD
Total
Stock-based compensation costs capitalized
FES
Stock-based Compensation Plan
Restricted Stock Units
Performance Shares
401(k) Savings Plan
Total
Stock-based compensation costs capitalized
$
$
$
$
$
$
62 $
2
(3 )
39
5
105 $
38 $
11 $
—
5
16 $
2 $
46 $
2
—
38
3
89 $
32 $
6 $
—
5
11 $
1 $
26
5
5
25
8
69
23
4
1
4
9
1
Years ended December 31
2016
2015
2014
(In millions)
Stock option expense was not material for FirstEnergy or FES for the years December 31, 2016, 2015 or 2014. Income tax benefits
associated with stock based compensation plan expense were $14 million, $12 million and $14 million (FES - $2 million, $2 million
and $2 million) for the years ended 2016, 2015 and 2014, respectively.
Restricted Stock Units
Beginning with the performance-based restricted stock units granted in 2015, two-thirds will be paid in stock and one-third will be
paid in cash. Prior to 2015, all performance-based restricted stock units were paid in stock. Restricted stock units paid in stock
provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the
number of stock units set forth in the agreement subject to adjustment based on FirstEnergy's performance relative to financial
and operational performance targets. The grant date fair value of the stock portion of the restricted stock unit award is measured
based on the average of the high and low prices of FE common stock on the date of grant. Restricted stock units paid in cash
provide the participant the right to receive cash based on the numbers of stock units set forth in the agreement and value of the
equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is
considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments.
The liability recorded for cash performance based restricted stock units as of December 31, 2016 was $14 million. No cash was
paid to settle the restricted stock unit obligations in 2016. The vesting period for each of the awards was three years. Dividend
equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same
performance conditions.
99
Restricted stock unit activity for the year ended December 31, 2016, was as follows:
Restricted Stock Unit Activity
Shares
Weighted-
Average Grant
Date Fair Value
Nonvested as of January 1, 2016
Granted in 2016
Forfeited in 2016
Vested in 2016(1)
Nonvested as of December 31, 2016
$
2,436,888
1,581,762
(81,618 )
(873,303 )
3,063,729 $
35.26
34.77
33.85
33.54
32.98
(1) Excludes dividend equivalents of 132,360 earned during vesting period
The weighted average fair value of awards granted in 2016, 2015 and 2014 were $34.77, $35.27 and $32.17 respectively. For the
years ended December 31, 2016, 2015, and 2014, the fair value of restricted stock units vested was $36 million, $22 million, and
$28 million, respectively. As of December 31, 2016, there was $47 million of total unrecognized compensation cost related to non-
vested share-based compensation arrangements granted for restricted stock units; that cost is expected to be recognized over a
period of approximately two years.
Restricted Stock
Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the
restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair
value of restricted stock is measured based on the average of the high and low prices of FirstEnergy common stock on the date
of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock.
Restricted common stock (restricted stock) activity for the year ended December 31, 2016, was as follows:
Restricted Stock
Nonvested as of January 1, 2016
Granted in 2016
Vested in 2016(1)
Nonvested as of December 31, 2016
Number of
Shares
190,656 $
28,756
(82,252 )
137,160 $
Weighted
Average
Grant-Date
Fair Value
40.65
32.69
46.83
35.27
(1) Excludes 23,402 shares for dividends earned during vesting period
The weighted average vesting period for restricted stock granted in 2016 was 3.49 years. The weighted average fair value of
awards granted in 2016, 2015, and 2014 were $32.69, $32.98 and $32.71 respectively. For the years ended December 31, 2016,
2015, and 2014, the fair value of restricted stock vested was $5 million, $8 million, and $4 million, respectively. As of December 31,
2016, there was $2 million of total unrecognized compensation cost related to non-vested restricted stock, which is expected to
be recognized over a period of approximately three years.
100
Stock Options
Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed
exercise price over a defined period of time. Stock options generally expire ten years from the date of grant. There were no stock
options granted in 2016. Stock option activity during 2016 was as follows:
Stock Option Activity
Balance, January 1, 2016 (1,211,358 options exercisable)
Options forfeited
Balance, December 31, 2016 (1,376,821 options exercisable)
Number of
Shares
1,411,971 $
(35,150 )
1,376,821 $
Weighted
Average
Exercise
Price
44.89
56.40
44.60
There was no cash received from the exercise of stock options in 2016. Cash received from the exercise of stock options in 2015
and 2014 was not material. The weighted-average remaining contractual term of options outstanding as of December 31, 2016
was 3.60 years.
Performance Shares
Prior to the 2015 grant of performance-based restricted stock units discussed above, the Company granted performance shares.
Performance shares are share equivalents and do not have voting rights. The performance shares outstanding track the
performance of FE's common stock over a three-year vesting period. Dividend equivalents accrue on performance shares and are
reinvested into additional performance shares with the same performance conditions. The final account value may be adjusted
based on the ranking of FE stock performance to a composite of peer companies. In 2016, $2 million cash was paid to settle
performance shares that vested over the 2013-2015 performance cycle. During 2015, no cash was paid to settle performance
shares because the performance criteria was not met for the 2012-2014 cycle.
401(k) Savings Plan
In 2016 and 2015, 1,159,215 and 1,072,494 shares of FE common stock, respectively, were issued and contributed to participants'
accounts.
EDCP
Under the EDCP, covered employees can defer a portion of their compensation, including base salary, annual incentive awards
and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in
FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest.
Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of
payout as stock or cash can vary depending upon the form of the award, the duration of the deferral and other factors. Certain
types of deferrals such as dividend equivalent units, Short-Term Incentive Awards, and performance share awards are required to
be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although
participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement.
In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years, effective for deferrals
made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from
service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in
cash over a time period as elected by the participant.
DCPD
Under the DCPD, members of the Board of Directors can elect to allocate all or a portion of their equity retainers to deferred stock
and their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. The net liability recognized for
DCPD of approximately $7 million and $9 million as of December 31, 2016 and December 31, 2015, respectively, is included in
the caption “Retirement benefits” on the Consolidated Balance Sheets.
101
6. TAXES
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax
effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the
amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences
and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be
paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of
consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense
associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have
taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit.
INCOME TAXES (BENEFITS)(1)
2016
2015
2014
(In millions)
FirstEnergy
Currently payable (receivable)-
Federal
State
Deferred, net-
Federal
State
Investment tax credit amortization
$
(1 ) $
9
8
(3,114 )
59
(3,055 )
(8 )
Total provision for income taxes (benefits)
$
(3,055 ) $
FES
Currently payable (receivable)-
Federal
State
Deferred, net-
Federal
State
Investment tax credit amortization
$
(67 ) $
(1 )
(68 )
(2,861 )
(57 )
(2,918 )
(2 )
Total provision for income taxes (benefits)
$
(2,988 ) $
1 $
30
31
277
15
292
(8 )
315 $
(56 ) $
2
(54 )
103
18
121
(2 )
65 $
(132 )
(72 )
(204 )
214
(42 )
172
(10 )
(42 )
(222 )
(13 )
(235 )
25
(14 )
11
(4 )
(228 )
(1) Provision for Income Taxes (Benefits) on Income from Continuing Operations. Currently payable (receivable) in
2014 excludes $106 million and $12 million of federal and state taxes, respectively, associated with discontinued
operations. Deferred, net in 2014 excludes $44 million and $5 million of federal and state tax benefits, respectively,
associated with discontinued operations.
102
FirstEnergy and FES tax rates are affected by permanent items, such as AFUDC equity and other flow-through items as well as
discrete items that may occur in any given period, but are not consistent from period to period. The following tables provide a
reconciliation of federal income tax expense at the federal statutory rate to the total income taxes on continuing operations for the
three years ended December 31:
2016
2015
2014
(In millions)
FirstEnergy
Income (loss) from Continuing Operations before income taxes (benefits) $
(9,232 ) $
Federal income tax expense (benefit) at statutory rate (35%)
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit
AFUDC equity and other flow-through
Amortization of investment tax credits
Change in accounting method
ESOP dividend
Impairment of non-deductible goodwill
Tax basis balance sheet adjustments
Uncertain tax positions
Valuation allowances
Other, net
Total income taxes (benefits)
Effective income tax rate
FES
$
(3,231 ) $
(192 )
(13 )
(8 )
—
(6 )
157
—
(16 )
246
8
$
(3,055 ) $
33.1 %
Income (loss) from Continuing Operations before income taxes (benefits) $
(8,444 )
Federal income tax expense (benefit) at statutory rate (35%)
Increases (reductions) in taxes resulting from-
$
(2,955 )
$
$
State income taxes, net of federal tax benefit
Amortization of investment tax credits
ESOP dividend
Impairment of non-deductible goodwill
Uncertain tax positions
Valuation allowances
Other, net
Total income taxes (benefits)
Effective income tax rate
(188 )
(2 )
(1 )
9
(8 )
151
6
$
(2,988 ) $
35.4 %
893
313
$
$
17
(16 )
(8 )
(8 )
(6 )
—
—
1
18
4
315
35.3 %
$
147
51
$
$
2
(2 )
(1 )
—
5
14
(4 )
65
44.2 %
$
171
60
(21 )
(13 )
(10 )
(27 )
(6 )
—
(25 )
(35 )
33
2
(42 )
(24.6 )%
(588 )
(206 )
(28 )
(4 )
(1 )
—
—
14
(3 )
(228 )
38.8 %
In 2016, FirstEnergy’s effective tax rate was 33.1% compared to 35.3% in 2015. The change in the effective tax rate year-over-
year resulted from the impairment of $800 million of goodwill (as described in Note 2, Asset Impairments), of which $433 million is
non-deductible for tax purposes. Additionally, $168 million of valuation allowances were recorded against state and local NOL
carryforwards and $78 million of valuation allowances were recorded against state and local property deferred tax assets, that
management believes, more likely than not, will not be realized.
In 2016, FES’ effective tax rate on income from continuing operations was 35.4% compared to 44.2% in 2015. The change in the
effective tax rate primarily resulted from $73 million of valuation allowances recorded against state and local NOL carryforwards
and $78 million of valuation allowances recorded against state and local property deferred tax assets, that management believes,
more likely than not, will not be realized, as well as the impairment of $23 million of goodwill, which is non-deductible for tax
purposes.
103
Accumulated deferred income taxes as of December 31, 2016 and 2015 are as follows:
$
$
$
FirstEnergy
Property basis differences
Deferred sale and leaseback gain
Pension and OPEB
Nuclear decommissioning activities
Asset retirement obligations
Regulatory asset/liability
Deferred compensation
Loss carryforwards and AMT credits
Valuation reserve
All other
Net deferred income tax liability
FES
Property basis differences
Deferred sale and leaseback gain
Pension and OPEB
Lease market valuation liability
Nuclear decommissioning activities
Asset retirement obligations
Loss carryforwards and AMT credits
Valuation reserve
All other
Net deferred income tax liability (asset)
$
2016
2015
(In millions)
7,088 $
(351 )
(1,347 )
635
(669 )
545
(269 )
(2,251 )
438
(54 )
3,765 $
(1,009 ) $
(328 )
(366 )
111
540
(453 )
(830 )
197
(141 )
(2,279 ) $
9,920
(360 )
(1,541 )
480
(731 )
763
(239 )
(1,965 )
192
254
6,773
1,901
(342 )
(393 )
95
483
(509 )
(687 )
46
6
600
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. FirstEnergy's
tax returns for all state jurisdictions are open from 2012-2015. In February 2016, the IRS completed its examination of the 2014
federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy’s taxable income or
effective tax rate. Tax year 2015 is currently under review by the IRS.
FirstEnergy has recorded as deferred income tax assets the effect of NOLs and tax credits that will more likely than not be realized
through future operations and through the reversal of existing temporary differences. As of December 31, 2016, the deferred
income tax assets, before any valuation allowances, for loss carryforwards and AMT credits consisted of $1.8 billion of Federal
NOL carryforwards that will begin to expire in 2030, Federal AMT credits of $25 million that have an indefinite carryforward period,
and $407 million of state and local NOL carryforwards that will begin to expire in 2017.
FES has recorded as deferred income tax assets the effect of NOLs and tax credits that will more likely than not be realized
through future operations and through the reversal of existing temporary differences. As of December 31, 2016, the deferred
income tax assets, before any valuation allowances, for loss carryforwards consisted of $706 million of Federal NOL carryforwards
that will begin to expire in 2031 and $120 million of state and local NOL carryforwards that will begin to expire in 2017.
The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10.1 billion
($407 million after-tax) for FirstEnergy, of which approximately $2.1 billion ($87 million after-tax) is expected to be utilized based
on current estimates and assumptions. FES’ pre-tax NOL carryforwards for state and local income tax purposes is approximately
$3.4 billion ($120 million after-tax), of which none is expected to be utilized based on current estimates and assumptions. The
ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax
jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability
and the manner in which future taxable income is apportioned to various state and local tax jurisdictions.
104
Expiration Period
FirstEnergy
FES
2017-2021
2022-2026
2027-2031
2032-2036
(In millions)
State
Local
State
Local
$
$
166 $
1,327
2,817
2,752
7,062 $
2,998 $
—
—
—
2,998 $
2 $
—
410
1,172
1,584 $
1,795
—
—
—
1,795
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and
measurement attribute is utilized for financial statement recognition and measurement of tax positions taken or expected to be
taken on a company's tax return. As of December 31, 2016 and 2015, FirstEnergy's total unrecognized income tax benefits were
approximately $84 million and $34 million, respectively. If ultimately recognized in future years, approximately $50 million of
unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2016, it is reasonably possible that
approximately $51 million of unrecognized tax benefits may be resolved during 2017 as a result of the statute of limitations expiring
and expected resolution with respect to certain claims, of which approximately $26 million would affect FirstEnergy's effective tax
rate.
The following table summarizes the changes in unrecognized tax positions for the years ended 2016, 2015 and 2014:
Balance, January 1, 2014
Current year increases
Prior years increases
Prior years decreases
Balance, December 31, 2014
Current year increases
Prior years increases
Prior years decreases
Balance, December 31, 2015
Current year increases
Prior years increases
Prior years decreases
Balance, December 31, 2016
FirstEnergy
FES
$
$
$
$
(In millions)
48 $
4
5
(23 )
34 $
3
7
(10 )
34 $
2
69
(21 )
84 $
3
—
—
—
3
—
5
—
8
—
—
(8 )
—
FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes. That amount
is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount
previously taken or expected to be taken on the federal income tax return. FirstEnergy's recognition of net interest associated with
unrecognized tax benefits in 2016, 2015, and 2014 was not material. For the years ended December 31, 2016 and 2015, the
cumulative net interest payable recorded by FirstEnergy was not material.
