A N N U A L
R E P O R T
2015
FINANCIAL HIGHLIGHTS
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
• Secured a 20-year license extension from
• Invested nearly $1 billion to modernize our
transmission system as part of our Energizing
the Future initiative
• Launched our Cash Flow Improvement Project
with the goal of capturing meaningful and
sustainable savings across our company
the Nuclear Regulatory Commission for the
Davis-Besse Nuclear Power Station
• Enhanced transmission and distribution
system reliability
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
BASIC AND DILUTED EARNINGS per common share
DIVIDENDS PAID per common share
BOOK VALUE per common share
2015
$15,026
$578
$1.37
$1.44
2014
$15,049
$299
$0.71
$1.44
$29.33
$29.49
2013
$14,892
$392
$0.94
$2.20
$30.32
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)
2015
2014
2013
$3,447
$2,713
$2,662
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
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 *
2015
2014
2013
2.80
2.56
2.47
0
0.5
1
1.5
2
2.5
3
N E T I N C O M E
(in millions)
2015
2014
2013
$299
$392
$578
0
100
200
300
400
500
600
* 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
Charles E. Jones
President and Chief Executive Officer
We maintained a strong focus in 2015 on achieving more regulated, customer-focused growth for your company.
Toward that end, we made significant investments to enhance the reliability and efficiency of our electric
system. These included $986 million in targeted improvements during the year to our transmission system,
and approximately $1.2 billion in capital upgrades that helped our regulated utilities continue to provide
reliable service to customers. We also received approval on a forward-looking rate filing for our American
Transmission Systems, Inc. (ATSI) transmission company, which will allow more effective and timely recovery
of its system investments.
Six of our regulated utilities received approval of settlements in distribution rate cases in 2015, and our
rate case in New Jersey also was resolved, resulting in an overall revenue increase of $321 million. In Ohio,
the Public Utilities Commission of Ohio (PUCO) is reviewing a settlement agreement with 17 key parties
supporting our Electric Security Plan IV (ESP) for The Illuminating Company, Ohio Edison and Toledo Edison.
The plan is expected to strengthen your company’s financial position in the years ahead and is designed
to provide significant benefits to our customers and communities – including more stable rates, a renewed
emphasis on energy efficiency and renewable power, and strong support for economic development. The
PUCO is expected to rule on the ESP by the end of March.
We also expect to achieve $240 million in annual savings by 2017 through our Cash Flow Improvement Project
– a comprehensive effort our employees conducted in 2015, and will closely monitor in the years ahead,
to reduce expenses and enhance revenue throughout our operations. In addition, we continue to execute
a more conservative strategy for our competitive generation business that minimizes risk while taking
advantage of market opportunities.
1
GROWING OUR
REGULATED OPERATIONS
We’re building a stronger energy system
through our primary growth platform,
Energizing the Future – an initial
$4.2 billion investment in the long-term
reliability of our transmission system
that began in 2014 and runs through
2017. Spanning our entire transmission
system, projects funded through the
program are designed to meet the
future energy needs of customers by
adding resiliency to our bulk electric
system, enhancing our facilities and
equipment, and increasing physical and
cyber security.
Initial efforts primarily focused on
the ATSI transmission system that
encompasses the service areas of Ohio
Edison, Toledo Edison, The Illuminating
Company and Penn Power, with
projects shifting eastward over time to
include our other service areas. Work
performed to date also has helped
us identify $15 billion in additional
opportunities across our 24,200-mile
transmission system that will benefit
customers through further reliability
enhancements.
Among other projects, we’re reinforcing
our system to ensure grid reliability
following the retirement of coal-fired
power plants in our region. For example,
since 2014, we’ve invested $500 million
in transmission projects to support
the deactivation of three of our power
plants along Lake Erie. As part of this
effort, we built a 119-mile transmission
line from Beaver County, Pa., to our new
Glenwillow substation in suburban
Cleveland, as well as five new substations
across portions of our Ohio service area.
In addition, we’re nearing completion of
a transmission reinforcement project in
Harrison County, W.Va., that involves the
construction of a new substation and a
6-mile transmission line. The project is
expected to enhance service reliability
for approximately 14,000 customers in
the northern portion of West Virginia.
Given that our regulated footprint is
aligned with some of the nation’s richest
shale fields, we’re making investments
through 2020 to support growth
in midstream shale gas operations
2
throughout our service area, including
planned expansions that are expected
to create 600 megawatts (MW) of
new industrial load. For example,
we recently completed preliminary
site work for a new substation near
Smithfield, W.Va., that is expected to
support new shale gas operations as
well as enhanced service reliability for
Mon Power customers. Over the past
few years, shale gas development has
accounted for approximately 500 MW
of new load growth in our region.
We remain committed to providing safe,
reliable service to our utility customers.
All of our utilities outperformed state
requirements for SAIDI – an industry-
wide measure of the average outage
duration for each customer served.
In the critical area of safety, our
companywide OSHA rate reached
industry top-quartile performance in
2015. This reflects the great importance
we place on safe work practices in every
facet of our operations.
A crew member welds a stainless steel roof for one of three,
1 million-gallon water tanks for the dewatering facility under
construction at our Bruce Mansfield Plant. The facility is
needed to dispose of the plant’s coal combustion byproducts
following the scheduled closing of the Little Blue Run
disposal site at the end of 2016.
CREATING A
SMARTER GRID
As part of our Energizing the Future
initiative, we began investing in nearly
900 smart grid projects designed to
make our transmission system more
robust, secure and resistant to extreme
weather events as well as cyber and
physical attacks.
These smart grid technologies have the
potential to significantly improve our
response time to outages by enabling
more efficient service restoration. In
addition, remote monitoring devices
can proactively evaluate grid conditions
and take corrective actions even before
outages occur. We’re also upgrading our
transmission equipment with advanced
technologies designed to enhance
the reliability of our system and meet
projected load growth in our region.
We continued to move forward with our
Pennsylvania smart meter program,
installing more than 160,000 smart
meters in our Penn Power service area
by the end of 2015. Through this state-
mandated effort, we plan to deploy more
than 2 million smart meters across our
Pennsylvania service area by mid-2019.
Although smart grid technologies can
be costly, we’re receiving full recovery of
our investments in Pennsylvania’s smart
meter program – and we will explore
similar programs in other states that
allow recovery of these costs. In fact,
as part of our proposed ESP, we filed
a plan to evaluate smart meter and
smart grid technologies across our
Ohio service area, subject to PUCO
consideration and approval.
NEARLY
32 MILLION
MEGAWATT-HOURS OF
CARBON-FREE ELECTRICITY
GENERATED BY OUR
THREE NUCLEAR POWER
STATIONS IN 2015
3
ENSURING FAIR AND
AFFORDABLE RATES
We made significant progress during
the year in our efforts to strengthen
earnings by ensuring fair, appropriate
and timely recovery of our transmission
and distribution investments.
In October, the Federal Energy
Regulatory Commission (FERC)
approved a settlement agreement for
a forward-looking rate structure for
ATSI, which owns and operates nearly
7,800 miles of transmission lines.
This agreement provides more timely
recovery of transmission investments
that are essential to ensuring the
future reliability of our service.
FERC also approved a plan to transfer
the transmission assets owned by three
of our operating companies – Jersey
Central Power & Light (JCP&L), Met-Ed
and Penelec – to a new affiliate, Mid-
Atlantic Interstate Transmission (MAIT).
Similar to our existing ATSI and TrAILCo
transmission companies, MAIT will help
us more effectively finance and build
transmission facilities within our
Met-Ed, Penelec and JCP&L service
areas while providing stronger support
to our Energizing the Future initiative as
it expands eastward. Although the New
Jersey Board of Public Utilities (BPU)
rejected one of the plan’s provisions, it
continues to review the remainder of the
proposal. We also filed a comprehensive
settlement agreement with the
Pennsylvania Public Utility Commission
(PPUC) for approval of MAIT.
Approval of our Ohio ESP by the PUCO
would be an important step in our efforts
to protect customers from future price
volatility. The plan includes a rider that
reflects the difference between the
cost of an eight-year Purchased Power
Agreement (PPA) and our Ohio utilities’
associated wholesale market revenues.
The PPA supports the continued
operation of two of our critical baseload
power plants – the Davis-Besse Nuclear
Power Station and the W.H. Sammis
Plant – which would preserve more
than $41 million in annual tax revenues
and an estimated 3,000 direct and
indirect jobs related to those facilities.
Although the PPA has been challenged
at FERC, we will continue to advocate
for the plan’s many benefits in that
proceeding.
In February of 2016, the PPUC approved
long-term infrastructure improvement
plans for our four Pennsylvania utilities,
supporting a projected increase in capital
investment of nearly $245 million
over the next five years to strengthen,
upgrade and modernize our distribution
systems in the state. The four utilities
also filed rate riders that, with PPUC
approval, would facilitate recovery of
these investments.
Our competitive subsidiary, FirstEnergy Solutions, contracts
for renewable energy from the 35-MW Casselman Wind Power
Project located in Somerset County, Pa.
PROVIDE MORE THAN
1 MILLION
MEGAWATT-HOURS PER YEAR
OF WIND GENERATION
4
LOWERING RISK IN OUR
COMPETITIVE BUSINESS
We continue to execute a conservative
sales and generation strategy that
offers less risk to the company.
To achieve this goal, our FirstEnergy
Solutions subsidiary continued to
restructure its sales portfolio to reduce
our exposure to weather-sensitive
demand and ensure we don’t sell more
power than we produce. A larger
portion of our generation is kept in
reserve to minimize our financial risk
when energy prices increase and ensure
power is available to sell when market
conditions are favorable.
We’re maintaining our support of
governmental aggregation and other
higher-margin sales while pursuing
wholesale opportunities that align
with our generation portfolio. We also
remain committed to economically
dispatching our fleet and operating
our units with greater flexibility.
FirstEnergy Nuclear Operating Company
(FENOC) reached a significant milestone
in 2015 when the Nuclear Regulatory
Commission approved a 20-year
license extension for the Davis-Besse
Nuclear Power Station, allowing the
unit to operate until 2037. In addition,
improved reliability and outage
execution enabled FENOC to produce
approximately 1 million megawatt-hours
over its original plan for the year, further
improving commodity margin.
PJM Interconnection’s new Capacity
Performance product had a positive
impact in more properly valuing
essential and highly reliable baseload
generating resources. Capacity auctions
held in August and September of 2015
are expected to improve revenues by
$1.1 billion from June 2016 through
May 2019. However, markets continue
to fall short of reflecting the true cost of
operating our baseload power plants.
MEETING OUR ENVIRONMENTAL
COMMITMENTS
In 2015, we continued to make progress
to improve the environmental performance
of our operations.
Our proposed Ohio ESP includes a goal
to reduce carbon dioxide emissions by
at least 90 percent below 2005 levels
by 2045 – exceeding President Obama’s
goal of achieving economywide reductions
of 80 percent or more by 2050.
The Clean Power Plan called for
individual states to develop plans for
meeting the U.S. Environmental Protection
Agency’s state-specific emission
reduction goals. However, on Feb. 9,
2016, the U.S. Supreme Court granted
a petition from 27 states and other
stakeholders to halt enforcement of the
Clean Power Plan’s final rule until after all
legal challenges are resolved.
FirstEnergy submitted extensive
comments before the rule was finalized,
and we’re continuing to engage federal
and state policymakers on issues
related to our ongoing efforts to
ensure the availability of clean, reliable
and affordable energy resources for
customers.
5
We’ve also made the significant investments needed to comply with the EPA’s Mercury
and Air Toxics Standards and other requirements, and we will continue to invest in our
fossil fleet to help maintain reliable and affordable supplies of power for customers as
we make the transition to a cleaner energy future.
$4.2 BILLION
IN PLANNED TRANSMISSION
INVESTMENTS FROM 2014
THROUGH 2017
SETTING A COURSE FOR
THE FUTURE
I’m proud of what our employees have accomplished, and I’m confident they will help
us succeed in the future by continuing to provide customers with the level of service
they expect and deserve.
We’re pursuing the right strategy for your company. By achieving solid performance
across our three business sectors – distribution, transmission and generation – and
remaining focused on meeting our customers’ immediate and long-term energy needs,
we can deliver more sustainable growth and greater financial stability for FirstEnergy
in the years ahead.
Thank you for your support as we work to achieve continued success for your company.
Charles E. Jones
President and Chief Executive Officer
March 16, 2016
6
6
6
PA
PA
OH
NJ
MD
WV
VA
C O R P O R A T E P R O F I L E
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 generation,
transmission and distribution 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.
Our generation subsidiaries control nearly 17,000 megawatts (MW) of
capacity from a diversified mix of scrubbed coal, nuclear, natural gas, oil,
hydroelectric pumped-storage and contracted wind and solar resources –
including 1,900 MW of renewable energy. The company’s transmission
subsidiaries operate approximately 24,200 miles of transmission lines
connecting the Midwest and Mid-Atlantic regions.
FirstEnergy Solutions, our competitive subsidiary, is a retail energy
supplier serving approximately 1.6 million residential, commercial and
industrial customers in Ohio, Pennsylvania, New Jersey, Maryland,
Michigan and Illinois.
Ohio
Ohio Edison
The Illuminating Company
Toledo Edison
Pennsylvania
Met-Ed
Penelec
Penn Power
West Penn Power
West Virginia/Maryland
Mon Power
Potomac Edison
New Jersey
Jersey Central Power & Light
Generating
Stations
Coal
Gas/Oil
Hydro
Nuclear
Wind
Solar
7
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
D E A R S H A R E H O L D E R S :
FirstEnergy’s management team and employees
made significant progress in 2015. Your Board
of Directors commends their efforts to achieve
customer-focused growth in the company’s regulated
utility operations, manage risk in its competitive
business, and reduce expenses.
Your Board provided an annual dividend rate of
$1.44 per share in 2015. As FirstEnergy addresses
future opportunities and challenges, we will continue
to review the dividend on a quarterly basis.
Your Board is committed to maintaining the
appropriate practices and policies that help ensure
good corporate governance. We also support
your management team as it focuses on ensuring
employee safety, providing outstanding service to
customers, enhancing the company’s environmental
performance, and delivering consistent and
predictable financial results.
I welcome Thomas N. Mitchell, who was elected
to serve on the company’s Board in January 2016.
Tom is a well-respected nuclear industry veteran
with 38 years of experience in the field, including
leadership positions at the World Association of
Nuclear Operators, the Institute of Nuclear Power
Operations, the Nuclear Energy Institute and the
Electric Power Research Institute.
Your Board remains dedicated to representing your
interests and enhancing the value of your investment
in FirstEnergy. Thank you for your ongoing support.
Sincerely,
George M. Smart,
Chairman of the Board
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.
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, CEO and
Director of Ontario
Power Generation Inc.
Ernest J. Novak, Jr.
Retired, formerly
Managing Partner of
the Cleveland office of
Ernst & Young LLP.
Christopher D.
Pappas
President and Chief
Executive Officer of
Trinseo S.A., formerly
Styron LLC (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
CEO of Dream Catcher
Educational Consulting
(higher education
coaching and professional
development). Retired
President of Cuyahoga
Community College.
F I R S T E N E R G Y C O R P. 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
Michael J. Dowling
Senior Vice President, External Affairs
Leila L. Vespoli
Executive Vice President, Markets and Chief Legal
Officer
Bennett L. Gaines
Senior Vice President, Corporate Services and
Chief Information 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
Charles D. Lasky
Senior Vice President, Human Resources
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 145 of this report.
8
2015
ANNUAL.REPORT
CONTENTS
i............... Glossary.of.Terms
1.............. Selected.Financial.Data
3............. Management’s.Discussion.and.Analysis
61............ Management.Reports
62........... Report.of.Independent.Registered.Public.Accounting.Firm
63........... Consolidated.Statements.of.Income
64........... Consolidated.Statements.of.Comprehensive.Income
65........... Consolidated.Balance.Sheets
66........... Consolidated.Statements.of.Common.Stockholders’.Equity
67........... Consolidated.Statements.of.Cash.Flows
68........... Notes.to.the.Consolidated.Financial.Statements
145.......... Executive.Officers.as.of.February.16,.2016
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AE
GLOSSARY OF TERMS
Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on
Unless the context requires otherwise, references to “we,” “us,” and “our” refer to FirstEnergy Corp. Additionally, the following
abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
Allegheny Energy Service Corporation, which provided legal, financial and other corporate support services to the
former AE subsidiaries
February 25, 2011, which subsequently merged with and into FE on January 1, 2014
AESC
AE Supply
AE
AGC
ATSI
AESC
Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on
Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP
February 25, 2011, which subsequently merged with and into FE on January 1, 2014
American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET
Allegheny Energy Service Corporation, which provided legal, financial and other corporate support services to the
in April 2012, which owns and operates transmission facilities
former AE subsidiaries
Buchanan Energy
AE Supply
Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply
Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
Buchanan Generation
AGC
Buchanan Generation, LLC, a joint venture between AE Supply and CNX Gas Corporation
Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP
CEI
ATSI
CES
Buchanan Energy
American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
in April 2012, which owns and operates transmission facilities
Competitive Energy Services, a reportable operating segment of FirstEnergy
Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply
FE
Buchanan Generation
FirstEnergy Corp., a public utility holding company
Buchanan Generation, LLC, a joint venture between AE Supply and CNX Gas Corporation
FELHC
CEI
FENOC
CES
FES
FE
FESC
FELHC
FET
FENOC
FES
FEV
FESC
FG
FET
FGMUC
FEV
FG
FirstEnergy
FGMUC
Global Holding
FirstEnergy
Global Rail
Global Holding
GPU
Global Rail
Green Valley
JCP&L
GPU
MAIT
Green Valley
ME
JCP&L
MP
MAIT
NG
ME
OE
MP
FELHC, Inc.
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
Competitive Energy Services, a reportable operating segment of FirstEnergy
FirstEnergy Solutions Corp., which provides energy-related products and services
FirstEnergy Corp., a public utility holding company
FirstEnergy Service Company, which provides legal, financial and other corporate support services
FELHC, Inc.
FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent of
FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
ATSI and TrAIL and has a joint venture in PATH
FirstEnergy Solutions Corp., which provides energy-related products and services
FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FirstEnergy Service Company, which provides legal, financial and other corporate support services
California Department of Water Resources
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
FirstEnergy Generation, LLC, a wholly-owned subsidiary of FES, which owns and operates non-nuclear generating
FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent of
facilities
ATSI and TrAIL and has a joint venture in PATH
FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FirstEnergy Generation Mansfield Unit 1 Corp., a wholly-owned subsidiary of FG, which owns various leasehold
interests in Bruce Mansfield Unit 1
FirstEnergy Generation, LLC, a wholly-owned subsidiary of FES, which owns and operates non-nuclear generating
FirstEnergy Corp., together with its consolidated subsidiaries
facilities
Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale
FirstEnergy Generation Mansfield Unit 1 Corp., a wholly-owned subsidiary of FG, which owns various leasehold
interests in Bruce Mansfield Unit 1
LLC
FirstEnergy Corp., together with its consolidated subsidiaries
Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup,
Montana
Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale
LLC
GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001
Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup,
Green Valley Hydro, LLC, which owned hydro generating stations
Montana
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001
Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, formed to own and operate transmission facilities
Green Valley Hydro, LLC, which owned hydro generating stations
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Monongahela Power Company, a West Virginia electric utility operating subsidiary
Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, formed to own and operate transmission facilities
FirstEnergy Nuclear Generation, LLC, a subsidiary of FES, which owns nuclear generating facilities
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
Monongahela Power Company, a West Virginia electric utility operating subsidiary
Ohio Edison Company, an Ohio electric utility operating subsidiary
NG
Ohio Companies
FirstEnergy Nuclear Generation, LLC, a subsidiary of FES, which owns nuclear generating facilities
CEI, OE and TE
OE
PATH
Ohio Edison Company, an Ohio electric utility operating subsidiary
Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
Ohio Companies
PATH-Allegheny
CEI, OE and TE
PATH Allegheny Transmission Company, LLC
PATH
PATH-WV
PATH-Allegheny
PE
Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH West Virginia Transmission Company, LLC
PATH Allegheny Transmission Company, LLC
The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary
AAA
AEP
AFS
AFUDC
ALJ
AMT
AOCI
Apple®
ARO
ARR
ASLB
ASU
BGS
BNSF
BRA
CAA
CBA
CCR
CDWR
CERCLA
CFL
CFR
CFTC
CO2
CONE
CPP
CSAPR
CSX
CTA
CWA
DCPD
DCR
DOE
DR
DSIC
DSP
EDC
EDCP
EE&C
EGS
ELPC
ENEC
EPA
EPRI
ERO
ESOP
ESP
ESTIP
American Arbitration Association
American Electric Power Company, Inc.
Available-for-sale
Allowance for Funds Used During Construction
Administrative Law Judge
Alternative Minimum Tax
Accumulated Other Comprehensive Income
Apple®, iPad® and iPhone® are registered trademarks of Apple Inc.
Asset Retirement Obligation
Auction Revenue Right
Atomic Safety and Licensing Board
Accounting Standards Update
Basic Generation Service
BNSF Railway Company
PJM RPM Base Residual Auction
Clean Air Act
Collective Bargaining Agreement
Coal Combustion Residuals
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
Delivery Capital Recovery
United States Department of Energy
Demand Response
Distribution System Improvement Charge
Default Service Plan
Electric Distribution Company
Executive Deferred Compensation Plan
Energy Efficiency and Conservation
Electric Generation Supplier
Environmental Law & Policy Center
Deferred Compensation Plan for Outside Directors
EMAAC
Eastern Mid-Atlantic Area Council of PJM
EmPOWER Maryland
EmPOWER Maryland Energy Efficiency Act
Expanded Net Energy Cost
United States Environmental Protection Agency
Electric Power Research Institute
Electric Reliability Organization
Employee Stock Ownership Plan
Electric Security Plan
Facebook®
FASB
Executive Short-Term Incentive Program
Facebook is a registered trademark of Facebook, Inc.
Financial Accounting Standards Board
Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
The Toledo Edison Company, an Ohio electric utility operating subsidiary
OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
West Penn Power Company, a Pennsylvania electric utility operating subsidiary
OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
West Penn Power Company, a Pennsylvania electric utility operating subsidiary
i
i
ii
PNBV Capital Trust, a special purpose entity created by OE in 1996
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
PNBV Capital Trust, a special purpose entity created by OE in 1996
PNBV
PN
Shippingport
PNBV
Signal Peak
Shippingport
Signal Peak
TE
TrAIL
TE
Utilities
TrAIL
WP
Utilities
WP
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
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 Electric Company, a Pennsylvania electric utility operating subsidiary
Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup,
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,
The Toledo Edison Company, an Ohio electric utility operating subsidiary
Montana
Pennsylvania Companies ME, PN, Penn and WP
Pennsylvania Companies ME, PN, Penn and WP
PATH West Virginia Transmission Company, LLC
Penn
PE
Penn
PN
Montana
PATH-WV
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
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
AE Supply
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
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., 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 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
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
facilities
LLC
Montana
GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001
Green Valley Hydro, LLC, which owned hydro generating stations
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
Global Rail
Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup,
Ohio Companies
CEI, OE and TE
PATH
Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH-Allegheny
PATH Allegheny Transmission Company, LLC
PATH-WV
PATH West Virginia Transmission Company, LLC
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
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
West Penn Power Company, a Pennsylvania electric utility operating subsidiary
i
AE
AESC
AGC
ATSI
CEI
CES
FE
FELHC
FENOC
FES
FESC
FET
FEV
FG
FGMUC
FirstEnergy
Global Holding
GPU
Green Valley
JCP&L
MAIT
ME
MP
NG
OE
PE
Penn
PN
PNBV
TE
TrAIL
Utilities
WP
Shippingport
Signal Peak
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AAA
AEP
AFS
AFUDC
ALJ
AMT
AOCI
Apple®
ARO
ARR
ASLB
ASU
BGS
BNSF
BRA
CAA
CBA
CCR
CDWR
CERCLA
CFL
CFR
CFTC
CO2
CONE
CPP
CSAPR
CSX
CTA
CWA
DCPD
DCR
DOE
DR
DSIC
DSP
EDC
EDCP
EE&C
EGS
ELPC
American Arbitration Association
American Electric Power Company, Inc.
Available-for-sale
Allowance for Funds Used During Construction
Administrative Law Judge
Alternative Minimum Tax
Accumulated Other Comprehensive Income
Apple®, iPad® and iPhone® are registered trademarks of Apple Inc.
Asset Retirement Obligation
Auction Revenue Right
Atomic Safety and Licensing Board
Accounting Standards Update
Basic Generation Service
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
United States Department of Energy
Demand Response
Distribution System Improvement Charge
Default Service Plan
Electric Distribution Company
Executive Deferred Compensation Plan
Energy Efficiency and Conservation
Electric Generation Supplier
Environmental Law & Policy Center
EMAAC
Eastern Mid-Atlantic Area Council of PJM
EmPOWER Maryland
EmPOWER Maryland Energy Efficiency Act
ENEC
EPA
EPRI
ERO
ESOP
ESP
ESTIP
Facebook®
FASB
Expanded Net Energy Cost
United States Environmental Protection Agency
Electric Power Research Institute
Electric Reliability Organization
Employee Stock Ownership Plan
Electric Security Plan
Executive Short-Term Incentive Program
Facebook is a registered trademark of Facebook, Inc.
Financial Accounting Standards Board
ii
FERC
Fitch
FMB
FPA
FTR
GAAP
GHG
GWH
HCl
IBEW
ICE
ICP 2007
ICP 2015
IRS
ISO
kV
KWH
KPI
LBR
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
Office and Professional Employees International Union
Greenhouse Gases
Gigawatt-hour
HydroChloric Acid
International Brotherhood of Electrical Workers
IntercontinentalExchange, Inc.
FirstEnergy Corp. 2007 Incentive Plan
FirstEnergy Corp. 2015 Incentive Compensation Plan
Internal Revenue Service
Independent System Operator
Kilovolt
Kilowatt-hour
Key Performance Indicator
Little Blue Run
LCAPP
Long-Term Capacity Agreement Pilot Program
LED
LMP
LOC
LSE
LTIIPs
MAAC
MATS
MDPSC
MISO
MLP
mmBTU
Moody’s
MVP
MW
MWD
MWH
NAAQS
NDT
NEIL
NERC
NGO
Ninth Circuit
NJBPU
NMB
NOL
NOV
NOx
NPDES
NPNS
NRC
NRG
NSR
NUG
NYISO
Light Emitting Diode
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
United States Court of Appeals for the Ninth Circuit
New Jersey Board of Public Utilities
Non-Market Based
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
iii
PJM Region
PJM Tariff
The aggregate of the zones within PJM
PJM Open Access Transmission Tariff
NYPSC
OCA
OCC
OEPA
OPEB
OPEIU
OTC
OTTI
OVEC
PA DEP
PCB
PCRB
PJM
PM
POLR
POR
PPA
PPB
PPUC
PSA
PSD
PTC
PUCO
PURPA
R&D
RCRA
REC
REIT
RFC
RFP
RGGI
RMR
ROE
RPM
RRS
RSS
RTEP
RTO
S&P
SAIDI
SAIFI
SB221
SB310
SBC
SEC
SERTP
SF6
SIP
SO2
SOS
New York State Public Service Commission
Office of Consumer Advocate
Ohio Consumers' Counsel
Ohio Environmental Protection Agency
Other Post-Employment Benefits
Over The Counter
Other-Than-Temporary Impairments
Ohio Valley Electric Corporation
Polychlorinated Biphenyl
Pollution Control Revenue Bond
PJM Interconnection, L.L.C.
Pennsylvania Department of Environmental Protection
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
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
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
State Implementation Plan(s) Under the Clean Air Act
Sulfur Hexafluoride
Sulfur Dioxide
Standard Offer Service
iv
Regulation FD
Regulation Fair Disclosure promulgated by the SEC
Seventh Circuit
United States Court of Appeals for the Seventh Circuit
LCAPP
Long-Term Capacity Agreement Pilot Program
ICP 2007
ICP 2015
FERC
Fitch
FMB
FPA
FTR
GAAP
GHG
GWH
HCl
IBEW
ICE
IRS
ISO
kV
KWH
KPI
LBR
LED
LMP
LOC
LSE
LTIIPs
MAAC
MATS
MDPSC
MISO
MLP
mmBTU
Moody’s
MVP
MW
MWD
MWH
NAAQS
NDT
NEIL
NERC
NGO
NMB
NOL
NOV
NOx
NPDES
NPNS
NRC
NRG
NSR
NUG
NYISO
Ninth Circuit
NJBPU
Accounting Principles Generally Accepted in the United States of America
Federal Energy Regulatory Commission
Fitch Ratings
First Mortgage Bond
Federal Power Act
Financial Transmission Right
Greenhouse Gases
Gigawatt-hour
HydroChloric Acid
International Brotherhood of Electrical Workers
IntercontinentalExchange, Inc.