105
General Taxes
General tax expense for 2016, 2015 and 2014, is summarized as follows:
FirstEnergy
KWH excise
State gross receipts
Real and personal property
Social security and unemployment
Other
Total general taxes
FES
State gross receipts
Real and personal property
Social security and unemployment
Other
Total general taxes
2016
2015
2014
(In millions)
$
$
$
$
196 $
212
472
127
35
1,042 $
28 $
42
15
3
88 $
193 $
224
410
119
32
978 $
44 $
36
16
2
98 $
194
226
393
112
37
962
69
39
17
3
128
106
7. LEASES
FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and
noncancelable leases.
In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on
the portions sold for basic lease terms of approximately 29 years, which expired in 2016 for Perry Unit 1 and will expire in 2017
for Beaver Valley Unit 2. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and
entered into similar operating leases for lease terms of approximately 30 years expiring in 2017. OE, CEI and TE had the right, at
the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the
facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The
basic rental payments are adjusted when applicable federal tax law changes.
In 2007, FG completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 and entered
into operating leases for basic lease terms of approximately 33 years, expiring in 2040. FES has unconditionally and irrevocably
guaranteed all of FG’s obligations under each of the leases.
On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in
Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Upon the
completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2. Therefore, upon the
expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100% of the unit's
output.
In November 2014, NG repurchased 55.3 MWs of lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for
approximately $87 million. On May 23, 2016, NG completed the purchase of the 3.75% lessor equity interests of the remaining
non-affiliated leasehold interest in Perry Unit 1 for $50 million. In addition, the Perry Unit 1 leases expired in accordance with their
terms on May 30, 2016, resulting in NG being the sole owner of Perry Unit 1 and entitled to100% of the unit's output.
Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE’s Perry Unit
1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV arrangements effectively reduce lease costs related to
those transactions (see "Note 9, Variable Interest Entities").
As of December 31, 2016, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was
93.83% of Bruce Mansfield Unit 1.
Operating lease expense for 2016, 2015 and 2014, is summarized as follows:
(In millions)
FirstEnergy
FES
2016
2015
2014
$
$
168 $
94 $
174 $
94 $
199
95
107
The future minimum capital lease payments as of December 31, 2016 are as follows:
Capital leases
FirstEnergy
FES
2017
2018
2019
2020
2021
Years thereafter
Total minimum lease payments
Interest portion
Present value of net minimum lease payments
Less current portion
Noncurrent portion
$
$
(In millions)
32 $
25
19
14
12
15
117
(13 )
104
29
75 $
6
2
—
—
—
1
9
(1 )
8
5
3
FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2016, are as follows:
Operating Leases
FirstEnergy
(In millions)
2017(1)
2018
2019
2020
2021
$
Years thereafter
Total minimum lease payments
$
125
142
123
97
119
1,351
1,957
(1) Includes a $3 million payment PNBV Trust will receive associated with certain
sale and leaseback transactions. These arrangements, which expire in 2017,
effectively reduce lease costs related to those transactions.
FES' future minimum operating lease payments as of December 31, 2016, are as follows:
Operating Leases
FES
(In millions)
2017
2018
2019
2020
2021
Years thereafter
Total minimum lease payments
$
$
82
101
97
68
93
1,222
1,663
108
8. INTANGIBLE ASSETS
As of December 31, 2016, intangible assets classified in Customer Intangibles and Other Deferred Charges on FirstEnergy’s
Consolidated Balance Sheet, include the following:
Intangible Assets
Actual
Amortization Expense
Estimated
(In millions)
NUG contracts(1)
OVEC(2)
Coal contracts(2)(3)(4)
FES customer contracts(5)
Gross
Accumulated
Amortization Net
2016
$
$
124 $
54
556
148
882 $
93 $
6
12
9
31 $
48
544
139
762 $ 120 $
2017 2018 2019 2020 2021 Thereafter
68
4
—
—
72
5 $
1
—
3
9 $
5 $
1
—
5
11 $
5 $
—
—
—
5 $
5 $
—
—
1
6 $
5 $
—
—
—
5 $
5 $
2
55
52
114 $
(1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
(2) Amortization expense excludes impairment charges related to intangible assets recognized in 2016, which totaled $92 million and are
included in Impairment of Assets. See "Note 2, Asset Impairments" for further discussion.
(3) The coal contracts were recorded with a regulatory offset and the amortization does not impact earnings. Accordingly, the amortization
expense for these coal contracts is excluded from table above.
(4) A gross amount of $40 million of coal contracts is related to FES. In June 2016, FES terminated a coal contract and the write-off is included
in amortization expense in the table above.
(5) During 2016, FES recorded a pre-tax charge of $37 million associated with the termination of a customer contract, which is included in
amortization expense in the table above.
FES acquired certain customer contract rights which were capitalized as intangible assets. These rights allow FES to supply
electric generation to customers, and the recorded value is being amortized ratably over the term of the related contracts.
9. VARIABLE INTEREST ENTITIES
FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies
FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if
it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly
impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant
to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a
VIE when it is determined that it is the primary beneficiary.
The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that
FirstEnergy consolidates, but does not own.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates
variable interests into categories based on similar risk characteristics and significance.
Consolidated VIEs
VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial
statements):
• PNBV Trust - PNBV, a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the
acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of
a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the
notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties.
• Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability
companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer
heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and
secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of
FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and
administers the phase-in recovery property including the billing, collection and remittance of usage-based charges
109
payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445
thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is
consolidated into its applicable utility. As of December 31, 2016 and December 31, 2015, $339 million and $362 million
of the phase-in recovery bonds were outstanding, respectively.
• JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of
JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In
August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated
with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included
as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole
obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s
equity and assets, which consist primarily of bondable transition property. As of December 31, 2016 and December 31,
2015, $85 million and $128 million of the transition bonds were outstanding, respectively.
• MP and PE Environmental Funding Companies - The entities issued bonds of which the proceeds were used to
construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to
collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's
and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by,
and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the
special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited
liability companies. As of December 31, 2016 and December 31, 2015, $406 million and $429 million of the environmental
control bonds were outstanding, respectively.
FES does not have any consolidated VIEs.
Unconsolidated VIEs
FirstEnergy is not the primary beneficiary of the following VIEs:
• Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in
the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not
the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint
venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. See "Note 1,
Organization, Basis of Presentation and Significant Accounting Policies - Investments", for additional information
regarding FEV's investment in Global Holding.
As discussed in "Note 16, Commitments, Guarantees and Contingencies", FE is the guarantor under Global Holding's
$300 million term loan facility. Failure by Global Holding to meet the terms and conditions under its term loan facility could
require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.
• PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM had
previously suspended in February 2011, is a series limited liability company that is comprised of multiple series, each of
which has separate rights, powers and duties regarding specified property and the series profits and losses associated
with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia
Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-
WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's
ownership interest in PATH-WV is subject to the equity method of accounting.
• Purchase Power Agreements - FirstEnergy evaluated its power purchase agreements and determined that certain NUG
entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all
of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of
production.
FirstEnergy maintains 14 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was
not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined
that for all but one of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be
considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope
exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily
to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated
110
Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a
variable interest were $108 million and $116 million, respectively, during the years ended December 31, 2016 and 2015.
• Sale and Leaseback Transactions - OE and FES have obligations that are not included on their Consolidated Balance
Sheets related to the Beaver Valley Unit 2 and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements,
respectively, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these
interests as it does not have control over the significant activities affecting the economics of the arrangements. As of
December 31, 2016, OE's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83%
of Bruce Mansfield Unit 1.
On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors'
interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to
NG. Upon the completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit
2. Therefore, upon the expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2
and entitled to 100% of the unit's output.
FES and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the
occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of
casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would
not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to
loss based upon the casualty value provisions as of December 31, 2016:
Maximum
Exposure
Discounted Lease
Payments, net
Net
Exposure
(In millions)
FirstEnergy
FES
$
$
1,123 $
1,098 $
879 $
875 $
244
223
111
10. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This
hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of
the fair value hierarchy and a description of the valuation techniques are as follows:
Level 1
- Quoted prices for identical instruments in active market
Level 2
- Quoted prices for similar instruments in active market
- Quoted prices for identical or similar instruments in markets that are not active
- Model-derived valuations for which all significant inputs are observable market data
Models are primarily industry-standard models that consider various assumptions, including quoted forward prices
for commodities, time value, volatility factors and current market and contractual prices for the underlying
instruments, as well as other relevant economic measures.
Level 3
- Valuation inputs are unobservable and significant to the fair value measurement
FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market
conditions change. When underlying prices are not observable, prices from the long-term price forecast, which
has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more
detailed description of FirstEnergy's valuation process for FTRs and NUGs follows:
FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly
day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the
annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost.
After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model
methodology, which approximates market. The primary inputs into the model, which are generally less observable
than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model
calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the
prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or
lower fair value measurement. See "Note 11, Derivative Instruments", for additional information regarding
FirstEnergy's FTRs.
NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain
obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using
a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are
regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for
the current year and the subsequent two years based on observable data and internal models using historical
trends and market data for the remaining years under contract. The internal models use forecasted energy
purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on
ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements
and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH.
Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value
measurement.
FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available.
Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no
changes in valuation methodologies used as of December 31, 2016, from those used as of December 31, 2015. The determination
of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty
credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms
of risk was not significant to the fair value measurements.
112
Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the
years ended December 31, 2016 and 2015. The following tables set forth the recurring assets and liabilities that are accounted for
at fair value by level within the fair value hierarchy:
FirstEnergy
Recurring Fair Value Measurements
December 31, 2016
December 31, 2015
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Corporate debt securities
$
Derivative assets - commodity contracts
Derivative assets - FTRs
Derivative assets - NUG contracts(1)
Equity securities(2)
Foreign government debt securities
U.S. government debt securities
U.S. state debt securities
Other(3)
Total assets
Liabilities
— $ 1,247 $
10
—
—
925
—
—
—
199
200
—
—
—
78
161
246
123
$ 1,134 $ 2,055 $
(In millions)
— $ 1,247 $
210
—
7
7
1
1
925
—
78
—
161
—
246
—
322
—
8 $ 3,197 $
— $ 1,245 $
224
4
—
—
—
—
—
576
75
—
180
—
246
—
212
105
685 $ 2,182 $
— $ 1,245
228
—
8
8
1
1
576
—
—
75
180
—
246
—
317
—
9 $ 2,876
Derivative liabilities - commodity contracts
$
Derivative liabilities - FTRs
Derivative liabilities - NUG contracts(1)
Total liabilities
$
(6 ) $
—
—
(6 ) $
(118 ) $
—
—
(118 ) $
— $
(6 )
(108 )
(114 ) $
(124 ) $
(6 )
(108 )
(238 ) $
(9 ) $
—
—
(9 ) $
(122 ) $
—
—
(122 ) $
— $
(13 )
(137 )
(150 ) $
(131 )
(13 )
(137 )
(281 )
Net assets (liabilities)(4)
$ 1,128 $ 1,937 $
(106 ) $ 2,959 $
676 $ 2,060 $
(141 ) $ 2,595
(1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
(2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred
Securities REIT index.
(3) Primarily consists of cash and short-term cash investments.
(4) Excludes $(3) million and $7 million as of December 31, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and
accrued income associated with financial instruments reflected within the fair value table.
113
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3
in the fair value hierarchy for the periods ended December 31, 2016 and December 31, 2015:
NUG Contracts(1)
FTRs
Derivative
Assets
Derivative
Liabilities
Net
Derivative
Assets
Derivative
Liabilities Net
(In millions)
January 1, 2015
Balance
Unrealized gain (loss)
Purchases
Settlements
December 31, 2015
Balance
Unrealized gain (loss)
Purchases
Settlements
December 31, 2016
Balance
$
$
2
2
—
(3 )
1
2
—
(2 )
$
(153 ) $
(151 ) $
39
$
(14 ) $
(49 )
—
65
(47 )
—
62
(5 )
22
(48 )
(7 )
(11 )
19
$
(137 ) $
(136 ) $
8
$
(13 ) $
(17 )
—
46
(15 )
—
44
(6 )
16
(11 )
(4 )
(7 )
18
25
(12 )
11
(29 )
(5 )
(10 )
9
7
$
1
$
(108 ) $
(107 ) $
7
$
(6 ) $
1
(1)
NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Level 3 Quantitative Information
The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value
hierarchy for the period ended December 31, 2016:
Fair Value, Net
(In millions)
Valuation
Technique
Significant Input
Range
Weighted
Average
FTRs
NUG Contracts
$
$
1 Model
(107 ) Model
RTO auction clearing prices
Generation
Regional electricity prices
($4.20) to $6.10
400 to 2,984,000
$32.60 to $33.40
$0.80
754,000
$32.80
Units
Dollars/MWH
MWH
Dollars/MWH
114
FES
Recurring Fair Value Measurements
December 31, 2016
December 31, 2015
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Corporate debt securities
$
Derivative assets - commodity contracts
Derivative assets - FTRs
Equity securities(1)
Foreign government debt securities
U.S. government debt securities
U.S. state debt securities
Other(2)
Total assets
Liabilities
— $
10
—
634
—
—
—
2
726 $
200
—
—
58
48
3
81
$
646 $ 1,116 $
(In millions)
726 $
— $
210
—
4
4
634
—
58
—
48
—
3
—
—
83
4 $ 1,766 $
678 $
— $
224
4
—
—
—
378
59
—
23
—
4
—
—
184
382 $ 1,172 $
678
— $
228
—
5
5
378
—
59
—
23
—
4
—
—
184
5 $ 1,559
Derivative liabilities - commodity contracts
$
Derivative liabilities - FTRs
Total liabilities
Net assets (liabilities)(3)
$
$
(6 ) $
—
(6 ) $
(118 ) $
—
(118 ) $
— $
(5 )
(5 ) $
(124 ) $
(5 )
(129 ) $
(9 ) $
—
(9 ) $
(122 ) $
—
(122 ) $
— $
(11 )
(11 ) $
(131 )
(11 )
(142 )
640 $
998 $
(1 ) $ 1,637 $
373 $ 1,050 $
(6 ) $ 1,417
(1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred
Securities REIT index.
(2) Primarily consists of short-term cash investments.
(3) Excludes $2 million and $1 million as of December 31, 2016 and December 31, 2015, respectively, of receivables, payables, taxes and
accrued income associated with financial instruments reflected within the fair value table.
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair
value hierarchy for the periods ended December 31, 2016 and December 31, 2015:
Derivative Asset Derivative Liability
Net Asset/(Liability)
(In millions)
(13 ) $
(5 )
(10 )
17
(11 ) $
(3 )
(5 )
14
(5 ) $
14
(3 )
(1 )
(16 )
(6 )
(7 )
5
7
(1 )
January 1, 2015 Balance
Unrealized gain (loss)
Purchases
Settlements
$
December 31, 2015 Balance
$
Unrealized loss
Purchases
Settlements
December 31, 2016 Balance
$
27 $
2
9
(33 )
5 $
(4 )
10
(7 )
4 $
115
Level 3 Quantitative Information
The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy
for the period ended December 31, 2016:
Fair Value, Net
(In millions)
Valuation
Technique
Significant Input
Range
Weighted
Average
Units
FTRs
$
(1 )
Model
RTO auction clearing prices
($4.20) to $5.30
$0.60 Dollars/MWH
INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the
Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash
equivalents include held-to-maturity securities and AFS securities.
At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are
evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent
and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which
the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an
investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be
required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost
basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair
value.
Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE
and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability
and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with
unrealized gains and losses offset against regulatory assets.
The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct
placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives,
securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.
AFS Securities
FirstEnergy holds debt and equity securities within its NDT and nuclear fuel disposal trusts. These trust investments are considered
AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of
investments held in NDT and nuclear fuel disposal trusts as of December 31, 2016 and December 31, 2015:
December 31, 2016(1)
December 31, 2015(2)
Cost
Basis
Unrealized
Gains
Fair Value
Cost
Basis
Unrealized
Gains
Fair Value
(In millions)
1,735 $
847
38 $
27
1,773 $
874
1,778 $
801
16 $
9
1,794
810
822 $
564
103 $
70
925 $
634
542 $
354
34 $
24
576
378
Debt securities
FirstEnergy
$
FES
Equity securities
$
FirstEnergy
FES
(1) Excludes short-term cash investments: FirstEnergy - $61 million; FES - $44 million.
(2) Excludes short-term cash investments: FirstEnergy - $157 million; FES - $139 million.
116
Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend
income for the three years ended December 31, 2016, 2015 and 2014 were as follows:
December 31, 2016
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
FirstEnergy
FES
December 31, 2015
FirstEnergy
FES
December 31, 2014
FirstEnergy
FES
$
$
$
(In millions)
1,678 $
717
170 $
117
(121 ) $
(69 )
(21 ) $
(19 )
100
56
Sale
Proceeds
Realized
Gains
Realized
Losses
(In millions)
OTTI
Interest and
Dividend Income
1,534 $
733
209 $
158
(191 ) $
(134 )
(102 ) $
(90 )
101
57
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
(In millions)
2,133 $
1,163
146 $
113
(75 ) $
(54 )
(37 ) $
(33 )
96
56
Held-To-Maturity Securities
Unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of
December 31, 2016 and December 31, 2015 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity
method investments totaling $266 million as of December 31, 2016 and $255 million as of December 31, 2015, are excluded from
the amounts reported above.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are
reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature,
FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value
and related carrying amounts of long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs,
premiums and discounts:
December 31, 2016
December 31, 2015
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
(In millions)
FirstEnergy
FES
$
19,885 $
3,000
19,829 $
1,555
20,244 $
3,027
21,519
3,121
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those
securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each
respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit
ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations
as Level 2 in the fair value hierarchy as of December 31, 2016 and December 31, 2015.
117
11. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for
electricity, natural gas, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy
Committee, comprised of senior management, provides general management oversight for risk management activities throughout
FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk
management programs and oversees compliance with corporate risk management policies and established risk management
practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts,
options, futures contracts and swaps.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal
purchases and normal sales criteria) as follows:
• Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to
AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects
earnings.
• Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as
an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item
being hedged is amortized into earnings.
• Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in
earnings on a mark-to-market basis, unless otherwise noted.
Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of
accounting with their effects included in earnings at the time of contract performance.
FirstEnergy has contractual derivative agreements through 2020.
Cash Flow Hedges
FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated
with fluctuating commodity prices and interest rates.
Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges
totaled $12 million and $11 million as of December 31, 2016 and December 31, 2015, respectively. Since the forecasted
transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments.
FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk
associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated
as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S.
Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included
in AOCI associated with prior interest rate cash flow hedges totaled $33 million (FES $3 million) and $42 million (FES $3 million)
as of December 31, 2016 and December 31, 2015, respectively. Based on current estimates, approximately $8 million of these
unamortized losses is expected to be amortized to interest expense during the next twelve months.
Refer to "Note 3, Accumulated Other Comprehensive Income", for reclassifications from AOCI during the years ended
December 31, 2016 and 2015.
As of December 31, 2016 and December 31, 2015, no commodity or interest rate derivatives were designated as cash flow
hedges.
Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk
associated with the debt portfolio of its subsidiaries. As of December 31, 2016 and December 31, 2015, no fixed-for-floating interest
rate swap agreements were outstanding.
118
Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $10
million and $20 million as of December 31, 2016 and December 31, 2015, respectively. During the next twelve months,
approximately $7 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized
gains included in long-term debt totaled approximately $10 million and $12 million during the years ended December 31, 2016 and
2015, respectively.
As of December 31, 2016 and December 31, 2015, no commodity or interest rate derivatives were designated as fair value hedges.
Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices.
Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so,
including circumstances where the hedging relationship does not qualify for hedge accounting.
Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are
entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative
instruments are not used in quantities greater than forecasted needs.
As of December 31, 2016, FirstEnergy's net asset position under commodity derivative contracts was $86 million, which related to
FES positions. Under these commodity derivative contracts, FES posted $52 million of collateral.
Based on commodity derivative contracts held as of December 31, 2016, an increase in commodity prices of 10% would decrease
net income by approximately $29 million during the next twelve months.
NUGs
As of December 31, 2016, FirstEnergy's net liability position under NUG contracts was $107 million representing contracts held at
JCP&L, ME and PN. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact
earnings.
FTRs
As of December 31, 2016, FirstEnergy's net asset associated with FTRs was $1 million and FES' net liability associated with FTRs
was $1 million, and FES posted $5 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of
future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority
of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that
have load serving obligations.
The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been
designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to
PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting
period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses
as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s Utilities are recorded as regulatory assets
or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in
earnings at the time of contract performance.
119
FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and
classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:
Derivative Assets
Derivative Liabilities
Fair Value
December 31,
2016
December 31,
2015
(In millions)
Fair Value
December 31,
2016
December 31,
2015
(In millions)
Current Assets -
Derivatives
Commodity Contracts $
FTRs
Deferred Charges and
Other Assets - Other
Commodity Contracts
FTRs
NUGs(1)
Derivative Assets
$
133 $
7
140
77
—
1
78
218 $
Current Liabilities -
Derivatives
150 Commodity Contracts
$
FTRs
7
157
Noncurrent Liabilities -
Adverse Power Contract
Liability
(72 ) $
(6 )
(78 )
(94 )
(12 )
(106 )
NUGs(1)
(108 )
(137 )
Noncurrent Liabilities -
Other
78
1 Commodity Contracts
1
80
237 Derivative Liabilities
FTRs
(52 )
—
(160 )
(238 ) $
(37 )
(1 )
(175 )
(281 )
$
(1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
FES records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and
classification of derivative instruments on FES' Consolidated Balance Sheets:
Derivative Assets
Derivative Liabilities
Fair Value
December 31,
2016
December 31,
2015
(In millions)
Fair Value
December 31,
2016
December 31,
2015
(In millions)
Current Assets -
Derivatives
Commodity Contracts $
FTRs
Deferred Charges and
Other Assets - Other
Commodity Contracts
FTRs
Derivative Assets
$
133 $
4
137
77
—
77
214 $
(72 ) $
(5 )
(77 )
(52 )
—
(52 )
(94 )
(10 )
(104 )
(37 )
(1 )
(38 )
(142 )
$
(129 ) $
Current Liabilities -
Derivatives
150 Commodity Contracts
$
FTRs
4
154
Noncurrent Liabilities -
Other
78
Commodity Contracts
1
FTRs
79
233 Derivative Liabilities
120
FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under
netting arrangements with the same counterparty. Certain of these contracts contain margining provisions that require the use of
collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to
mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the
collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative
and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on
FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position:
December 31, 2016
Fair Value
Amounts Not Offset in Consolidated
Balance Sheet
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
(In millions)
Derivative Assets
Commodity contracts
FTRs
NUG contracts
Derivative Liabilities
Commodity contracts
FTRs
NUG contracts
$
$
$
$
210 $
7
1
218 $
(124 ) $
(6 )
(108 )
(238 ) $
(117 ) $
(6 )
—
(123 ) $
117 $
6
—
123 $
— $
—
—
— $
1 $
—
—
1 $
93
1
1
95
(6 )
—
(108 )
(114 )
December 31, 2015
Fair Value
Amounts Not Offset in Consolidated
Balance Sheet
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
(In millions)
Derivative Assets
Commodity contracts
$
FTRs
NUG contracts
Derivative Liabilities
Commodity contracts
FTRs
NUG contracts
$
$
$
228 $
8
1
237 $
(131 ) $
(13 )
(137 )
(281 ) $
(125 ) $
(8 )
—
(133 ) $
125 $
8
—
133 $
— $
—
—
— $
3 $
5
—
8 $
103
—
1
104
(3 )
—
(137 )
(140 )
121
The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets
and the effect of netting arrangements and collateral on its financial position:
December 31, 2016
Fair Value
Amounts Not Offset in Consolidated
Balance Sheet
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
(In millions)
Derivative Assets
Commodity contracts
FTRs
Derivative Liabilities
Commodity contracts
FTRs
$
$
$
$
210 $
4
214 $
(124 ) $
(5 )
(129 ) $
(117 ) $
(4 )
(121 ) $
117 $
4
121 $
— $
—
— $
1 $
1
2 $
93
—
93
(6 )
—
(6 )
December 31, 2015
Fair Value
Amounts Not Offset in Consolidated
Balance Sheet
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
(In millions)
Derivative Assets
Commodity contracts
FTRs
Derivative Liabilities
Commodity contracts
FTRs
$
$
$
$
228 $
5
233 $
(131 ) $
(11 )
(142 ) $
(125 ) $
(5 )
(130 ) $
125 $
5
130 $
— $
—
— $
103
—
103
3 $
6
9 $
(3 )
—
(3 )
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of
December 31, 2016:
Power Contracts
FTRs
NUGs
Natural Gas
Purchases
Sales
Net
Units
18
28
3
29
(In millions)
47
—
—
29
(29 )
28
3
—
MWH
MWH
MWH
mmBTU
The following table summarizes the volumes associated with FES' outstanding derivative transactions as of December 31, 2016:
Power Contracts
FTRs
Natural Gas
Purchases
Sales
Net
Units
(In millions)
47
—
29
(29 )
22
—
MWH
MWH
mmBTU
18
22
29
122
The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income
(Loss) during 2016, 2015 and 2014 are summarized in the following tables:
2016
Unrealized Gain (Loss) Recognized in:
Other Operating Expense
Realized Gain (Loss) Reclassified to:
Revenues
Purchased Power Expense
Other Operating Expense
Fuel Expense
2015
Unrealized Gain (Loss) Recognized in:
Other Operating Expense
Realized Gain (Loss) Reclassified to:
Revenues
Purchased Power Expense
Other Operating Expense
Fuel Expense
Year Ended December 31
Commodity
Contracts
FTRs
Total
(In millions)
$
$
(14 ) $
5 $
(9 )
210 $
(131 )
—
(8 )
8 $
—
(35 )
—
218
(131 )
(35 )
(8 )
Year Ended December 31
Commodity
Contracts
FTRs
Total
(In millions)
$
$
93 $
(20 ) $
73
111 $
(130 )
—
(34 )
50 $
—
(49 )
—
161
(130 )
(49 )
(34 )
Commodity
Contracts
Year Ended December 31
Interest
FTRs
Rate Swaps Total
2014
Unrealized Gain (Loss) Recognized in:
Other Operating Expense
Realized Gain (Loss) Reclassified to:
Revenues
Purchased Power Expense
Other Operating Expense
Fuel Expense
Interest Expense
$
$
(In millions)
(86 ) $
22 $
— $
(64 )
(6 ) $
365
—
(6 )
—
68 $
—
(44 )
—
—
— $
—
—
—
14
62
365
(44 )
(6 )
14
123
The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss)
during 2016, 2015 and 2014 are summarized in the following tables:
2016
Unrealized Gain (Loss) Recognized in:
Other Operating Expense
Realized Gain (Loss) Reclassified to:
Revenues
Purchased Power Expense
Other Operating Expense
2015
Unrealized Gain (Loss) Recognized in:
Other Operating Expense
Realized Gain (Loss) Reclassified to:
Revenues
Purchased Power Expense
Other Operating Expense
2014
Unrealized Gain (Loss) Recognized in:
Other Operating Expense
Realized Gain (Loss) Reclassified to:
Revenues
Purchased Power Expense
Other Operating Expense
Year Ended December 31
Commodity
Contracts
FTRs
Total
(In millions)
$
$
(14 ) $
5 $
(9 )
210 $
(131 )
—
8 $
—
(35 )
218
(131 )
(35 )
Year Ended December 31
Commodity
Contracts
FTRs
Total
(In millions)
$
$
93 $
(19 ) $
74
111 $
(130 )
—
49 $
—
(49 )
160
(130 )
(49 )
Year Ended December 31
Commodity
Contracts
FTRs
Total
(In millions)
$
$
(86 ) $
21 $
(65 )
(6 ) $
365
—
67 $
—
(43 )
61
365
(43 )
124
The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory
accounting during 2016 and 2015. Changes in the value of these contracts are deferred for future recovery from (or credit to)
customers:
Derivatives Not in a Hedging Relationship with
Regulatory Offset
Outstanding net asset (liability) as of January 1, 2016
Unrealized loss
Purchases
Settlements
Outstanding net asset (liability) as of December 31, 2016
Outstanding net asset (liability) as of January 1, 2015
Unrealized loss
Purchases
Settlements
Outstanding net asset (liability) as of December 31, 2015
12. CAPITALIZATION
COMMON STOCK
Retained Earnings and Dividends
Year Ended December 31
Regulated
FTRs
Total
NUGs
(In millions)
$
$
$
$
(136 ) $
(15 )
—
44
(107 ) $
(151 ) $
(47 )
—
62
(136 ) $
1 $
(3 )
4
—
2 $
11 $
(9 )
12
(13 )
1 $
(135 )
(18 )
4
44
(105 )
(140 )
(56 )
12
49
(135 )
As of December 31, 2016, FirstEnergy had an accumulated deficit of $4.5 billion. Dividends declared in 2016 and 2015 were $1.44
per share, which included dividends of $0.36 per share paid in the first, second, third and fourth quarters. The amount and timing
of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions,
results of operations, financial condition and other factors. On January 19, 2017 the Board of Directors declared a quarterly
dividend of $0.36 per share to be paid from other paid-in-capital in the first quarter of 2017.