FirstEnergy Corp. 2007 Incentive Plan
FirstEnergy Corp. 2015 Incentive Compensation Plan
Internal Revenue Service
Independent System Operator
Kilovolt
Kilowatt-hour
Key Performance Indicator
Little Blue Run
Light Emitting Diode
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
United States Court of Appeals for the Ninth Circuit
New Jersey Board of Public Utilities
Non-Market Based
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
iii
NYPSC
OCA
OCC
OEPA
OPEB
OPEIU
OTC
OTTI
OVEC
PA DEP
PCB
PCRB
PJM
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
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
RTO
S&P
SAIDI
SAIFI
SB221
SB310
SBC
SEC
SERTP
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
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
Sulfur Hexafluoride
State Implementation Plan(s) Under the Clean Air Act
Sulfur Dioxide
Standard Offer Service
iv
SPE
SREC
SSO
TDS
TMI-2
TO
TTS
Twitter®
Special Purpose Entity
Solar Renewable Energy Credit
Standard Service Offer
Total Dissolved Solid
Three Mile Island Unit 2
Transmission Owner
Temporary Transaction Surcharge
Twitter is a registered trademark of Twitter, Inc.
U.S. Court of Appeals for
the D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
UWUA
VIE
VRR
VSCC
WVDEP
WVPSC
Utility Workers Union of America
Variable Interest Entity
Variable Resource Requirement
Virginia State Corporation Commission
West Virginia Department of Environmental Protection
Public Service Commission of West Virginia
v
Special Purpose Entity
Solar Renewable Energy Credit
Standard Service Offer
Total Dissolved Solid
Three Mile Island Unit 2
Transmission Owner
Temporary Transaction Surcharge
Twitter is a registered trademark of Twitter, Inc.
U.S. Court of Appeals for
United States Court of Appeals for the District of Columbia Circuit
the D.C. Circuit
Utility Workers Union of America
Variable Interest Entity
Variable Resource Requirement
Virginia State Corporation Commission
West Virginia Department of Environmental Protection
Public Service Commission of West Virginia
SPE
SREC
SSO
TDS
TMI-2
TO
TTS
Twitter®
UWUA
VIE
VRR
VSCC
WVDEP
WVPSC
SELECTED FINANCIAL DATA
For the Years Ended December 31,
2015
2014
2013
2012
2011
Revenues
Income From Continuing Operations
Earnings Available to FirstEnergy Corp.
Earnings per Share of Common Stock:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Earnings Available to FirstEnergy Corp.
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Earnings 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)
15,255 $
755 $
770 $
15,049 $
213 $
299 $
14,892 $
375 $
392 $
15,026 $
578 $
578 $
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 $
1.81 $
0.04
1.85 $
1.80 $
0.04
1.84 $
422
424
1.44 $
52,187 $
420
421
1.44 $
51,648 $
418
419
1.65 $
50,058 $
418
419
2.20 $
50,175 $
12,422 $
19,192
31,614 $
12,422 $
19,176
31,598 $
12,695 $
15,831
28,526 $
13,093 $
15,179
28,272 $
16,087
856
885
2.19
0.03
2.22
2.18
0.03
2.21
399
401
2.20
47,410
13,299
15,716
29,015
(1)Reflects the application of ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all accumulated deferred income taxes to
be classified as non-current. The retrospective change decreased Total Assets as of December 31 as follows: 2014 - $518 million, 2013 -$366 million,
2012 - $319 million as these amounts were reclassified from current assets to non-current liabilities.
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
$
$
$
$
$
2015
2014
High
Low
High
Low
41.68 $
37.05 $
35.09 $
33.00 $
41.68 $
33.82 $
32.46 $
30.31 $
28.89 $
28.89 $
34.28 $
35.59 $
34.95 $
40.84 $
40.84 $
30.10
31.17
29.98
33.04
29.98
Closing prices are from http://finance.yahoo.com.
v
1
SHAREHOLDER RETURN
MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES
The following graph shows the total cumulative return from a $100 investment on December 31, 2010 in FirstEnergy’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 90,633 and 90,346 holders of 423,560,397 and 423,650,645 shares of FirstEnergy’s common stock as of December 31,
2015 and January 31, 2016, respectively. Information regarding retained earnings available for payment of cash dividends is given in
Note 11, Capitalization of the Combined Notes to Consolidated Financial Statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
2
3
Forward-Looking Statements: This report
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 speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in
particular.
The ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully
implement our sales strategy for the CES segment.
The accomplishment of our regulatory and operational goals in connection with our transmission investment plan, including
but not limited to, the proposed transmission asset transfer to MAIT, and the effectiveness of our strategy to reflect a more
• 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
regulated business profile.
opportunities.
The impact of the regulatory process on the pending 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 ESP IV in Ohio.
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, including FERC Opinion No. 531’s revised ROE methodology for FERC-jurisdictional
wholesale generation and transmission utility service;; 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.
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.
• 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 and asset valuations.
•
The continued ability of our regulated utilities to recover their costs.
• Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and
market prices.
• 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.
•
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).
The uncertainties associated with the deactivation of certain older regulated and competitive fossil units, including the
impact on vendor commitments 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.
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.
The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited
to, any such proceedings related to vendor commitments.
The impact of labor disruptions by our unionized workforce.
• Replacement power costs being higher than anticipated or not fully hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction
mandates.
• 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.
•
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
• Our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel
raising initiatives.
transportation on such margins.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES
Forward-Looking Statements: This report 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 speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in
particular.
The ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully
implement our sales strategy for the CES segment.
The accomplishment of our regulatory and operational goals in connection with our transmission investment plan, including
but not limited to, the proposed transmission asset transfer to MAIT, 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 impact of the regulatory process on the pending 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 ESP IV in Ohio.
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, including FERC Opinion No. 531’s revised ROE methodology for FERC-jurisdictional
wholesale generation and transmission utility service;; 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.
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.
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 and asset valuations.
The continued ability of our regulated utilities to recover their costs.
Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and
market prices.
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.
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).
The uncertainties associated with the deactivation of certain older regulated and competitive fossil units, including the
impact on vendor commitments 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.
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.
The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited
to, any such proceedings related to vendor commitments.
The impact of labor disruptions by our unionized workforce.
Replacement power costs being higher than anticipated or not fully hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction
mandates.
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.
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.
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.
3
• 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 material accounting policies.
• 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.
• 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, and increase requirements to post additional collateral to support outstanding
commodity positions, LOCs and other financial guarantees.
• 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 any changes in tax laws or regulations or adverse tax audit results or rulings.
•
Issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do
business.
• 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 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 of our Annual Report on Form 10-K filed with the SEC on February 16, 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
FE. 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.
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRSTENERGY’S BUSINESS
FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving
approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New
York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and
Maryland. This segment also includes regulated electric generation facilities located primarily in West Virginia, Virginia and New
Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing
electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls 3,790 MWs of
generation capacity.
The service areas of, and customers served by, FirstEnergy's regulated distribution utilities are summarized below (in thousands):
Company
OE
Penn
CEI
TE
JCP&L
ME
PN
WP
MP
PE
Area Served
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, 2015
Customers
Served (1)
1,038
1,109
164
746
308
561
588
723
390
401
6,028
The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, 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 rates that recover costs and provide a return on
transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are
primarily from transmission services provided pursuant to its PJM Tariff to LSEs. 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. This business segment currently controls 13,162 MWs of capacity. The CES segment’s net income is 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.
The CES segment expects to sell its annual generation output of approximately 75 to 80 million MWHs, with up to an additional 5
million MWHs available from PPAs for wind, solar and its entitlement from OVEC, through a target portfolio mix of approximately 10 to
15 million MWHs in Governmental Aggregation sales, 0 to 10 million MWHs of POLR sales, 0 to 20 million MWHs in large commercial
and industrial sales (Direct), 10 to 20 million MWHs in block wholesale sales, including Structured Sales, and 10 to 20 million MWHs
of spot wholesale sales.
Corporate support 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. As of
December 31, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to
variable-interest rates, and $1.7 billion was borrowed by FE under its revolving credit facility.
4
5
• 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 material accounting policies.
•
•
•
•
•
•
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.
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, and increase requirements to post additional collateral to support outstanding
commodity positions, LOCs and other financial guarantees.
• 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 any changes in tax laws or regulations or adverse tax audit results or rulings.
Issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do
business.
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 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 of our Annual Report on Form 10-K filed with the SEC on February 16, 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
FE. 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.
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRSTENERGY’S BUSINESS
FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving
approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New
York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and
Maryland. This segment also includes regulated electric generation facilities located primarily in West Virginia, Virginia and New
Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing
electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls 3,790 MWs of
generation capacity.
The service areas of, and customers served by, FirstEnergy's regulated distribution utilities are summarized below (in thousands):
Company
OE
Penn
CEI
TE
JCP&L
ME
PN
WP
MP
PE
Area Served
Customers
Served (1)
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
1,038
164
746
308
1,109
561
588
723
390
401
6,028
(1)
As of December 31, 2015
The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, 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 rates that recover costs and provide a return on
transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are
primarily from transmission services provided pursuant to its PJM Tariff to LSEs. 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. This business segment currently controls 13,162 MWs of capacity. The CES segment’s net income is 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.
The CES segment expects to sell its annual generation output of approximately 75 to 80 million MWHs, with up to an additional 5
million MWHs available from PPAs for wind, solar and its entitlement from OVEC, through a target portfolio mix of approximately 10 to
15 million MWHs in Governmental Aggregation sales, 0 to 10 million MWHs of POLR sales, 0 to 20 million MWHs in large commercial
and industrial sales (Direct), 10 to 20 million MWHs in block wholesale sales, including Structured Sales, and 10 to 20 million MWHs
of spot wholesale sales.
Corporate support 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. As of
December 31, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to
variable-interest rates, and $1.7 billion was borrowed by FE under its revolving credit facility.
4
5
EXECUTIVE SUMMARY
FirstEnergy continues to capitalize on investment opportunities available in its Regulated Transmission and Regulated Distribution
businesses while implementing a conservative hedging strategy at its Competitive business. FirstEnergy is focused on improving its
balance sheet and maintaining investment grade credit metrics at each business unit, while improving metrics at FirstEnergy over
time.
April 1, 2017.
Competitive Energy Services
Additionally, during 2015, the NJBPU issued orders on JCP&L’s base rate proceedings and its generic storm proceedings resulting in
a reduction of approximately $34 million in annual revenues, inclusive of recovery of 2011 and 2012 storm costs, as well as the
NJBPU’s recently modified CTA policy. As part of the base rate order, JCP&L is required to file another base rate case no later than
FirstEnergy’s regulated investment strategy focuses on delivering enhanced customer service and reliability, strengthening grid and
cyber-security, and adding resiliency and operating flexibility to its transmission and distribution infrastructure. Focusing on
reinvestment in its regulated operations will also provide stability and growth for FirstEnergy as this plan is implemented over the
coming years.
Regulated Transmission
The centerpiece of FirstEnergy’s regulated investment strategy is the Energizing the Future transmission expansion plan. The initial
phase of this plan includes $4.2 billion in investments from 2014 through 2017 to modernize FirstEnergy's transmission system.
In conjunction with its transmission expansion plan, in 2015 ATSI received FERC-approval of its "forward looking" rate, implemented
on January 1, 2015, where transmission rates are based on estimated costs for the current year with an annual true up, and an ROE
of: (i) 12.38% from January 1, 2015 through June 30, 2015;; (ii) 11.06% from July 1, 2015 through December 31, 2015;; and 10.38%
effective January 1, 2016, unless changed pursuant to Section 205 or 206 of the FPA, provided the effective date for any change
cannot be earlier than January 1, 2018.
Additionally, in June 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. If approved, MAIT will operate similar to FET’s
two existing stand-alone transmission subsidiaries ATSI and TrAIL. FERC approval is expected in March 2016 with final decisions
expected from the NJBPU and PPUC by mid-2016. Following FERC approval of the transfer, MAIT expects to file a Section 204
application with FERC, and other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET,
JCP&L, PN and ME for their respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application
with FERC to establish its transmission rate.
Regulated Distribution
During 2015, FirstEnergy continued to pursue key regulatory initiatives across its utility footprint, focusing on providing significant
benefits to customers while ensuring the timely and appropriate recovery of investments. These initiatives included:
Also, in 2015, PJM conducted the 2015 BRA for the 2018/2019 delivery year and Capacity Performance transition auctions for the
2016/2017 and 2017/2018 delivery years. FirstEnergy’s net competitive capacity position as a result of the BRA and Capacity
• The Ohio Companies' ESP IV, Powering Ohio’s Progress: The ESP IV, including the impact of filed stipulations in the case,
contemplates continuing a distribution rate freeze through May 2024 while helping ensure continued availability of more than
3,200 MWs of FirstEnergy’s critical baseload generating assets primarily located in the state and serving the long-term
energy needs of Ohio customers. Evidentiary hearings commenced in August 2015. On December 1, 2015, FirstEnergy's
Ohio Companies filed an additional settlement at the PUCO, which included the PUCO Staff as a signatory party, that sets
forth ambitious steps to help safeguard customers against retail generation price increases in future years, deploy new
energy efficiency programs, and provide a clear path to a cleaner energy future by establishing a goal to substantially
reduce carbon emissions. The settlement includes an eight-year rate provision (Rider RRS) designed to help protect
customers against rising retail price increases and market volatility, while helping preserve vital baseload power plants that
serve Ohio customers and provide thousands of family-sustaining jobs in the state. The plants involved include the Davis-
Besse Nuclear Power Station, the W.H. Sammis Plant, and a portion of the output of OVEC units in Gallipolis, Ohio, and
Madison, Indiana. A decision is anticipated in March 2016. On January 27, 2016, certain parties filed a complaint at FERC
against FES, OE, CEI, and TE that requests FERC review of the ESP IV PPA under Section 205 of the FPA. In addition to
such proceeding, parties have expressed an intention to challenge, in the courts and/or before FERC, the PPA or PUCO
approval of the ESP IV, if approved. Management intends to vigorously defend against such challenges.
•
•
Implementation of New Rates in Pennsylvania for ME, PN, Penn and WP: The new rates were approved in April 2015 and
went into effect in May 2015, providing for an increase in annual revenues of approximately $293 million and approximately
$88 million of additional annual operating expenses. Furthermore, in October 2015, the Pennsylvania companies filed
LTIIPs with the PPUC for infrastructure improvements over the 2016 to 2020 period totaling nearly $245 million, which were
approved on February 11, 2016. The Pennsylvania Companies filed DSIC riders on February 16, 2016, for quarterly cost
recovery associated with the projects approved in the LTIIPs.
Implementation of New Rates in West Virginia for MP and PE: The new rates were approved and went into effect in
February 2015, resulting in recovery of $63 million annually for reliability investments and expenses, storm damage
expenses, and investments in operating improvements and environmental compliance at MP’s and PE’s regulated coal-fired
power plants in West Virginia. MP and PE also received orders in December 2015 in their ENEC case and their biennial
vegetation management program surcharge reconciliation, resulting in revenue increases, effective January 1, 2016, totaling
$96.9 million and $36.7 million, respectively, to recover deferred costs.
6
7
FirstEnergy continues its strategy for its competitive business to more effectively hedge its generation by reducing exposure to
weather-sensitive load in certain sales channels and pursuing high-margin sales, while leaving a portion of its generation available to
capture future market opportunities or to mitigate risk. This strategy is designed to position CES to benefit from opportunities as
markets improve while limiting risk from continued challenging market conditions. At the same time, FirstEnergy continues to
advocate for reforms that can ensure competitive wholesale markets adequately value baseload generation, which is essential to
maintaining grid reliability.
The CES segment economically hedges exposure to price risk on a ratable basis, which is intended to reduce the near-term financial
impact of market price volatility. On average, the CES segment expects to produce approximately 75 - 80 million MWHs of electricity
annually, with up to an additional 5 million MWHs available from purchased power agreements for wind, solar and its entitlement from
OVEC. In 2015, CES sold approximately 75 million MWHs of which 68 million MWHs were through contract sales with another 7
million MWHs of wholesale sales. As of December 31, 2015, committed sales for 2016 and 2017 were approximately 61 million
MWHs and 38 million MWHs, respectively.
From a generation perspective, FirstEnergy continues to focus on ensuring its competitive fleet is cost-effective, efficient and
environmentally sound. FirstEnergy is on track to exceed benchmarks established by MATS and other environmental regulations.
FirstEnergy’s total cost for MATS compliance is expected to be approximately $345 million ($168 million at CES and $177 million at
Regulated Distribution), of which $202 million has been spent through December 31, 2015 ($80 million at CES and $122 million at
Regulated Distribution).
During 2015, FirstEnergy completed scheduled shutdowns for three of its nuclear units - Beaver Valley Unit 1 and Unit 2 and the
Perry Nuclear Power plant - for refueling and maintenance. During the outages, fuel assemblies were exchanged and numerous
inspections and preventative maintenance and improvement projects were completed to ensure continued safe and reliable
operations. Additionally, in December 2015, the NRC approved a 20-year license extension for the Davis-Besse Nuclear Power
Station allowing the unit to operate until 2037.
Performance transition auctions is as follows:
2016 - 2017
2017 - 2018
2018 - 2019*
Legacy
Obligation
Capacity
Performance
Legacy
Obligation
Capacity
Performance
Base
Generation
Capacity
Performance
(MW)
($/MWD)
(MW)
($/MWD)
(MW)
(MW)
($/MWD)
($/MWD)
(MW)
($/MWD)
($/MWD)
(MW)
2,765 $114.23 4,210
$134.00
375 $120.00 6,245 $151.50 —
$149.98 6,245
$164.77
$59.37 3,675
$134.00
985 $120.00 3,565 $151.50 240 $149.98 3,930
$164.77
$119.13 —
$134.00
150 $120.00 —
$151.50
35
**
20
**
ATSI
RTO
All Other
Zones
875
135
3,775
7,885
1,510
9,810
275
10,195
*Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year.
**Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at
$215.00/MWD and 15 MWs cleared at $164.77/MWD.
Projected CES Capacity Revenue* ($ Millions)
Capacity Revenue
2016
$815
2017
$590
2018
$620
(through 5/31)
2019
$260
*Includes revenues from the results of incremental/transitional capacity auctions, bilateral transactions and capacity transfer rights.
FirstEnergy continues to capitalize on investment opportunities available in its Regulated Transmission and Regulated Distribution
businesses while implementing a conservative hedging strategy at its Competitive business. FirstEnergy is focused on improving its
balance sheet and maintaining investment grade credit metrics at each business unit, while improving metrics at FirstEnergy over
FirstEnergy’s regulated investment strategy focuses on delivering enhanced customer service and reliability, strengthening grid and
cyber-security, and adding resiliency and operating flexibility to its transmission and distribution infrastructure. Focusing on
reinvestment in its regulated operations will also provide stability and growth for FirstEnergy as this plan is implemented over the
EXECUTIVE SUMMARY
time.
coming years.