In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from the FERC
to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity to total capitalization ratio
remains above 35%. In addition, TrAIL and AGC have authorization from the FERC to pay cash dividends to their respective
parents from paid-in capital accounts, as long as their FERC-defined equity to total capitalization ratio remains above 45%. The
articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain
FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of
these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FirstEnergy as of December 31,
2016.
Stock Issuance
On December 13, 2016, FE contributed 16,097,875 newly issued shares of its common stock to its qualified pension plan in a
private placement transaction. These shares were valued at approximately $500 million in the aggregate, and were issued to
satisfy a portion of FirstEnergy’s future pension funding obligations. An independent fiduciary was retained to manage and liquidate
the stock over time at its discretion.
FE issued approximately 2.7 million shares of common stock in 2016 and 2.5 million shares of common stock in 2015 and 2014
to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan and certain
share-based benefit plans.
125
PREFERRED AND PREFERENCE STOCK
FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2016, as follows:
Preferred Stock
Preference Stock
Shares
Authorized
Par Value
Shares
Authorized
Par Value
8,000,000
no par
3,000,000
5,000,000 $
no par
25
FirstEnergy
OE
OE
Penn
CEI
TE
TE
JCP&L
ME
PN
MP
PE
WP
5,000,000 $
6,000,000 $
8,000,000 $
1,200,000 $
4,000,000
3,000,000 $
12,000,000 $
15,600,000
10,000,000
11,435,000
940,000 $
10,000,000 $
32,000,000
100
100
25
100
no par
100
25
no par
no par
no par
100
0.01
no par
As of December 31, 2016, and 2015, there were no preferred or preference shares outstanding.
126
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31,
2016 and 2015:
(Dollar amounts in millions)
Maturity Date
Interest Rate
2016
2015
As of December 31, 2016
As of December 31
FirstEnergy:
FMBs
Secured notes - fixed rate
Secured notes - variable rate
Total secured notes
Unsecured notes - fixed rate
Unsecured notes - variable rate
Total unsecured notes
Capital lease obligations
Unamortized debt discounts
Unamortized debt issuance costs
Unamortized fair value adjustments
Currently payable long-term debt
2017 - 2056
2017 - 2037
2017
3.340% - 9.740%
0.679% - 12.000%
3.500%
$
2017 - 2045
2021
2.150% - 7.700%
2.430%
Total long-term debt and other long-term obligations
$
FES:
Secured notes - fixed rate
Secured notes - variable rate
Total secured notes
Unsecured notes - fixed rate
Unsecured notes - variable rate
Total unsecured notes
Capital lease obligations
Unamortized debt discounts
Unamortized debt issuance costs
Currently payable long-term debt
2017 - 2022
2017
4.250% - 12.000% $
3.500%
2017 - 2039
2.150% - 6.800%
Total long-term debt and other long-term obligations
$
On May 1, 2016, JCP&L repaid $300 million of 5.625% senior unsecured notes at maturity.
3,328 $
2,295
10
2,305
13,058
1,200
14,258
104
(25 )
(87 )
(6 )
(1,685 )
18,192 $
617 $
10
627
2,373
—
2,373
8
(1 )
(15 )
(179 )
2,813 $
3,269
2,096
2
2,098
13,580
1,292
14,872
132
(18 )
(93 )
5
(1,166 )
19,099
340
2
342
2,593
92
2,685
13
(1 )
(17 )
(512 )
2,510
On June 1 and July 1 of 2016, NG repurchased approximately $225 million and $60 million, respectively of PCRBs, which were
subject to a mandatory put on such date. On August 15, 2016, NG remarketed the approximately $285 million of PCRBs secured
by FMBs with a fixed interest rate of 4.375% and mandatory put dates ranging from June 1, 2022 to July 1, 2022.
On July 11, 2016, Penn issued $50 million of 4.24% FMBs due 2056. Proceeds received from the issuance of the FMBs were
used: (i) to fund capital expenditures; (ii) for working capital needs and other general business purposes; and (iii) to repay
borrowings under the FirstEnergy regulated companies' money pool.
On August 15, 2016, WP repaid $145 million of 5.875% FMBs at maturity. Also, on September 23, 2016, WP agreed to sell $475
million of new 3.84% FMBs due 2046 ($100 million), 4.09% FMBs due 2047 ($100 million) and 4.14% FMBs due 2047 ($275
million). On December 15, 2016, WP issued the $100 million of 3.84% FMBs due 2046. The remaining sales are expected to settle
on September 15, 2017 and December 15, 2017, respectively. Proceeds to be received from the issuances of the FMBs were or
are, as the case may be, expected to be used: (i) for general corporate purposes; and (ii) to repay a portion of WP's $275 million
of 5.95% FMBs that mature on December 15, 2017.
127
On August 15, 2016, FG remarketed approximately $86 million of PCRBs secured by FMBs with fixed interest rates ranging from
4.25% to 4.50% and mandatory put dates ranging from May 1, 2021 to June 1, 2021.
On September 15, 2016, FG remarketed $100 million of PCRBs secured by FMBs with a fixed interest rate of 4.25% and a
mandatory put of September 15, 2021.
On September 15 and 30, 2016, respectively, FG retired an aggregate of $12 million of PCRBs with original maturity dates in 2018
and 2029.
On October 17, 2016, PE issued $155 million of 3.89% FMBs due 2046. Proceeds received from the issuance were used: (i) to
repay short-term borrowings incurred to repay PE's $100 million of 5.80% FMBs that matured on October 15, 2016; and (ii) for
general corporate purposes.
See "Note 7, Leases", for additional information related to capital leases.
Securitized Bonds
Environmental Control Bonds
The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote,
special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to
construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and
payable solely from, the proceeds of the environmental control charges. As of December 31, 2016 and 2015, $406 million and
$429 million of environmental control bonds were outstanding, respectively.
Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include transition bonds issued by JCP&L Transition Funding
and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. The proceeds were used to securitize the
recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station
and to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. As of December 31, 2016 and 2015, $85
million and $128 million of the transition bonds were outstanding, respectively.
Phase-In Recovery Bonds
In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates
supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and
purchased power regulatory assets. As of December 31, 2016 and 2015, $339 million and $362 million of the phase-in recovery
bonds were outstanding, respectively.
See "Note 9, Variable Interest Entities" for additional information on securitized bonds.
Other Long-term Debt
The Ohio Companies, Penn, FG and NG each have a first mortgage indenture under which they can issue FMBs secured by a
direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property.
Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2016, the sinking fund
requirement for all FMBs issued under the various mortgage indentures was zero.
In 2016, FG remarketed $86 million of fixed rate PCRBs and retired $12 million of variable interest rate PCRBs, which resulted in
the elimination of LOCs related to $92 million of variable interest rate PCRBs that are no longer outstanding.
128
The following table presents scheduled debt repayments for outstanding long-term debt, excluding capital leases, fair value
purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31,
2016. 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.
Year
2017
2018
2019
2020
2021
FirstEnergy
FES
$
(In millions)
1,641 $
1,702
2,266
1,231
832
163
516
478
667
774
Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. The following table classifies
these PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on
which the debt holders may exercise their right to tender their PCRBs.
Year
FirstEnergy
FES
$
2017
2018
2019
2020
2021
(In millions)
130 $
375
232
490
342
130
375
232
490
342
Obligations to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are entitled to the benefit of irrevocable
bank LOCs, to pay principal of, or interest on, the applicable PCRBs. To the extent that drawings are made under the LOCs, FG
is entitled to a credit against its obligation to repay those bonds. FG pays annual fees based on the amounts of the LOCs to the
issuing bank and is obligated to reimburse the bank for any drawings thereunder.
Debt Covenant Default Provisions
FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities. The most
restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain
financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an
event of default, which may have an adverse effect on its financial condition. As of December 31, 2016, FirstEnergy and FES
remain in compliance with all debt covenant provisions.
Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a
default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries, excluding FES and AES, default
under another financing arrangement in excess of a certain principal amount, typically $100 million. Although such defaults by any
of the Utilities, ATSI or TrAIL would generally cross-default FE financing arrangements containing these provisions, defaults by
any of AE Supply, FES, FG or NG would generally not cross-default to applicable financing arrangements of FE. Also, defaults by
FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are
not typically found in any of the senior notes or FMBs of FE, FG, NG or the Utilities.
13. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
On December 6, 2016, FE and certain subsidiaries entered into new five-year syndicated credit facilities available through
December 6, 2021, and concurrently terminated existing syndicated credit facilities that were to expire March 31, 2019, as follows:
• FE and the Utilities entered into a new $4 billion revolving credit facility, which represents an increase of $500 million over
the existing $3.5 billion facility it replaced,
• FET and its subsidiaries entered into a $1 billion revolving credit facility, which replaced their existing $1 billion facility,
and FES and AE Supply terminated their unsecured $1.5 billion credit facility (commitments of $900 million and $600
129
million for FES and AE Supply, respectively) and FES entered into a new, two-year secured credit facility with FE in
which FE provided a committed line of credit to FES of up to $500 million and additional credit support of up to $200
million to cover a $169 million surety bond for the benefit of the PA DEP with respect to LBR, and other bonds as
designated in writing to FE. In connection with the cancellation of the prior FES/AE Supply facility and entry into the
new FES secured facility with FE, certain commitments and amendments associated with shared services and
operational matters were made including, without limitation, as follows: (i) FE reaffirmed its obligations under the
Intercompany Tax Allocation Agreement, and (ii) amendments to the Service Agreement by and among FESC, FES, FG
and NG, to prevent termination until the earlier of December 31, 2018, or a change in control of FES or its subsidiaries.
FE, the Utilities and FET and its subsidiaries may use borrowings under their new facilities for working capital and other general
corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. FES expects to use its
new facility with FE to conduct its ordinary course of business in lieu of borrowing under the unregulated money pool. The new
facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million).
Under the terms of the new FE and FET credit facilities, each borrower is required to maintain a consolidated debt to total
capitalization ratio, as defined, of no more than 0.65 to 1.00, or in the case of FET, 0.75 to 1.00. For purposes of calculating its
ratio, FE is permitted certain adjustments to total capitalization including (i) an exclusion for certain previously incurred after-tax,
non-cash write-downs and non-cash charges of approximately $2.75 billion and (ii) a new exclusion for additional after-tax, non-
cash write-downs and 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. Additionally, under the new credit facility, FE is now also required to
maintain a minimum interest coverage ratio of 1.75 to 1.00 until December 31, 2017, 2.00 to 1.00 beginning January 1, 2018 until
December 31, 2018, 2.25 to 1.00 beginning January 1, 2019 until December 31, 2019, and 2.50 to 1.00 beginning January 1, 2020
until December 31, 2021. FE and each of the other borrowers under the new FE and FET credit facilities are currently in compliance
with these financial covenants. In the case of FE, the impairment charges recognized in the fourth quarter of 2016 described under
Note 2, Asset Impairments, are excluded from FE's calculation of total capitalization pursuant to the new $5.5 billion after-tax
exclusion referenced in (ii) above consistent with the terms of the facility. Other terms of the new FE credit facility exclude FES
and AE Supply from the definition of “significant subsidiaries,” which removes them from FE’s covenants and defaults resulting
from adverse judgments in excess of $100 million and eliminates lender approvals previously required for FES and AE Supply
asset sales.
Outstanding alternate base rate advances under the new FE and FET facilities will bear interest at a fluctuating interest rate per
annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to the applicable
borrower’s then-current senior unsecured non-credit enhanced debt ratings (reference ratings) plus the highest of (i) the “prime
rate” published by the Wall Street Journal from time to time, (ii) the sum of 1/2 of 1% per annum plus the federal funds rate in effect
from time to time and (iii) the LIBOR for a one-month interest period plus 1%. Outstanding Eurodollar rate advances will bear
interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by
reference to the applicable borrower’s reference ratings. Swing line loans under the new FE facility will bear interest at a rate per
annum equal to the sum of the alternate base rate plus an applicable margin determined by reference to the applicable borrower’s
reference ratings. Changes in reference ratings of a borrower would lower or raise its applicable margin depending on whether
ratings improved or were lowered, respectively.
FirstEnergy had $2,675 million and $1,708 million of short-term borrowings as of December 31, 2016 and 2015, respectively.
FirstEnergy’s available liquidity from external sources as of January 31, 2017 was as follows:
Borrower(s)
FirstEnergy(1)
FET(2)
Type
Maturity
Commitment
Available
Liquidity
Revolving
Revolving
December 2021 $
December 2021
Subtotal $
Cash
Total $
(In millions)
4,000 $
1,000
5,000 $
—
5,000 $
1,341
1,000
2,341
308
2,649
(1) FE and the Utilities.
(2)
Includes FET, ATSI and TrAIL.
130
FES had $101 million (payable to AE Supply) and $8 million of short-term borrowings as of December 31, 2016 and 2015,
respectively. FES' available liquidity as of January 31, 2017 was as follows:
Type
Commitment
Available
Liquidity
Two-year secured credit facility with FE
$
Cash
$
(In millions)
$
500
—
500 $
500
2
502
The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term
indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations,
as of December 31, 2016:
Borrower
FE
FET
OE
CEI
TE
JCP&L
ME
PN
WP
MP
PE
ATSI
Penn
TrAIL
MAIT
Revolving
Credit Facility
Sub-Limits
Regulatory and
Other Short-Term
Debt Limitations
(In millions)
$
4,000
1,000
500
500
500
600
300
300
200
500
150
500
50
400
400
$
— (1)
— (1)
500 (2)
500 (2)
500 (2)
500 (2)
500 (2)
300 (2)
200 (2)
500 (2)
150 (2)
500 (2)
100 (2)
400 (2)
400 (2)(3)
(1) No limitations.
(2) Excluding amounts which may be borrowed under the regulated companies' money pool.
(3) Pending regulatory approval, as discussed under "FERC Matters" below.
The facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event
of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the
facilities is related to the credit ratings of the company borrowing the funds, other than the FET facility, which is based on its
subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions
for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of December 31, 2016, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants as well
as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective facilities. In
the case of FE, the impairment charges recognized in the fourth quarter of 2016 disclosed in "Note 2. Asset Impairments" above
are excluded from FE's calculation of total capitalization pursuant to the new exclusion referenced in (ii) above consistent with the
terms of the facility.