Regulated Transmission
The centerpiece of FirstEnergy’s regulated investment strategy is the Energizing the Future transmission expansion plan. The initial
phase of this plan includes $4.2 billion in investments from 2014 through 2017 to modernize FirstEnergy's transmission system.
In conjunction with its transmission expansion plan, in 2015 ATSI received FERC-approval of its "forward looking" rate, implemented
on January 1, 2015, where transmission rates are based on estimated costs for the current year with an annual true up, and an ROE
of: (i) 12.38% from January 1, 2015 through June 30, 2015;; (ii) 11.06% from July 1, 2015 through December 31, 2015;; and 10.38%
effective January 1, 2016, unless changed pursuant to Section 205 or 206 of the FPA, provided the effective date for any change
cannot be earlier than January 1, 2018.
Additionally, in June 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. If approved, MAIT will operate similar to FET’s
two existing stand-alone transmission subsidiaries ATSI and TrAIL. FERC approval is expected in March 2016 with final decisions
expected from the NJBPU and PPUC by mid-2016. Following FERC approval of the transfer, MAIT expects to file a Section 204
application with FERC, and other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET,
JCP&L, PN and ME for their respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application
with FERC to establish its transmission rate.
Regulated Distribution
During 2015, FirstEnergy continued to pursue key regulatory initiatives across its utility footprint, focusing on providing significant
benefits to customers while ensuring the timely and appropriate recovery of investments. These initiatives included:
• The Ohio Companies' ESP IV, Powering Ohio’s Progress: The ESP IV, including the impact of filed stipulations in the case,
contemplates continuing a distribution rate freeze through May 2024 while helping ensure continued availability of more than
3,200 MWs of FirstEnergy’s critical baseload generating assets primarily located in the state and serving the long-term
energy needs of Ohio customers. Evidentiary hearings commenced in August 2015. On December 1, 2015, FirstEnergy's
Ohio Companies filed an additional settlement at the PUCO, which included the PUCO Staff as a signatory party, that sets
forth ambitious steps to help safeguard customers against retail generation price increases in future years, deploy new
energy efficiency programs, and provide a clear path to a cleaner energy future by establishing a goal to substantially
reduce carbon emissions. The settlement includes an eight-year rate provision (Rider RRS) designed to help protect
customers against rising retail price increases and market volatility, while helping preserve vital baseload power plants that
serve Ohio customers and provide thousands of family-sustaining jobs in the state. The plants involved include the Davis-
Besse Nuclear Power Station, the W.H. Sammis Plant, and a portion of the output of OVEC units in Gallipolis, Ohio, and
Madison, Indiana. A decision is anticipated in March 2016. On January 27, 2016, certain parties filed a complaint at FERC
against FES, OE, CEI, and TE that requests FERC review of the ESP IV PPA under Section 205 of the FPA. In addition to
such proceeding, parties have expressed an intention to challenge, in the courts and/or before FERC, the PPA or PUCO
approval of the ESP IV, if approved. Management intends to vigorously defend against such challenges.
•
Implementation of New Rates in Pennsylvania for ME, PN, Penn and WP: The new rates were approved in April 2015 and
went into effect in May 2015, providing for an increase in annual revenues of approximately $293 million and approximately
$88 million of additional annual operating expenses. Furthermore, in October 2015, the Pennsylvania companies filed
LTIIPs with the PPUC for infrastructure improvements over the 2016 to 2020 period totaling nearly $245 million, which were
approved on February 11, 2016. The Pennsylvania Companies filed DSIC riders on February 16, 2016, for quarterly cost
recovery associated with the projects approved in the LTIIPs.
•
Implementation of New Rates in West Virginia for MP and PE: The new rates were approved and went into effect in
February 2015, resulting in recovery of $63 million annually for reliability investments and expenses, storm damage
expenses, and investments in operating improvements and environmental compliance at MP’s and PE’s regulated coal-fired
power plants in West Virginia. MP and PE also received orders in December 2015 in their ENEC case and their biennial
vegetation management program surcharge reconciliation, resulting in revenue increases, effective January 1, 2016, totaling
$96.9 million and $36.7 million, respectively, to recover deferred costs.
Additionally, during 2015, the NJBPU issued orders on JCP&L’s base rate proceedings and its generic storm proceedings resulting in
a reduction of approximately $34 million in annual revenues, inclusive of recovery of 2011 and 2012 storm costs, as well as the
NJBPU’s recently modified CTA policy. As part of the base rate order, JCP&L is required to file another base rate case no later than
April 1, 2017.
Competitive Energy Services
FirstEnergy continues its strategy for its competitive business to more effectively hedge its generation by reducing exposure to
weather-sensitive load in certain sales channels and pursuing high-margin sales, while leaving a portion of its generation available to
capture future market opportunities or to mitigate risk. This strategy is designed to position CES to benefit from opportunities as
markets improve while limiting risk from continued challenging market conditions. At the same time, FirstEnergy continues to
advocate for reforms that can ensure competitive wholesale markets adequately value baseload generation, which is essential to
maintaining grid reliability.
The CES segment economically hedges exposure to price risk on a ratable basis, which is intended to reduce the near-term financial
impact of market price volatility. On average, the CES segment expects to produce approximately 75 - 80 million MWHs of electricity
annually, with up to an additional 5 million MWHs available from purchased power agreements for wind, solar and its entitlement from
OVEC. In 2015, CES sold approximately 75 million MWHs of which 68 million MWHs were through contract sales with another 7
million MWHs of wholesale sales. As of December 31, 2015, committed sales for 2016 and 2017 were approximately 61 million
MWHs and 38 million MWHs, respectively.
From a generation perspective, FirstEnergy continues to focus on ensuring its competitive fleet is cost-effective, efficient and
environmentally sound. FirstEnergy is on track to exceed benchmarks established by MATS and other environmental regulations.
FirstEnergy’s total cost for MATS compliance is expected to be approximately $345 million ($168 million at CES and $177 million at
Regulated Distribution), of which $202 million has been spent through December 31, 2015 ($80 million at CES and $122 million at
Regulated Distribution).
During 2015, FirstEnergy completed scheduled shutdowns for three of its nuclear units - Beaver Valley Unit 1 and Unit 2 and the
Perry Nuclear Power plant - for refueling and maintenance. During the outages, fuel assemblies were exchanged and numerous
inspections and preventative maintenance and improvement projects were completed to ensure continued safe and reliable
operations. Additionally, in December 2015, the NRC approved a 20-year license extension for the Davis-Besse Nuclear Power
Station allowing the unit to operate until 2037.
Also, in 2015, PJM conducted the 2015 BRA for the 2018/2019 delivery year and Capacity Performance transition auctions for the
2016/2017 and 2017/2018 delivery years. FirstEnergy’s net competitive capacity position as a result of the BRA and Capacity
Performance transition auctions is as follows:
2016 - 2017
2017 - 2018
2018 - 2019*
Legacy
Obligation
Capacity
Performance
Legacy
Obligation
Capacity
Performance
Base
Generation
Capacity
Performance
(MW)
($/MWD)
(MW)
2,765 $114.23 4,210
$59.37 3,675
875
$119.13 —
135
($/MWD)
$134.00
$134.00
$134.00
ATSI
RTO
All Other
Zones
($/MWD)
($/MWD)
(MW)
(MW)
(MW)
375 $120.00 6,245 $151.50 —
$149.98 6,245
985 $120.00 3,565 $151.50 240 $149.98 3,930
$151.50
150 $120.00 —
($/MWD)
20
35
**
(MW)
($/MWD)
$164.77
$164.77
**
3,775
7,885
1,510
9,810
275
10,195
*Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year.
**Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at
$215.00/MWD and 15 MWs cleared at $164.77/MWD.
Projected CES Capacity Revenue* ($ Millions)
Capacity Revenue
2016
$815
2017
$590
2018
$620
2019
(through 5/31)
$260
*Includes revenues from the results of incremental/transitional capacity auctions, bilateral transactions and capacity transfer rights.
6
7
CES
FirstEnergy continues to focus on maintaining the value of its competitive business and continues to advocate for reforms that ensure
the competitive wholesale markets adequately value baseload generation, which is essential for maintaining grid reliability. While it
cannot predict if or when a power price recovery may occur, FirstEnergy believes it has taken appropriate action over the last several
years to reposition this business for such a recovery. CES uses a conservative hedging strategy, and expects to sell its annual
generation resources of approximately 75-80 million MWHs through a combination of retail and wholesale sales, maintaining 10-20
million MWHs to mitigate risk in the event of unplanned outages or extreme weather or to take advantage of market upside
opportunities through the wholesale spot market.
STRATEGY AND OUTLOOK
FirstEnergy owns a large and diverse mix of assets managed in an integrated model, featuring an electric distribution service area
and transmission footprint that are among the largest in the nation, as well as a competitive operations segment that owns or controls
over 13,000 MWs of generation with a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other
renewables. FirstEnergy continues to focus on developing its transmission business, strengthening its regulated utilities, and
managing overall risk and conservatively operating its competitive business.
FirstEnergy continues to focus on investment opportunities in its Regulated Transmission and Regulated Distribution segments. This
investment strategy is focused on delivering enhanced customer service and reliability, strengthening grid and cyber-security, and
adding resiliency and operating flexibility to its transmission and distribution infrastructure. FirstEnergy expects to fund these
investments through a combination of cash from operations, debt, and, depending on the regulated operating company, capital
contributions from its parent. In the future, FirstEnergy may consider additional equity to fund capital requirements in its regulated
operations.