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Term Loans
On December 6, 2016, FE terminated its existing $1 billion and $200 million term loan credit agreements and entered into a new
$1.2 billion five-year syndicated term loan credit agreement. The term loan contains covenants and other terms and conditions
substantially similar to those of the FE revolving credit facility described above, including a consolidated debt to total capitalization
ratio and minimum interest coverage ratio requirement.
The initial borrowing under the new $1.2 billion FE term loan, which took the form of a Eurodollar rate advance, may be converted
from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate
base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate
base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-
announced “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the
rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal
to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods
of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes
in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered,
respectively.
On February 16, 2017, FE entered into two separate $125 million three-year term loan credit agreements with Bank of America,
N.A. and The Bank of Nova Scotia, respectively, the proceeds of which were used to reduce short-term debt. The terms and
conditions of these new credit agreements are substantially similar to the December 6, 2016, $1.2 billion five-year syndicated term
loan credit agreement.
As of December 31, 2016, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants as
well as the interest coverage ratio requirement, as defined under its term loan.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding company to
meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated
companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and
unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool
agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds.
The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in 2016 was 0.69% per annum for the regulated
companies’ money pool and 2.02% per annum for the unregulated companies’ money pool.
As discussed above, FES expects to use its new $500 million secured credit facility with FE in lieu of borrowing under the
unregulated companies' money pool. In addition, a separate money pool for use by FES, its subsidiaries and FENOC is expected
to be established in the first quarter of 2017 at which time those companies will no longer have access to the unregulated
companies' money pool. As of January 31, 2017, FES, its subsidiaries and FENOC had no borrowings in the aggregate under the
unregulated companies' money pool.
Weighted Average Interest Rates
The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money
Pools, as of December 31, 2016 and 2015, were as follows:
FirstEnergy
2.47 %
2.16 %
2016
2015
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14. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant
decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground
storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized
conditional retirement obligations, primarily for asbestos remediation.
The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating
facilities, which total $713 million, as of December 31, 2016. FES uses an expected cash flow approach to measure the fair value
of their nuclear decommissioning AROs.
FirstEnergy and FES maintain NDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair
values of the decommissioning trust assets as of December 31, 2016 and 2015 were as follows:
FirstEnergy
FES
$
$
2016
2015
(In millions)
2,514 $
1,552 $
2,282
1,327
The following table summarizes the changes to the ARO balances during 2016 and 2015:
ARO Reconciliation
FirstEnergy
FES
Balance, January 1, 2015
Liabilities settled
Accretion
Revisions in estimated cash flows
Balance, December 31, 2015
Liabilities settled
Accretion
Liabilities Incurred
Balance, December 31, 2016
$
$
$
(In millions)
1,387 $
(13 )
92
(56 )
1,410 $
(27 )
95
4
1,482 $
841
(8 )
55
(57 )
831
(18 )
56
32
901
During 2016, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from
an owner participant in Perry Unit 1, OE transferred the ARO (included within the FES liabilities incurred above) and related NDT
assets associated with the leasehold interest to NG with the difference of $28 million credited to the common stock of FES. As of
June 30, 2016, NG owns 100% of Perry Unit 1.
During 2015, FE and FES reduced its ARO by $57 million based on the results of decommissioning cost studies for the Davis-
Besse and Perry nuclear generating stations.
Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic
Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal
requirements pending the EPA's evaluation of the need for future regulation.
In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards
regarding 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of
spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected,
any 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.
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15. REGULATORY MATTERS
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, Illinois, Michigan, New Jersey and
Maryland, 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.
MARYLAND
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. PE's current plan, covering the three-year period 2015-
2017, was approved by the MDPSC on December 23, 2014. 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 set in PE's plan for 2016, and increasing
0.2% per year thereafter to reach 2%. The costs of the 2015-2017 plan are expected to be approximately $70 million, of which
$43 million was incurred through December 31, 2016. PE continues to recover 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 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 yet 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. Initial comments in the proceeding were
filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 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.
NEW JERSEY
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
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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.
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 include
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 (Generic CTA proceeding), 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 New Jersey Superior Court and JCP&L filed to
participate as a respondent in that proceeding. Briefing has been completed. The oral argument was held on October 25, 2016.
On April 28, 2016, JCP&L filed tariffs with the NJBPU proposing a general rate increase associated with its distribution operations
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. The filing requested approval to increase
annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30,
2016. On November 30, 2016, JCP&L submitted to the ALJ a Stipulation of Settlement achieved with all the intervening parties
providing for an annual $80 million distribution revenue increase, effective January 1, 2017. The ALJ filed an Initial Decision
concluding that the Stipulation of Settlement should be approved, and the NJBPU approved the Stipulation of Settlement on
December 12, 2016. As part of the Stipulation of Settlement the intervening parties agreed that JCP&L can accelerate the
amortization of the 2012 major storm expenses (approximately $19 million annually) that are recovered through the SRC to achieve
full recovery by December 31, 2019. On November 23, 2016, JCP&L filed an Amendment to its January 15, 2016 SRC Filing with
the NJBPU, requesting that JCP&L be able to accelerate the amortization of the 2012 major storm expenses as agreed to in the
Stipulation of Settlement, and a Stipulation of Settlement with NJBPU Staff and the Division of Rate Counsel regarding the SRC
Filing was filed on December 27, 2016. The NJBPU approved this Stipulation of Settlement at the January 25, 2017 public meeting.
OHIO
The Ohio Companies currently operate under an ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material
terms of ESP IV, as approved in the PUCO’s Opinions and Orders issued on March 31, 2016 and 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. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually.
Revenues from the 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 approximately $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 the collection of lost distribution revenues associated with energy efficiency and peak demand
reduction programs, an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing
was made on February 29, 2016), a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045, and
contributions, totaling $51 million, to fund energy conservation programs, economic development and job retention in the Ohio
Companies’ service territory, and a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers,
and to establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.
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On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications for rehearing on the Ohio
Companies’ ESP IV with the PUCO. On September 6, 2016, while the applications for rehearing were still pending before the
PUCO, the OCC and NOAC filed a notice of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner
Entries on the parties’ applications for rehearing. On September 16, 2016, the Ohio Companies intervened and filed a motion to
dismiss the appeal. The PUCO resolved such applications for rehearing in the October 12, 2016 Opinion and Order. The OCC and
NOAC appeal remains pending before the Ohio Supreme Court.
On November 10, 2016 and November 14, 2016, several parties, including the Ohio Companies, filed additional applications for
rehearing on 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 December 7, 2016, the PUCO granted the applications for rehearing for further consideration of the matters
specified in the applications for rehearing. The matter remains pending before the PUCO. For additional information, see “FERC
Matters - Ohio ESP IV PPA,” below.
Under ORC 4928.66, the Ohio Companies were required to implement energy efficiency programs that achieved a total annual
energy savings of 1,990 GWHs and total peak demand reduction of 486 MWs in 2015. On May 12, 2016, the Ohio Companies
filed their Energy Efficiency and Peak Demand Reduction Program Status Report indicating compliance with their 2015 statutory
benchmarks. In 2016, the Ohio Companies estimated the annual energy savings target and peak demand reduction target will be
comparable to the 2015 targets due to the energy efficiency requirements under SB310, which amended ORC 4928.66 to freeze
the energy efficiency and peak demand reduction benchmarks for 2015 and 2016. 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.
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. The hearings were held in January 2017.
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 2015 and 2016 that remain at the 2014
level. 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. On February 18, 2014, the OCC
and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of
Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument.
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. The matter remains pending before the PUCO.
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PENNSYLVANIA
The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive
procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that
fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-
term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-
month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn.
Following the expiration of the current DSPs, the Pennsylvania Companies will operate under new 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 new
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. In addition, the new DSPs include modifications to the Pennsylvania Companies’
existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated
with alternative EGS charges.
Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency
and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans were effective through May 31, 2016.
Total Phase II costs of these plans were $174 million and are recoverable through the Pennsylvania Companies' reconcilable
EE&C riders. 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 October 19, 2015, each of the Pennsylvania
Companies filed LTIIPs with the PPUC for infrastructure improvement over the five-year period of 2016 to 2020 for the following
costs: WP- $88.34 million; PN- $56.74 million; Penn- $56.35 million; and ME- $43.44 million. On February 11, 2016, the PPUC
approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC
approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. On June 9, 2016, the PPUC
approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation
among customers. The four proceedings were consolidated by the ALJ. On January 19, 2017, in the PPUC’s order approving the
Pennsylvania Companies’ general rate cases, discussed below, the PPUC referred the issue of whether ADIT should be included
in DSIC calculations to the consolidated DSIC proceeding. On February 2, 2017, the parties to the consolidated DSIC proceeding
submitted a Joint Settlement to the ALJ to resolve issues referred to by the ALJ in its June 9, 2016 Order, subject to PPUC approval,
and would not result in any refund or reallocation among customers. The ADIT issue will be considered separately from the issues
resolved in the Joint Settlement Petition of February 2, 2017, and is the sole issue to be litigated in the consolidated DSIC
proceeding through a procedural schedule to be determined by the ALJ.
On April 28, 2016, each of the Pennsylvania Companies filed tariffs with the PPUC proposing general rate increases associated
with their distribution operations to benefit customers by modernizing the grid with smart technologies, increasing vegetation
management activities, and continuing other customer service enhancements. The filings requested approval to increase annual
operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP,
based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania
Companies. As a result of the enactment of Act 40 of 2016 that terminated the practice of making a CTA when calculating a utility’s
federal income taxes for ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7, 2016,
that quantified the value of the elimination of the CTA and outlined their plan for investing 50 percent of that amount in rate base
eligible equipment as required by the new law. Formal settlement agreements for each of the Pennsylvania Companies were filed
on October 14, 2016, which proposed increases in annual operating revenues of approximately $96 million at ME, $100 million at
PN, $29 million at Penn, and $66 million at WP. One item related to the calculation of DSIC rates was reserved for briefing, with
briefs filed by two parties. On November 21, 2016, the ALJ issued a Recommended Decision recommending approval of the
settlement agreements and dismissal of the one issue reserved for briefing. Exceptions to that Recommended Decision were filed
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by one party on December 1, 2016, and reply exceptions were filed by the Pennsylvania Companies on December 8, 2016. On
January 19, 2017, the PPUC issued an order approving the settlements and referring the reserved issue to the Pennsylvania
Companies’ consolidated DSIC proceeding. On February 3, 2017, one party filed a Petition for Reconsideration or Clarification
relating to the limited issue of the scope of the record to be transferred to the DSIC proceeding, discussed above. The outcome of
this request will not affect the new rates which took effect on January 27, 2017.
WEST VIRGINIA
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 March 31, 2016, MP and PE filed with the WVPSC seeking approval of their Phase II energy efficiency program including three
MP and PE energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of 0.5% of 2013
distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC
in the 2012 proceeding approving the transfer of ownership of the 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. A unanimous settlement was reached by the parties on all issues and presented to the WVPSC on
August 18, 2016. An order approving the settlement in full without modification was issued by the WVPSC on September 23,
2016. The Phase II program began initial implementation in November 2016.
The Staff of the WVPSC and the Consumer Advocate Division filed a Show Cause petition on August 5, 2016, requesting that the
WVPSC order MP and PE to file and implement RFPs for all future capacity and energy requirements above 100 MWs and that
they comply with an RFP settlement provision from the Harrison power station acquisition. MP and PE filed a timely response to
the petition arguing for dismissal on September 7, 2016. On October 17, 2016, the WVPSC denied the petition filed by the Staff
of the WVPSC and the Consumer Advocate Division and dismissed the case.
On August 16, 2016, MP and PE filed their annual ENEC case proposing an annual increase in rates of approximately $65 million
effective January 1, 2017, which is a 4.7% increase over existing rates. The increase is comprised of a $119 million under-
recovered balance as of June 30, 2016, and a projected $54 million over-recovery for the 2017 rate effective period. The parties
reached a unanimous settlement providing for a $25 million increase beginning January 1, 2017 and keeping ENEC rates at the
same level for a two year period. The settlement was presented to the WVPSC at a hearing on November 9, 2016. On December
9, 2016, the WVPSC approved the settlement as submitted.
On August 22, 2016, MP and PE filed an application for approval of a modernization and improvement plan for coal-fired boilers
at electric power plants and cost-recovery surcharge proposing an approximate $6.9 million annual increase in rates to be effective
May 1, 2017, which is a 0.5% increase over existing rates. The filing is in response to recent legislation by the West Virginia
Legislature permitting accelerated recovery of costs related to modernizing and improving coal-fired boilers, including costs related
to meeting environmental requirements and reducing emissions. The filing was supplemented on September 28, 2016, to add two
additional projects, resulting in an approximate $7.4 million annual increase in rates. The Staff of the WVPSC filed a motion to
dismiss the case arguing the new statute was not meant to recover these types of projects, but the WVPSC set the case for
hearing for February 21-23, 2017. As part of the annual ENEC settlement described above, the parties agreed that MP and PE
will increase ENEC rates to provide for a return of and on MATS/CSPR capital costs incurred during 2016-2017. Accordingly, MP
and PE withdrew this case as part of the ENEC approval.
On December 30, 2015, MP 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 finding that IRPs are informational and that it
must not approve or disapprove the IRP. MP issued a RFP to address its generation shortfall identified in the IRP on December
16, 2016 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. MP expects to execute definitive agreements with selected respondent(s) and file the appropriate
applications with the WVPSC and FERC by March 15, 2017.
RELIABILITY MATTERS
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 its subsidiaries, AE Supply, FENOC, ATSI and TrAIL. NERC is the
ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day
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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.
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.
On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review
the ESP IV PPA under Section 205 of the FPA. On April 27, 2016, FERC issued an order granting the complaint, prohibiting any
transactions under the ESP IV PPA pending authorization by FERC, and directing FES to submit the ESP IV PPA for FERC review
if the parties desired to transact under the agreement. FES and the Ohio Companies did not file the ESP IV PPA for FERC review
but rather agreed to suspend the ESP IV PPA. FES and the Ohio Companies subsequently advised FERC of this course of action.
On January 19, 2017, FERC issued an order accepting compliance filings by FES, its subsidiaries, and the Ohio Companies
updating their respective market-based rate tariffs to clarify that affiliate sales restrictions under the tariffs apply to the ESP IV PPA,
and also that the ESP IV PPA does not affect certain other waivers of its affiliate restrictions rules FERC previously granted these
entities.
On May 2, 2016, the Ohio Companies filed an Application for Rehearing with the PUCO that included a modified Rider RRS
proposal that did not involve a FERC-jurisdictional PPA. Several parties subsequently filed protests and comments with FERC
alleging, among other things, that the modified Rider RRS constituted a "virtual PPA". FERC rejected these protests in its January
19, 2017 order accepting the updated market-based rate tariffs of FES, its subsidiaries, and the Ohio Companies discussed below.