FirstEnergy's longer term strategic outlook for its regulated and competitive businesses will be determined following resolution of the
Ohio Companies' ESP IV, including the proposed PPA between FES and the Ohio Companies. Once the ESP IV is finalized,
FirstEnergy expects to be in a position to more fully understand the longer-term outlook of its competitive businesses and the longer
term growth rate of its regulated businesses, including planned capital investments and any additional equity to fund growth in its
regulated businesses.
FirstEnergy is focused on improving its balance sheet and maintaining investment grade credit metrics at each business unit, while
improving metrics at FirstEnergy Corp. over time. As part of an ongoing effort to manage costs, FirstEnergy identified both immediate
and long-term savings opportunities through its cash flow improvement plan. The cash flow improvement plan identified targeted cash
savings of approximately $58 million in 2015, $155 million in 2016 and $240 million annually by 2017, with reductions in operating
expenses representing approximately 65% of the savings over the three-year period.
Regulated Transmission
As noted above, the centerpiece of FirstEnergy’s growth strategy is a $4.2 billion investment in the Energizing the Future program
from 2014 through 2017. Through 2015, FirstEnergy's capital expenditures under this plan were $2.4 billion and in 2016 capital
expenditures under this plan are currently projected to be approximately $1 billion. This program is focused on a large number of
small projects within the company’s 24,000 mile service territory that improve service to customers. The projects within the program
are either regulatory required or support reliability enhancement. Regulatory required projects include those requested by PJM to
support grid reliability, generator deactivations, or shale gas expansion activities. The second category of projects, those that support
reliability enhancement, focus on replacing aging equipment;; increasing automation, communication, and security within the system;;
and increasing load serving capability. In the initial years of the program, the majority of the projects are located within the ATSI
system, with expectations to move east across FirstEnergy's service territory over time. An additional $15 billion in transmission
investment opportunities have been identified across the system beyond the 2014-2017 period, making this a continuing and
sustainable platform for investment.
In 2016, FirstEnergy expects to receive approval to transfer transmission assets of JCP&L, Met-Ed and Penelec to MAIT, a new
stand-alone transmission subsidiary.
Regulated Distribution
The five-state service territory served by FirstEnergy’s Regulated Distribution segment also offers substantial opportunities for future
investments to improve service to more than 6 million customers. In 2015, FirstEnergy completed major rate cases in West Virginia,
Pennsylvania and New Jersey. In Pennsylvania, a filing for an infrastructure improvement plan that includes an investment of $245
million through 2020 was approved by the PPUC on February 11, 2016, and in Ohio, a comprehensive settlement in the ESP IV is
pending PUCO approval. The ESP IV settlement contains additional opportunities for investment in the Ohio Companies, including
grid modernization and energy efficiency as well as continuation of Rider DCR with revenue caps increasing $180 million over the
term of the ESP IV. The settlement also includes a FERC-jurisdictional PPA where the Ohio Companies would purchase the output
from FES’ Davis-Besse nuclear plant, Sammis coal plant and entitlement to OVEC generation output, a total of 3,244 MW, for an
eight-year term beginning June 1, 2016.
FirstEnergy also continues to closely monitor sales trends across its utility footprint. Within its Regulated Distribution segment,
FirstEnergy continues to be impacted by lower customer usage as a result of energy efficiency mandates and products. During 2015,
electric distribution deliveries on a weather-adjusted basis declined 1.6% in the residential customer class and 0.6% in the
commercial customer class as compared to 2014. Furthermore, in the industrial sector, increases in the shale gas sector were more
than offset with lower usage in the steel and mining sectors, resulting in an overall decrease in the industrial sector of 2.0%.
8
9
CES
FirstEnergy continues to focus on maintaining the value of its competitive business and continues to advocate for reforms that ensure
the competitive wholesale markets adequately value baseload generation, which is essential for maintaining grid reliability. While it
cannot predict if or when a power price recovery may occur, FirstEnergy believes it has taken appropriate action over the last several
years to reposition this business for such a recovery. CES uses a conservative hedging strategy, and expects to sell its annual
generation resources of approximately 75-80 million MWHs through a combination of retail and wholesale sales, maintaining 10-20
million MWHs to mitigate risk in the event of unplanned outages or extreme weather or to take advantage of market upside
opportunities through the wholesale spot market.
STRATEGY AND OUTLOOK
FirstEnergy owns a large and diverse mix of assets managed in an integrated model, featuring an electric distribution service area
and transmission footprint that are among the largest in the nation, as well as a competitive operations segment that owns or controls
over 13,000 MWs of generation with a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other
renewables. FirstEnergy continues to focus on developing its transmission business, strengthening its regulated utilities, and
managing overall risk and conservatively operating its competitive business.
FirstEnergy continues to focus on investment opportunities in its Regulated Transmission and Regulated Distribution segments. This
investment strategy is focused on delivering enhanced customer service and reliability, strengthening grid and cyber-security, and
adding resiliency and operating flexibility to its transmission and distribution infrastructure. FirstEnergy expects to fund these
investments through a combination of cash from operations, debt, and, depending on the regulated operating company, capital
contributions from its parent. In the future, FirstEnergy may consider additional equity to fund capital requirements in its regulated
operations.
FirstEnergy's longer term strategic outlook for its regulated and competitive businesses will be determined following resolution of the
Ohio Companies' ESP IV, including the proposed PPA between FES and the Ohio Companies. Once the ESP IV is finalized,
FirstEnergy expects to be in a position to more fully understand the longer-term outlook of its competitive businesses and the longer
term growth rate of its regulated businesses, including planned capital investments and any additional equity to fund growth in its
regulated businesses.
FirstEnergy is focused on improving its balance sheet and maintaining investment grade credit metrics at each business unit, while
improving metrics at FirstEnergy Corp. over time. As part of an ongoing effort to manage costs, FirstEnergy identified both immediate
and long-term savings opportunities through its cash flow improvement plan. The cash flow improvement plan identified targeted cash
savings of approximately $58 million in 2015, $155 million in 2016 and $240 million annually by 2017, with reductions in operating
expenses representing approximately 65% of the savings over the three-year period.
Regulated Transmission
As noted above, the centerpiece of FirstEnergy’s growth strategy is a $4.2 billion investment in the Energizing the Future program
from 2014 through 2017. Through 2015, FirstEnergy's capital expenditures under this plan were $2.4 billion and in 2016 capital
expenditures under this plan are currently projected to be approximately $1 billion. This program is focused on a large number of
small projects within the company’s 24,000 mile service territory that improve service to customers. The projects within the program
are either regulatory required or support reliability enhancement. Regulatory required projects include those requested by PJM to
support grid reliability, generator deactivations, or shale gas expansion activities. The second category of projects, those that support
reliability enhancement, focus on replacing aging equipment;; increasing automation, communication, and security within the system;;
and increasing load serving capability. In the initial years of the program, the majority of the projects are located within the ATSI
system, with expectations to move east across FirstEnergy's service territory over time. An additional $15 billion in transmission
investment opportunities have been identified across the system beyond the 2014-2017 period, making this a continuing and
In 2016, FirstEnergy expects to receive approval to transfer transmission assets of JCP&L, Met-Ed and Penelec to MAIT, a new
sustainable platform for investment.
stand-alone transmission subsidiary.
Regulated Distribution
The five-state service territory served by FirstEnergy’s Regulated Distribution segment also offers substantial opportunities for future
investments to improve service to more than 6 million customers. In 2015, FirstEnergy completed major rate cases in West Virginia,
Pennsylvania and New Jersey. In Pennsylvania, a filing for an infrastructure improvement plan that includes an investment of $245
million through 2020 was approved by the PPUC on February 11, 2016, and in Ohio, a comprehensive settlement in the ESP IV is
pending PUCO approval. The ESP IV settlement contains additional opportunities for investment in the Ohio Companies, including
grid modernization and energy efficiency as well as continuation of Rider DCR with revenue caps increasing $180 million over the
term of the ESP IV. The settlement also includes a FERC-jurisdictional PPA where the Ohio Companies would purchase the output
from FES’ Davis-Besse nuclear plant, Sammis coal plant and entitlement to OVEC generation output, a total of 3,244 MW, for an
eight-year term beginning June 1, 2016.
FirstEnergy also continues to closely monitor sales trends across its utility footprint. Within its Regulated Distribution segment,
FirstEnergy continues to be impacted by lower customer usage as a result of energy efficiency mandates and products. During 2015,
electric distribution deliveries on a weather-adjusted basis declined 1.6% in the residential customer class and 0.6% in the
commercial customer class as compared to 2014. Furthermore, in the industrial sector, increases in the shale gas sector were more
than offset with lower usage in the steel and mining sectors, resulting in an overall decrease in the industrial sector of 2.0%.
8
9
FINANCIAL OVERVIEW
(In millions, except per share amounts)
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 long-lived assets
Total operating expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Loss on debt redemptions
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total other expense
For the Years Ended December 31,
2014
15,049 $
2015
15,026 $
2013
14,892 $
$
Increase (Decrease)
2015 vs 2014
(23 )
— % $
2014 vs 2013
157
1 %
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 $255 million and $73 million, respectively.
• 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 the FERC-approved settlement discussed above.