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. 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
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“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. The PJM TOs responded to the protesting parties' various pleadings and motions. 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
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, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be
disputed. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC
and certain United States 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. On July 15, 2016, the MISO TOs filed an appeal of FERC's orders with the Sixth
Circuit. On November 16, 2016, the Sixth Circuit granted FirstEnergy's intervention on behalf of ATSI, the Ohio Companies, and
PP, and a procedural schedule has been established. 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 costs for the "Michigan Thumb" transmission
project and "legacy RTEP" transmission projects cannot be predicted at this time.
Transfer of Transmission Assets to MAIT
On June 10, 2015, MAIT, a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the
purposes of owning and operating all FERC-jurisdictional transmission assets of JCP&L, ME and PN following the receipt of all
necessary state and federal regulatory approvals. In February and August 2016, respectively, FERC and the PPUC granted the
authorization for PN and ME to contribute their transmission assets to MAIT at book value, together with the approval of related
intercompany agreements, including MAIT’s participation in FirstEnergy’s regulated companies' money pool. FirstEnergy
subsequently withdrew its request for authorization before the NJBPU to also transfer JCP&L's transmission assets to MAIT.
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On October 28, 2016, MAIT and PJM submitted joint applications to FERC requesting authorization for (i) PJM to update its Tariff
and other agreements to reflect the withdrawal of ME and PN as TOs, and (ii) MAIT to become a participating PJM TO. FERC
approval would authorize MAIT to be a PJM TO, and would permit PJM to implement MAIT’s formula rate on MAIT’s behalf. On
January 26, 2017, FERC issued an order granting the requested authorization and MAIT now owns and operates the transmission
assets of ME and PN. On January 31, 2017, MAIT issued membership interests to FET, PN and ME in exchange for their respective
cash and asset contributions.
On October 14 and 28, 2016, MAIT submitted applications to FERC requesting authorization to issue equity, short-term debt, and
long-term debt. On December 8, 2016, FERC issued an order authorizing the application to issue equity as requested. MAIT is
expected to issue short-term debt and participate in the FirstEnergy regulated companies' money pool for working capital, to fund
day-to-day operations, and for other general corporate purposes. Over the long-term, MAIT is expected to issue long-term debt to
support capital investment and to establish an actual capital structure for ratemaking purposes. On February 3, 2017, MAIT
amended its debt authorization application to provide additional information regarding recovery of its investment and debt costs.
MAIT requested an order from FERC on the debt authorization by February 28, 2017. FERC’s order remains pending.
MAIT Transmission Formula Rate
On October 28, 2016, 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 January 1, 2017. On November 30, 2016, 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. MAIT filed a response to the protests on December 12, 2016. On
December 28, 2016, FERC Staff issued a deficiency letter with respect to the PJM-related application, which also requested
additional information regarding MAIT’s proposed formula rate. As a result of the deficiency letter, FERC’s order on the formula
rate remains pending. MAIT responded to FERC Staff’s request on January 10, 2017, and requested that FERC issue an order
approving the formula rate immediately after consummation of the transaction, which occurred on January 31, 2017. On February
15, 2017, MAIT filed a further answer to certain protesting parties' comments on its January 10th deficiency letter response.
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. On November 18, 2016, 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 December 5, 2016, JCP&L filed a
response to the protest. On December 28, 2016, FERC Staff issued a deficiency letter requesting additional information regarding
JCP&L’s proposed transmission rate. As a result of the deficiency letter, FERC’s order on the rate remains pending. JCP&L
responded to FERC Staff’s request on January 10, 2017, and requested that FERC issue an order approving the formula rate
effective January 1, 2017. On February 15, 2017, JCP&L filed a further answer to certain protesting parties' comments on its
January 10th deficiency letter response.
Competitive Generation Asset Sale
On February 17, 2017, AE Supply and AGC submitted filings with FERC for authorization to sell four natural gas generating plants
and an undivided ownership interest in Bath County to Aspen for approximately $925 million, in an all cash transaction. The four
natural gas plants are: Springdale Generating Facility (638 MWs), Chambersburg Generating Facility (88 MWs), Gans Generating
Facility (88 MWs), and Hunlock Creek (45 MWs). The 713 MW ownership interest in Bath County represents AE Supply’s indirect
ownership interest in the power station. The FERC applications include a request for authorization to transfer the hydroelectric
license under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the
hydroelectric projects under Part II of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected
FERC-jurisdictional rates and implementing the transaction once regulatory approval is obtained. The VSCC also must approve
the sale of the Bath County Hydro interest. The parties expect to close the transaction in the third quarter of 2017, subject to
satisfaction of various customary and other closing conditions, including without limitation, receipt of regulatory approvals and third
party consents. See "Note 22. Subsequent Events" below for additional information regarding the transaction.
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California Claims Litigation
Since 2002, AE Supply has been involved in litigation and claims based on its power sales to the California Energy Resource
Scheduling division of the CDWR during 2001-2003. This litigation and claims are related to litigation and claims advanced by the
California Attorney General and certain California utilities regarding alleged market manipulation of the wholesale energy markets
in California during the 2000-2001 period. AE Supply negotiated a settlement with the California Attorney General and the California
utilities and, on August 24, 2016, filed the settlement agreement for FERC approval. The settlement calls for AE Supply to pay,
without admission of any liability, $3.6 million in settlement in principle of all remaining claims that are based on AE Supply’s power
sales in the western energy markets during the 2001-2003 time period. On October 27, 2016 FERC approved this settlement, and
AE Supply paid the settlement shortly thereafter.
PATH Transmission Project
On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia
through Virginia and into Maryland which PJM had previously suspended in February 2011. 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 settlement
proceedings and a hearing if the parties could not agree to a settlement. On March 24, 2014, the FERC Chief ALJ terminated
settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional
pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531,
discussed below, to the PATH proceeding. On September 14, 2015, the ALJ issued his initial decision, disallowing recovery of
certain costs. On January 19, 2017, FERC issued an order accepting the initial decision in part and denying it in part. Relying on
its revised ROE methodology described in FERC Opinion No. 531, FERC reduced the PATH formula rate ROE from 10.4% to
8.11% effective January 19, 2017. Additionally, FERC allowed recovery of costs related to land acquisitions and dispositions and
legal expenses, but disallowed certain costs related to advertising and outreach. PATH filed a request for rehearing with FERC on
February 20, 2017, seeking recovery of the advertising and outreach costs and requesting that the ROE be reset to 10.4%.
Market-Based Rate Authority, Triennial Update
The Utilities, AE Supply, FES and its subsidiaries, Buchanan Generation, LLC, and Green Valley Hydro, LLC 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 the 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. The filings remain pending before FERC.
16. COMMITMENTS, GUARANTEES AND CONTINGENCIES
NUCLEAR INSURANCE
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.3 billion
(assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting
to $375 million; and (ii) $13 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 maximum potential assessment under
these provisions would be $509 million (NG-$506 million) per incident but not more than $76 million (NG-$75 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 annually, corresponding to their
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respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.40 billion (NG-$1.39 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
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.
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of
business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing
the value of the transaction to the third party.
As of December 31, 2016, outstanding guarantees and other assurances aggregated approximately $3.3 billion, consisting of
parental guarantees ($581 million), subsidiaries' guarantees ($1,933 million), other guarantees ($300 million) and other
assurances ($465 million).
Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt
obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and
NG. Accordingly, present and future holders of indebtedness of FES, FG, and NG would have claims against each of FES, FG,
and NG, regardless of whether their primary obligor is FES, FG, or NG.
COLLATERAL AND CONTINGENT-RELATED FEATURES
In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale
and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments
contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit
support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The
collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for
the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable
master netting agreements.
Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require
posting of collateral. Based on FES' power portfolio exposure as of December 31, 2016, FES has posted collateral of $190 million
and AE Supply has posted collateral of $4 million. The Regulated Distribution Segment has posted collateral of $3 million.
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These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary
were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required
to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for
margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the
potential additional credit rating contingent contractual collateral obligations as of December 31, 2016:
Potential Additional Collateral Obligations
FES
AE Supply Regulated
Total
Contractual Obligations for Additional Collateral
At Current Credit Rating
Upon Further Downgrade
Surety Bonds (Collateralized Amount)(1)
Total Exposure from Contractual Obligations
(In millions)
$
$
7 $
—
240
247 $
3 $
—
25
28 $
— $
48
102
150 $
10
48
367
425
(1) Effective January 2017, FE is a guarantor for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.
Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated
Distribution segment and CES segment. As of December 31, 2016, neither FES nor AE Supply had any collateral posted with their
affiliates. Moreover, a further downgrade for either FES or AE Supply would not trigger any obligations to post any such collateral.
OTHER COMMITMENTS, CONTINGENCIES AND ASSURANCES
FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed
$300 million. In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC,
each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations
of Global Holding under the facility.
In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and
their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding,
are pledged to the lenders under the current facility as collateral.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental
matters. 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 U.S. Court of Appeals for 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 EPA’s regulatory approach under CSAPR, but questioning whether EPA
required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. 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. Depending on the outcome of the appeals and on how
the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES'
operations may result.
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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. States will then have roughly three years to develop implementation plans to attain 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. 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. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.
MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective
in April 2015 with averaging of emissions from multiple units located at a single plant. FirstEnergy's total capital cost for compliance
(over the 2012 to 2018 time period) is currently expected to be approximately $345 million (CES segment of $168 million and
Regulated Distribution segment of $177 million), of which $286 million has been spent through December 31, 2016 ($125 million
at CES and $161 million at Regulated Distribution).
On August 3, 2015, FG, a 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 arises 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. In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that
excused FG’s further performance. 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 liability hearing from
November 28, 2016, through December 9, 2016, and, if necessary, a damages hearing is scheduled to begin on May 8, 2017. The
decision on liability is expected to be issued within sixty days from the end of the liability hearing proceedings, which are scheduled
to conclude February 24, 2017. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the
contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused. FG intends to
vigorously assert its position in the arbitration proceedings. If, however, the arbitration panel rules in favor of BNSF and CSX, the
results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. Refer to the
"Strategic Review of Competitive Operations" section of "Note 1, Organization and Basis of Presentation," for possible actions that
may be taken by FES in the event of an adverse outcome, including, without limitation, seeking protection under U.S. bankruptcy
laws. FirstEnergy and FES are unable to estimate the loss or range of loss.
On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from
BNSF and NS who 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 Plant. 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, among other things, damages, including lost profits through 2025, and a declaratory judgment that
FG's claim of force majeure is invalid. FG intends to vigorously assert its position in this arbitration proceeding. 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. Refer to the "Strategic Review of
Competitive Operations" section of "Note 1, Organization and Basis of Presentation," for possible actions that may be taken by
FES in the event of an adverse outcome, including, without limitation, seeking protection under U.S. bankruptcy laws. FirstEnergy
and FES are unable to estimate the loss or range of loss.
145
As to both coal transportation agreements referenced in the above arbitration proceedings, FG paid approximately $70 million in
the aggregate in liquidated damages to settle delivery shortfalls in 2014 related to its deactivated plants, which approximated full
liquidated damages under the agreements for such year related to the plant deactivations. Liquidated damages for the period
2015-2025 remain in dispute under both coal transportation agreements.
As to a specific coal supply agreement, AE Supply asserted termination rights effective in 2015 as a result of MATS. In response
to notification of the termination, the coal supplier commenced litigation alleging AE Supply does not have sufficient justification to
terminate the agreement. AE Supply has filed an answer denying any liability related to the termination. This matter is currently in
the discovery phase of litigation and no trial date has been established. There are approximately 5.5 million tons remaining under
the contract for delivery. At this time, AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with
respect to this agreement.
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, 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, 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 United States 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 regulations in August 2015
(which have been stayed by the U.S. Supreme Court), to reduce CO2 emissions from existing fossil fuel fired electric generating
units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO2 emission rate
goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop
SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions
trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO2 emission limits
for new, modified, and reconstructed fossil fuel fired electric generating units. Numerous states and private parties filed appeals
and motions to stay the CPP with the U.S. Court of Appeals for 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. Depending
on the outcome 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 greenhouse
gas emissions by 26 to 28 percent below 2005 levels by 2025 and 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 are effective on November 4, 2016. It
remains unclear whether and how the results of the 2016 United States election could impact the regulation of GHG emissions at
the federal and state level. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential
146
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. FirstEnergy is studying various control options and their costs and effectiveness,
including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from
the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based
on those studies, 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 will 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. 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.
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 coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal
requirements pending the EPA's evaluation of the need for future regulation.
In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards
regarding 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of
spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected,
any 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
147
"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. On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices
of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit
for the Hatfield’s Ferry CCR disposal facility.
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, 2016 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 $137 million have been accrued through December 31, 2016. Included in the total are accrued liabilities of
approximately $89 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 loss cannot be determined or reasonably estimated
at this time.
OTHER LEGAL PROCEEDINGS
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As
of December 31, 2016, FirstEnergy had approximately $2.5 billion invested in external trusts to be used for the decommissioning
and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based
on market conditions. If the value 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. FE and FES have also entered into a total of $24.5 million in parental guarantees in support of the decommissioning
of the spent fuel storage facilities located at the nuclear facilities. As FES no longer maintains investment grade credit ratings from
either S&P or Moody’s, NG funded a $10 million supplemental trust in 2016 in lieu of the FES parental guarantee that would be
required to support the decommissioning of the spent fuel storage facilities. The termination of the FES parental guarantee is
subject to NRC review. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental
guarantees, as appropriate.
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. FENOC plans to submit a license amendment application to the NRC related to the laminar cracking in the Shield
Building.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the
lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require
additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in
spent fuel pools. The NRC also requested that licensees including FENOC re-analyze earthquake and flooding risks using the
latest information available, conduct earthquake and flooding hazard walkdowns at their nuclear plants, assess the ability of current
communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power and assess plant
staffing levels needed to fill emergency positions. Although a majority of the necessary modifications and upgrades at FirstEnergy’s
nuclear facilities have been implemented, the improvements still remain subject to regulatory approval.
148
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. In addition to the $500
million credit facility with FE discussed above, FE is working with FES to establish conditional credit support on terms and
conditions to be agreed upon for the $400 million FES parental support agreement that is currently in place for the benefit of NG
in the event that FES is unable to provide the necessary support to NG.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal
business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected
to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described
under Note 15, Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can
reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably
possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can
be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to
liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
17. TRANSACTIONS WITH AFFILIATED COMPANIES
FES’ operating revenues, operating expenses, investment income and interest expenses include transactions with affiliated
companies. These affiliated company transactions include affiliated company power sales agreements between FirstEnergy's
competitive and regulated companies, support service billings, including corporate and nuclear facility operational and
maintenance support, interest on affiliated company notes including the money pools and other transactions.
FirstEnergy's competitive companies at times provide power through affiliated company power sales to meet a portion of the
Utilities' POLR and default service requirements. The primary affiliated company transactions for FES during the three years ended
December 31, 2016 are as follows:
FES
Revenues:
Electric sales to affiliates
Other
Expenses:
Purchased power from affiliates
Fuel
Support services
Investment Income:
Interest income from FE
Interest Expense:
Interest expense to affiliates
Interest expense to FE
2016
2015
(In millions)
2014
$
457 $
11
664 $
14
622
4
748
2
5
2
353
1
705
2
4
3
861
15
271
1
619
3
3
4
FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to FES and the Utilities
from FESC and FENOC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for
services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using
formulas developed by FESC and FENOC. The current allocation or assignment formulas used and their bases include multiple
factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset
balances, revenues, number of customers, other factors and specific departmental charge ratios. Intercompany transactions are
generally settled under commercial terms within thirty days. FES purchases the entire output of the generation facilities owned by
FG and NG, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale
and leaseback arrangements, and pursuant to full output, cost-of-service PSAs. Prior to April 1, 2016, FES financially purchased
the uncommitted output of AE Supply's generation facilities under a PSA. On December 21, 2015, FES agreed under a PSA to
149
physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply are evaluating
the possible termination of the PSA.
Additionally, FES and AE Supply are parties to an affiliated commodity transfer agreement in which AE Supply sells coal to FES
in accordance with the terms and conditions set forth under the respective coal purchase agreements that AE Supply has with a
third party. During 2016, 2015 and 2014, AE Supply sold 1.5 million, 1.2 million, and 1.7 million tons of coal to FES, respectively,
at its cost of $80.4 million, $62.8 million, and $96.3 million, respectively.
FES and the Utilities are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries that
provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE are generally reallocated to the
subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company
receiving the tax benefit (see "Note 6, Taxes").
150
18. SUPPLEMENTAL GUARANTOR INFORMATION
In 2007, FG completed a sale and leaseback transaction for its undivided interest in Bruce Mansfield Unit 1. FES has fully and
unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass
through certificates are not guaranteed by FES or FG, but the notes are secured by, among other things, each lessor trust's
undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements,
including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing
lease for FG.
The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31,
2016, 2015, and 2014, Condensed Consolidating Balance Sheets as of December 31, 2016 and December 31, 2015, and
Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2016, 2015, and 2014, for the parent and
guarantor and non-guarantor subsidiaries are presented below. These statements are provided as FG's parent company fully and
unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce
Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned
subsidiaries are accounted for by the parent company using the equity method. Results of operations for FG and NG are, therefore,
reflected in their parent company's investment accounts and earnings as if operating lease treatment was achieved. The principal
elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to
reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
151
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2016
FES
FG
NG
Eliminations Consolidated
(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES
$
4,242 $
1,739 $
2,004 $
(3,587 ) $
4,398
OPERATING EXPENSES:
Fuel
Purchased power from affiliates
Purchased power from non-affiliates
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
General taxes
Impairment of assets
Total operating expenses
—
4,024
1,020
310
(1 )
13
31
39
5,436
582
—
—
286
(4 )
120
30
3,937
4,951
198
187
—
632
53
206
27
4,729
6,032
OPERATING LOSS
(1,194 )
(3,212 )
(4,028 )
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from
equity investees
Miscellaneous income
Interest expense — affiliates
Interest expense — other
Capitalized interest
Total other income (expense)
(4,585 )
4
(50 )
(55 )
—
(4,686 )
30
3
(10 )
(105 )
8
(74 )
84
—
(4 )
(44 )
26
62
LOSS BEFORE INCOME TAX BENEFITS
(5,880 )
(3,286 )
(3,966 )
—
(3,587 )
—
49
—
(3 )
—
(83 )
(3,624 )
37
4,538
—
57
57
—
4,652
4,689
35
780
624
1,020
1,277
48
336
88
8,622
12,795
(8,397 )
67
7
(7 )
(147 )
34
(46 )
(8,443 )
(2,988 )
(5,455 )
INCOME TAX BENEFITS
NET LOSS
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(425 )
(1,169 )
(1,429 )
$
(5,455 ) $
(2,117 ) $
(2,537 ) $
4,654 $
NET LOSS
$
(5,455 ) $
(2,117 ) $
(2,537 ) $
4,654 $
(5,455 )
(14 )
—
—
(14 )
(5 )
(9 )
(2,126 ) $
—
—
52
52
20
32
(2,505 ) $
14
—
(52 )
(38 )
(15 )
(23 )
4,631 $
(14 )
—
52
38
15
23
(5,432 )
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs
Amortized gain on derivative hedges
Change in unrealized gain on available-for-sale securities
Other comprehensive income (loss)
Income taxes (benefits) on other comprehensive income
(loss)
Other comprehensive income (loss), net of tax
COMPREHENSIVE LOSS
(14 )
—
52
38
15
23
(5,432 ) $
$
152
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2015
FES
FG
NG
Eliminations Consolidated
(In millions)
STATEMENTS OF INCOME
REVENUES
$
4,824 $
1,801 $
2,138 $
(3,758 ) $
5,005
OPERATING EXPENSES:
Fuel
Purchased power from affiliates
Purchased power from non-affiliates
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
General taxes
Impairment of assets
Total operating expenses
OPERATING INCOME (LOSS)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from
equity investees
Miscellaneous income
Interest expense — affiliates
Interest expense — other
Capitalized interest
Total other income (expense)
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
NET INCOME
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME
$
$
OTHER COMPREHENSIVE LOSS:
Pension and OPEB prior service costs
Amortized gain on derivative hedges
Change in unrealized gain on available-for-sale securities
Other comprehensive loss
Income tax benefits on other comprehensive loss
Other comprehensive loss, net of tax
COMPREHENSIVE INCOME
$
—
3,826
1,684
378
(8 )
12
45
21
5,958
(1,134 )
844
1
(29 )
(52 )
—
764
(370 )
(452 )
679
—
—
273
10
124
26
2
1,114
687
17
2
(8 )
(104 )
6
(87 )
600
224
192
285
—
608
55
191
27
10
1,368
770
(5 )
—
(4 )
(49 )
29
(29 )
741
278
—
(3,758 )
—
49
—
(3 )
—
—
(3,712 )
(46 )
(870 )
—
34
58
—
(778 )
(824 )
15
82 $
376 $
463 $
(839 ) $
82 $
376 $
463 $
(839 ) $
(6 )
(3 )
(9 )
(18 )
(7 )
(11 )
71 $
(5 )
—
—
(5 )
(2 )
(3 )
373 $
—
—
(8 )
(8 )
(3 )
(5 )
458 $
5
—
8
13
5
8
(831 ) $
871
353
1,684
1,308
57
324
98
33
4,728
277
(14 )
3
(7 )
(147 )
35
(130 )
147
65
82
82
(6 )
(3 )
(9 )
(18 )
(7 )
(11 )
71
153
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2014
FES
FG
NG
Eliminations Consolidated
(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES
$
5,990 $
1,902 $
2,172 $
(3,920 ) $
6,144
OPERATING EXPENSES:
Fuel
Purchased power from affiliates
Purchased power from non-affiliates
Other operating expenses
Pension and OPEB mark-to-market adjustment
Provision for depreciation
General taxes
Total operating expenses
OPERATING INCOME (LOSS)
OTHER INCOME (EXPENSE):
Investment income, including net income from equity
investees
Miscellaneous income
Interest expense — affiliates
Interest expense — other
Capitalized interest
Total other income (expense)
INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
INCOME (LOSS) FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of $8)
NET INCOME (LOSS)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)
$
$
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs
Amortized gain on derivative hedges
Change in unrealized gain on available-for-sale securities
Other comprehensive income (loss)
Income taxes (benefits) on other comprehensive
income (loss )
Other comprehensive income (loss), net of tax
COMPREHENSIVE INCOME (LOSS)
$
—
3,920
2,767
790
19
10
72
7,578
(1,588 )
791
2
(12 )
(56 )
—
725
(863 )
(619 )
(244 )
—
1,055
—
4
269
90
119
31
1,568
334
8
4
(6 )
(102 )
4
(92 )
242
87
155
116
198
271
—
527
188
193
25
1,402
770
61
—
(4 )
(54 )
30
33
803
298
505
—
—
(3,920 )
—
49
—
(3 )
—
(3,874 )
(46 )
(799 )
—
15
60
—
(724 )
(770 )
6
(776 )
—
(244 ) $
271 $
505 $
(776 ) $
1,253
271
2,771
1,635
297
319
128
6,674
(530 )
61
6
(7 )
(152 )
34
(58 )
(588 )
(228 )
(360 )
116
(244 )
(244 ) $
271 $
505 $
(776 ) $
(244 )
(6 )
(10 )
21
5
2
3
(241 ) $
(5 )
—
—
(5 )
(2 )
(3 )
268 $
—
—
21
21
8
13
518 $
5
—
(21 )
(16 )
(6 )
(10 )
(786 ) $
(6 )
(10 )
21
5
2
3
(241 )
154
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2016
FES
FG
NG
(In millions)
Eliminations
Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
Customers
Affiliated companies
Other
Notes receivable from affiliated companies
Materials and supplies
Derivatives
Collateral
Prepayments and other
PROPERTY, PLANT AND EQUIPMENT:
In service
Less — Accumulated provision for depreciation
Construction work in progress
INVESTMENTS:
Nuclear plant decommissioning trusts
Investment in affiliated companies
Other
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits
Customer intangibles
Property taxes
Derivatives
Other
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
Short-term borrowings-
Affiliated companies
Other
Accounts payable-
Affiliated companies
Other
Accrued taxes
Derivatives
Other
CAPITALIZATION:
Total equity
Long-term debt and other long-term obligations
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction
Accumulated deferred income taxes
Retirement benefits
Asset retirement obligations
Derivatives
Other
2
213
452
27
29
267
137
157
63
1,347
7,057
5,929
1,128
427
1,555
1,552
—
10
1,562
2,279
9
40
77
372
2,777
7,241
179
101
—
550
110
143
77
156
1,316
218
2,813
3,031
757
—
197
901
52
987
2,894
7,241
$
— $
2 $
— $
— $
—
315
2
1,585
142
—
—
24
2,070
2,524
1,920
604
67
671
—
—
9
9
1,271
—
12
—
327
1,610
4,360 $
200 $
483
—
107
93
48
6
54
991
828
2,093
2,921
—
3
172
188
—
85
448
4,360 $
—
417
8
1,294
80
—
—
1
1,800
4,703
4,144
559
358
917
1,552
—
1
1,553
883
—
28
—
—
911
5,181 $
5 $
—
—
406
—
61
—
10
482
2,006
1,120
3,126
—
—
—
713
—
860
1,573
5,181 $
—
(612 )
—
(3,351 )
—
—
—
—
(3,963 )
(290 )
(187 )
(103 )
—
(103 )
—
(2,923 )
—
(2,923 )
(270 )
—
—
—
21
(249 )
(7,238 ) $
(26 ) $
(3,351 )
—
(706 )
—
(16 )
—
36
(4,063 )
(2,834 )
(1,091 )
(3,925 )
757
(7 )
—
—
—
—
750
(7,238 ) $
213
332
17
501
45
137
157
38
1,440
120
52
68
2
70
—
2,923
—
2,923
395
9
—
77
24
505
4,938 $
— $
2,969
—
743
17
50
71
56
3,906
218
691
909
—
4
25
—
52
42
123
4,938 $
155
$
$
$
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2015
FES
FG
NG
(In millions)
Eliminations
Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
Customers
Affiliated companies
Other
Notes receivable from affiliated companies
Materials and supplies
Derivatives
Collateral
Prepayments and other
PROPERTY, PLANT AND EQUIPMENT:
In service
Less — Accumulated provision for depreciation
Construction work in progress
INVESTMENTS:
Nuclear plant decommissioning trusts
Investment in affiliated companies
Other
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits
Customer intangibles
Goodwill
Property taxes
Derivatives
Other
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
Short-term borrowings-
Affiliated companies
Other
Accounts payable-
Affiliated companies
Other
Accrued taxes
Derivatives
Other
CAPITALIZATION:
Total equity
Long-term debt and other long-term obligations
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction
Accumulated deferred income taxes
Retirement benefits
Asset retirement obligations
Derivatives
Other
2
275
451
59
11
470
154
70
66
1,558
14,311
5,765
8,546
1,157
9,703
1,327
—
10
1,337
—
61
23
40
79
367
570
13,168
512
—
8
542
139
76
104
181
1,562
5,605
2,510
8,115
791
600
332
831
38
899
3,491
13,168
$
— $
2 $
— $
— $
—
403
4
1,210
204
—
—
18
1,841
6,367
2,144
4,223
249
4,472
—
—
10
10
16
—
—
12
—
312
340
6,663 $
229 $
389
8
146
118
93
1
61
1,045
2,944
2,116
5,060
—
—
305
191
1
61
558
6,663 $
—
461
19
805
213
—
—
—
1,498
8,233
3,775
4,458
878
5,336
1,327
—
—
1,327
—
—
—
28
—
14
42
8,203 $
308 $
—
—
368
—
62
—
9
747
4,476
840
5,316
—
697
—
640
—
803
2,140
8,203 $
—
(846 )
—
(2,410 )
—
—
—
—
(3,256 )
(382 )
(194 )
(188 )
—
(188 )
—
(7,452 )
—
(7,452 )
(316 )
—
—
—
—
12
(304 )
(11,200 ) $
(25 ) $
(2,410 )
—
(856 )
—
(86 )
—
45
(3,332 )
(7,420 )
(1,136 )
(8,556 )
791
(103 )
—
—
—
—
688
(11,200 ) $
275
433
36
406
53
154
70
48
1,475
93
40
53
30
83
—
7,452
—
7,452
300
61
23
—
79
29
492
9,502 $
— $
2,021
—
884
21
7
103
66
3,102
5,605
690
6,295
—
6
27
—
37
35
105
9,502 $
156
$
$
$
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2016
FES
FG
NG
Eliminations Consolidated
(In millions)
$
(842 ) $
549
$
1,103
$
(25 ) $
785
—
(941 )
25
—
(916 )
—
—
—
—
—
—
941
—
941
—
—
— $
471
101
(507 )
(8 )
57
(546 )
(232 )
9
717
(783 )
10
(18 )
1
(842 )
—
2
2
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt
Short-term borrowings, net
Redemptions and Repayments-
Long-term debt
Other
—
948
—
—
186
94
(224 )
(6 )
Net cash provided from (used for) financing
activities
948
50
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
Nuclear fuel
Proceeds from asset sales
Sales of investment securities held in trusts
Purchases of investment securities held in trusts
Cash Investments
Loans to affiliated companies, net
Other
(30 )
—
9
—
—
10
(95 )
—
(224 )
—
—
—
—
—
(376 )
1
285
—
(308 )
(2 )
(25 )
(292 )
(232 )
—
717
(783 )
—
(488 )
—
Net cash used for investing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
(106 )
—
—
— $
(599 )
—
2
2 $
(1,078 )
—
—
— $
157
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2015
FES
FG
NG
Eliminations Consolidated
(In millions)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES
$
(637 ) $
551
$
1,261
$
(24 ) $
1,151
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt
Short-term borrowings, net
Redemptions and Repayments-
Long-term debt
Short-term borrowings, net
Common stock dividend payment
Other
Net cash provided from (used for) financing
activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
Nuclear fuel
Proceeds from asset sales
Sales of investment securities held in trusts
Purchases of investment securities held in trusts
Cash investments
Loans to affiliated companies, net
Other
Net cash used for investing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
—
796
(17 )
—
(70 )
—
709
(5 )
—
10
—
—
(10 )
(67 )
—
(72 )
—
—
— $
45
67
(70 )
—
—
(5 )
37
296
—
(348 )
(28 )
—
(1 )
(81 )
(223 )
—
3
—
—
—
(372 )
4
(588 )
—
2
2 $
(399 )
(190 )
—
733
(791 )
—
(533 )
—
(1,180 )
—
—
— $
—
(863 )
24
(98 )
—
—
(937 )
—
—
—
—
—
—
961
—
961
—
—
— $
341
—
(411 )
(126 )
(70 )
(6 )
(272 )
(627 )
(190 )
13
733
(791 )
(10 )
(11 )
4
(879 )
—
2
2
158
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2014
FES
FG
NG
Eliminations Consolidated
(In millions)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES
$
(600 ) $
408
$
785
$
(22 ) $
571
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt
Short-term borrowings, net
Equity contribution from parent
Redemptions and Repayments-
Long-term debt
Short-term borrowings, net
Other
—
247
500
(1 )
—
(1 )
431
114
—
(269 )
—
(12 )
Net cash provided from (used for) financing
activities
745
264
447
—
—
(568 )
(123 )
(2 )
(246 )
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
Nuclear fuel
Proceeds from asset sales
Sales of investment securities held in trusts
Purchases of investment securities held in trusts
Loans to affiliated companies, net
Other
Net cash used for investing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
(8 )
—
—
—
—
(136 )
(1 )
(145 )
—
—
— $
(169 )
—
307
—
—
(815 )
5
(672 )
—
2
2 $
(662 )
(233 )
—
1,163
(1,219 )
412
—
(539 )
—
—
— $
—
(361 )
—
22
(178 )
—
(517 )
—
—
—
—
—
539
—
539
—
—
— $
878
—
500
(816 )
(301 )
(15 )
246
(839 )
(233 )
307
1,163
(1,219 )
—
4
(817 )
—
2
2
159
19. SEGMENT INFORMATION
FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES.
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate
reportable operating segments.
During the fourth quarter of 2016, FirstEnergy modified its segment reporting to reclassify the results of operations from certain
transmission assets of ME, PN and JCP&L, from the Regulated Distribution segment to the Regulated Transmission segment.
Costs associated with these transmission assets, which are currently included in ME, PN, and JCP&L's stated rates, will be
recovered through MAIT's and JCP&L’s formula rates prospectively, once approved by FERC. The external segment reporting is
consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to
regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments
for 2015 and 2014 have been revised to conform to the current presentation reflecting the operating activity of the identified
transmission assets within Regulated Transmission.
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 and TrAIL
and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated
with the abandoned PATH project. 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 "FERC Matters" below, effective January 31,
2017, MAIT includes the transmission assets of ME and PN, and JCP&L submitted applications to FERC requesting authorization
to implement forward-looking formula transmission rates. Those applications are pending before FERC. Both the forward-looking
and stated rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of
ATSI's and TrAIL's revenue requirement is updated annually based on a projected rate base and projected costs, which is subject
to an annual true-up based on actual costs. Except for the recovery of the PATH abandoned project regulatory asset, the segment's
revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. 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, Illinois, Michigan, New Jersey and
Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including
the Utilities. As of December 31, 2016, this business segment controlled 13,162 MWs of electric generating capacity, including, as
discussed in "Note 15, Regulatory Matters", 1,572 MWs of natural gas and hydroelectric generating capacity subject to an asset
purchase agreement with Aspen and the 1,300 MW Pleasants power station which was offered into MP's RFP process by AE
Supply. 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.
Corporate support not charged to FE's subsidiaries, 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, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of
which 28% was subject to variable-interest rates, and $2.7 billion was borrowed by FE under its revolving credit facility.
160
Segment Financial Information
For the Years Ended December 31
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/
Other
Reconciling
Adjustments Consolidated
(In millions)
2016
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of assets
Investment income
Interest expense
Income taxes (benefits)
Net income (loss)
Total assets
Total goodwill
Property additions
2015
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Net income (loss)
Total assets
Total goodwill
Property additions
2014
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Investment income
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Total assets
Total goodwill
Property additions
$
$
$
9,629 $
—
9,629
676
313
—
49
586
375
651
27,702
5,004
1,063
9,582 $
—
9,582
664
261
8
42
—
600
325
588
27,390
5,092
1,040
9,054 $
—
9,054
651
1
56
603
209
433
—
433
27,332
5,092
855
1,151 $
—
1,151
187
7
—
—
158
187
331
8,755
614
1,101
1,054 $
—
1,054
164
7
—
—
—
147
191
328
7,800
526
1,020
817 $
—
817
134
11
—
117
139
255
—
255
6,864
526
1,446
4,070 $
479
4,549
387
—
10,665
66
194
(3,498 )
(6,919 )
5,952
—
619
4,698 $
686
5,384
394
—
34
(16 )
—
192
50
89
16,027
800
588
5,470 $
819
6,289
387
—
54
197
(223 )
(417 )
86
(331 )
16,180
800
939
— $
—
—
63
—
—
10
219
(121 )
(240 )
739
—
52
— $
—
—
60
—
—
(9 )
362
193
(262 )
(427 )
877
—
56
— $
—
—
48
—
2
168
(178 )
(58 )
—
(58 )
1,176
—
72
(288 ) $
(479 )
(767 )
—
—
—
(41 )
—
2
—
—
—
—
(308 ) $
(686 )
(994 )
—
—
—
(39 )
—
—
11
—
—
—
—
(292 ) $
(819 )
(1,111 )
—
—
(40 )
(4 )
11
—
—
—
—
—
—
14,562
—
14,562
1,313
320
10,665
84
1,157
(3,055 )
(6,177 )
43,148
5,618
2,835
15,026
—
15,026
1,282
268
42
(22 )
362
1,132
315
578
52,094
6,418
2,704
15,049
—
15,049
1,220
12
72
1,081
(42 )
213
86
299
51,552
6,418
3,312
161
20. DISCONTINUED OPERATIONS
On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to a subsidiary of LS Power
Equity Partners II, LP for approximately $394 million (FES - $307 million). The carrying value of the assets sold was $235 million
(FES - $122 million), including goodwill of $29 million (FES - $1 million). Pre-tax income for the hydroelectric facilities of $155
million (FES - $186 million) for the year ended December 31, 2014, was included in discontinued operations in the Consolidated
Statement of Income (Loss). Included in income for discontinued operations in the year ended December 31, 2014, was a pre-tax
gain on the sale of assets of $142 million (FES - $177 million). Revenues for the hydroelectric facilities of $5 million (FES - $5
million) for year ended December 31, 2014, were included in discontinued operations in the Consolidated Statement of Income
(Loss).
21. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarizes certain consolidated operating results by quarter for 2016 and 2015.
FirstEnergy
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In millions, except per share amounts)
2016
2015
Revenues
Other operating expense
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Impairment of assets
Operating Income (Loss)
Income (loss) before income taxes (benefits)
Income taxes (benefits)
Net Income (Loss)
Earnings (loss) per share of common stock-(1)
Basic - Earnings (losses) Available to
FirstEnergy Corp.
Diluted - Earnings (losses) Available to
FirstEnergy Corp.
3,869 $ 3,541 $
Dec. 31 Sept. 30 June 30
$ 3,375 $
1,023
147
339
9,218
(8,924 )
(9,185 )
(3,389 )
(5,796 )
3,917 $
953
—
311
—
861
631
251
380
3,401 $
964
—
334
1,447
(975 )
(1,219 )
(130 )
(1,089 )
Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31
3,897
1,057
—
319
—
594
366
144
222
4,123 $
842
—
328
8
908
621
226
395
3,465 $
900
—
322
16
554
302
115
187
950
242
313
18
236
(396 )
(170 )
(226 )
918
—
329
—
776
541
213
328
(13.44 )
(13.44 )
0.89
0.89
(2.56 )
(2.56 )
0.78
0.77
(0.53 )
(0.53 )
0.94
0.44
0.53
0.93
0.44
0.53
(1) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares
throughout the year and the $500 million equity issuance in December 2016. See FirstEnergy's Consolidated Statements of
Stockholders' Equity, "Note 5, Stock-Based Compensation Plans" and "Note 12, Capitalization" for additional information.
FES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In millions)
2016
2015
Revenues
Other operating expense
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Impairment of assets
Operating Income (Loss)
Income (loss) from continuing operations
before income taxes (benefits)
Income taxes (benefits)
Net Income (Loss)
1,199 $ 1,171 $
Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31
1,377
$
413
—
80
—
12
997 $
352
48
86
8,082
(8,153 )
1,100 $
316
—
83
—
101
1,338 $
246
—
79
—
240
1,102 $
369
—
84
540
(571 )
1,119 $
337
—
81
16
—
240
—
83
—
226
312
57
84
17
25
(8,171 )
(2,983 )
(5,188 )
96
56
40
(581 )
(143 )
(438 )
213
82
131
(13 )
1
(14 )
190
70
120
(25 )
(4 )
(21 )
(5 )
(2 )
(3 )
162
22. SUBSEQUENT EVENTS
On January 18, 2017, AE Supply and AGC entered into an asset purchase agreement to sell four of AE Supply’s natural gas
generating plants in Pennsylvania and approximately 59% of AGC’s interests in a Virginia hydroelectric power station to Aspen.
The power stations included in the sale have a total capacity of 1,572 MWs:
• Bath County Hydro (713 MWs pumped-storage hydro) in Warm Springs, Va. (represents AE Supply’s indirect interest)
• Springdale Generating Facility Units 1-5 (638 MWs natural gas) in Springdale Township, Pa.
• Chambersburg Generating Facility Units 12-13 (88 MWs natural gas) in Guildford Township, Pa.
• Gans Generating Facility Units 8-9 (88 MWs natural gas) in Springhill Township, Pa.
• Hunlock Creek (45 MWs natural gas) in Hunlock Creek, Pa.
Under the terms of the agreement, the facilities would be purchased for an all cash purchase price of approximately $925 million.
The transaction is expected to close in the third quarter of 2017 subject to satisfaction of various customary and other closing
conditions, including, without limitation, receipt of regulatory approvals, third party consents and the satisfaction and discharge of
AE Supply’s senior note indenture, under which there is approximately $305 million aggregate principal amount of indebtedness
outstanding. There can be no assurance that any such approvals will be obtained and/or any such conditions will be satisfied or
that such sale will be consummated. Further, the satisfaction and discharge of AE Supply’s senior note indenture in connection
with the closing is expected to require the payment of a “make-whole” premium calculated just prior to the redemption, which
based on current interest rates is approximately $100 million. It is expected that proceeds from the sale will be invested in the
unregulated money pool and may be used for the repayment of debt and general corporate purposes.
As a further condition to closing, FE will provide Aspen two limited guaranties of certain obligations of AE Supply and AGC arising
under the purchase agreement. The guaranties vary in amount and scope and expire in one and three years, respectively.
On February 16, 2017, FE entered into two separate $125 million three-year term loan credit agreements with Bank of America,
N.A. and The Bank of Nova Scotia, respectively, the proceeds of which were used to reduce short-term debt. The terms and
conditions of these new credit agreements are substantially similar to the December 6, 2016, $1.2 billion five-year syndicated term
loan credit agreement.
163
SHAREHOLDER SERVICES
T R A N S F E R A G E N T A N D R E G I S T R A R
American Stock Transfer & Trust Company, LLC (AST) is the company’s Transfer Agent and Registrar.
Registered shareholders wanting to transfer stock, or who need assistance or information, can send their
stock certificate(s) or write to FirstEnergy Corp., c/o American Stock Transfer & Trust Company, LLC,
P.O. Box 2016, New York, NY 10272-2016. Shareholders also can call toll-free at 1-800-736-3402, between
8:00 a.m. and 8:00 p.m. Eastern time, Monday through Friday. For Internet access to general shareholder and
account information, visit the AST website at https://us.astfinancial.com/investpower/new_plandet.asp.
S T O C K I N V E S T M E N T P L A N
Registered shareholders and employees of the company can participate in the Stock Investment Plan.
To learn more about the company’s Stock Investment Plan, visit AST’s website at
https://us.astfinancial.com/investpower/new_plandet.asp or contact AST toll-free at 1-800-736-3402.
D I R E C T D I V I D E N D D E P O S I T
Registered shareholders can have their dividend payments automatically deposited to checking, savings
or credit union accounts at any financial institution that accepts electronic direct deposits. Using this free
service ensures that payments will be available to you on the payment date, eliminating the possibility
of mail delay or lost checks. Contact AST toll-free at 1-800-736-3402 to receive a Direct Dividend Deposit
Authorization Agreement.
S T O C K L I S T I N G A N D T R A D I N G
The common stock of FirstEnergy is listed on the New York Stock Exchange under the symbol FE.
F O R M 1 0 - K A N N U A L R E P O R T
The Annual Report on Form 10-K, as filed with the Securities and Exchange Commission, including
the financial statements and financial statement schedules, will be sent to you without charge
upon written request to Ketan K. Patel, Vice President, Corporate Secretary and Chief Ethics Officer,
FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. You also can view the Form 10-K by
visiting the company’s website at www.firstenergycorp.com/financialreports.
PRESORTED STD
U.S. POSTAGE
PAID
AKRON, OH
PERMIT No. 561
76 South Main Street, Akron, Ohio 44308-1890