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
INCOME FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of
$0, $69 and $9, respectively) (Note 19)
NET INCOME
EARNINGS PER SHARE OF COMMON
STOCK:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Net Income
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Net Income
$
$
$
$
$
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
(8 )
72
—
(1,073 )
118
(891 )
171
(42 )
213
2,496
3,963
3,593
(256 )
1,202
539
978
795
13,310
1,582
(132 )
33
—
(1,016 )
103
(1,012 )
570
195
375
(425 )
(398 )
(213 )
(593 )
62
256
16
42
(1,253 )
1,230
(19 )%
(8 )%
(5 )%
(71 )%
5 %
2,133 %
2 %
— %
(9 )%
116 %
8
(94 )
(362 )
(59 )
(1 )
(508 )
722
357
365
(100 )%
(131 )%
— %
5 %
(1 )%
57 %
422 %
(850 )%
171 %
(216 )
753
369
1,091
18
(527 )
(16 )
(795 )
677
(520 )
124
39
—
(57 )
15
121
(399 )
(237 )
(162 )
(9 )%
19 %
10 %
(426 )%
1 %
(98 )%
(2 )%
(100 )%
5 %
(33 )%
(94 )%
118 %
— %
6 %
15 %
(12 )%
(70 )%
(122 )%
(43 )%
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, mark-to-market and retail-related costs partially offset by higher nuclear planned outage costs, partially offset
by an increase at Regulated Distribution, resulting from higher network transmission expenses, which are recovered through
transmission rates as discussed above, 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, 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 a
change in accounting method with the IRS 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
—
86
17
(86 )
(100 )%
69
406 %
tax expense of $25 million that related to prior periods resulting from adjustments to its tax basis balance sheet.
578 $
299 $
392 $
279
93 % $
(93 )
(24 )%
2014 compared with 2013
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 $
0.86
(0.20 )
0.66
0.86
(0.20 )
0.66
169 % $
(100 )%
93 % $
169 % $
(100 )%
93 % $
(0.39 )
0.16
(0.23 )
(0.39 )
0.16
(0.23 )
(43 )%
400 %
(24 )%
(43 )%
400 %
(24 )%
FirstEnergy’s net income in 2015 was $578 million, or basic and diluted earnings of $1.37 per share of common stock, compared with
$299 million, or basic and diluted earnings of $0.71 per share of common stock in 2014, and $392 million, or basic and diluted
earnings of $0.94 per share of common stock in 2013. Highlights of the key changes in year-over-year financial results are included
below:
2015 compared with 2014
As further discussed below, 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, $153 million at Regulated Distribution and $75 million at
Regulated Transmission, partially offset by a $369 million decrease at Corporate/Other.
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 $523 million increase at Regulated Distribution and a $242 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
discussed above, 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 retail generation revenue, resulting from a lower number of customers
shopping with an alternative generation supplier and higher retail transmission revenue, which is recovering higher
transmission related expenses. Distribution deliveries decreased 0.8%, or 1.1 million MWHs, as weather adjusted sales
declined as a result of energy efficiency mandates and products and decreases in certain industrial sectors, partially offset
by an increase in weather-related sales.
10
11
FirstEnergy’s 2014 income from continuing operations decreased $162 million as compared to 2013 resulting from a year-over-year
decline of $182 million at CES and $36 million at Regulated Distribution, partially offset by a year-over-year improvement at
Regulated Transmission of $9 million and $47 million at Corporate/Other.
In 2014, FirstEnergy’s revenue increased $157 million compared to 2013. The increase resulted from a $382 million increase at
Regulated Distribution and a $38 million increase at Regulated Transmission, partially offset by a decrease in CES revenues of $209
million.
expenses.
2013.
• The increase in revenue at Regulated Distribution resulted from higher wholesale generation sales associated with the
Harrison/Pleasants asset transfer whereby MP acquired 1,476 MWs of generation from AE Supply.
• The increase at Regulated Transmission primarily reflected a higher rate base and recovery of incremental operating
• The decrease at CES resulted from lower contract sales as in 2014, CES began to reduce its exposure to weather sensitive
load to more effectively hedge its generation, targeting annual contract sales of 65 to 75 million MWHs as compared to the
109 million MWHs sold in 2013. This change in strategy resulted in a 9% decrease in MWH sales in 2014 as compared to
Operating expenses increased $677 million in 2014 compared to 2013, including a $1,091 million increase in FirstEnergy’s Pension
and OPEB mark-to-market adjustment, primarily reflecting an increase at Regulated Distribution of $428 million, CES of $265 million
and Regulated Transmission of $40 million.
Changes in certain operating expenses include the following:
• Lower fuel expense of $216 million, primarily reflected the deactivation of power plants in 2013 and increased outages. Fuel
expense at CES and Regulated Distribution was further impacted by the October 2013 Harrison/Pleasants asset transfer.
• Purchased power increased $753 million, primarily reflecting higher CES purchases resulting from plant deactivations,
increased outages and the asset transfer discussed above as well as higher unit pricing and capacity expense. The
increase in unit pricing primarily resulted from market conditions associated with the extreme weather events in the first
quarter of 2014, which included the polar vortex.
• Other operating expenses increased $369 million primarily resulting from higher costs at Regulated Distribution associated
with network transmission expenses, increased vegetation management expenses in West Virginia, as well as higher
operating and maintenance associated with reliability improvements, storm restoration costs and the Harrison/Pleasants
(In millions, except per share amounts)
2015
2014
2013
2015 vs 2014
2014 vs 2013
For the Years Ended December 31,
Increase (Decrease)
$
15,026 $
15,049 $
14,892 $
(23 )
— % $
157
1 %
FINANCIAL OVERVIEW
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 long-lived assets
Total operating expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Loss on debt redemptions
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total other expense
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
INCOME FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of
$0, $69 and $9, respectively) (Note 19)
NET INCOME
EARNINGS PER SHARE OF COMMON
STOCK:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Net Income
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Net Income
$
$
$
$
$
below:
2015 compared with 2014
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
(8 )
72
—
(1,073 )
118
(891 )
171
(42 )
213
2,496
3,963
3,593
(256 )
1,202
539
978
795
13,310
1,582
(132 )
33
—
(1,016 )
103
(1,012 )
570
195
375
(425 )
(398 )
(213 )
(593 )
62
256
16
42
(1,253 )
1,230
(19 )%
(8 )%
(5 )%
(71 )%
5 %
2,133 %
2 %
— %
(9 )%
116 %
8
(94 )
(362 )
(59 )
(1 )
(508 )
722
357
365
(100 )%
(131 )%
— %
5 %
(1 )%
57 %
422 %
(850 )%
171 %
(216 )
753
369
1,091
18
(527 )
(16 )
(795 )
677
(520 )
124
39
—
(57 )
15
121
(399 )
(237 )
(162 )
(9 )%
19 %
10 %
(426 )%
1 %
(98 )%
(2 )%
(100 )%
5 %
(33 )%
(94 )%
118 %
— %
6 %
15 %
(12 )%
(70 )%
(122 )%
(43 )%
—
86
17
(86 )
(100 )%
69
406 %
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 $
0.86
(0.20 )
0.66
0.86
(0.20 )
0.66
169 % $
(100 )%
93 % $
169 % $
(100 )%
93 % $
(0.39 )
0.16
(0.23 )
(0.39 )
0.16
(0.23 )
(43 )%
400 %
(24 )%
(43 )%
400 %
(24 )%
FirstEnergy’s net income in 2015 was $578 million, or basic and diluted earnings of $1.37 per share of common stock, compared with
$299 million, or basic and diluted earnings of $0.71 per share of common stock in 2014, and $392 million, or basic and diluted
earnings of $0.94 per share of common stock in 2013. Highlights of the key changes in year-over-year financial results are included
As further discussed below, 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, $153 million at Regulated Distribution and $75 million at
Regulated Transmission, partially offset by a $369 million decrease at Corporate/Other.
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 $523 million increase at Regulated Distribution and a $242 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
discussed above, 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 retail generation revenue, resulting from a lower number of customers
shopping with an alternative generation supplier and higher retail transmission revenue, which is recovering higher
transmission related expenses. Distribution deliveries decreased 0.8%, or 1.1 million MWHs, as weather adjusted sales
declined as a result of energy efficiency mandates and products 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 the 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 $255 million and $73 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, mark-to-market and retail-related costs partially offset by higher nuclear planned outage costs, partially offset
by an increase at Regulated Distribution, resulting from higher network transmission expenses, which are recovered through
transmission rates as discussed above, 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, 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 a
change in accounting method with the IRS 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.
578 $
299 $
392 $
279
93 % $
(93 )
(24 )%
2014 compared with 2013
FirstEnergy’s 2014 income from continuing operations decreased $162 million as compared to 2013 resulting from a year-over-year
decline of $182 million at CES and $36 million at Regulated Distribution, partially offset by a year-over-year improvement at
Regulated Transmission of $9 million and $47 million at Corporate/Other.
In 2014, FirstEnergy’s revenue increased $157 million compared to 2013. The increase resulted from a $382 million increase at
Regulated Distribution and a $38 million increase at Regulated Transmission, partially offset by a decrease in CES revenues of $209
million.
• The increase in revenue at Regulated Distribution resulted from higher wholesale generation sales associated with the
Harrison/Pleasants asset transfer whereby MP acquired 1,476 MWs of generation from AE Supply.
• The increase at Regulated Transmission primarily reflected a higher rate base and recovery of incremental operating
expenses.
• The decrease at CES resulted from lower contract sales as in 2014, CES began to reduce its exposure to weather sensitive
load to more effectively hedge its generation, targeting annual contract sales of 65 to 75 million MWHs as compared to the
109 million MWHs sold in 2013. This change in strategy resulted in a 9% decrease in MWH sales in 2014 as compared to
2013.
Operating expenses increased $677 million in 2014 compared to 2013, including a $1,091 million increase in FirstEnergy’s Pension
and OPEB mark-to-market adjustment, primarily reflecting an increase at Regulated Distribution of $428 million, CES of $265 million
and Regulated Transmission of $40 million.
Changes in certain operating expenses include the following:
• Lower fuel expense of $216 million, primarily reflected the deactivation of power plants in 2013 and increased outages. Fuel
expense at CES and Regulated Distribution was further impacted by the October 2013 Harrison/Pleasants asset transfer.
• Purchased power increased $753 million, primarily reflecting higher CES purchases resulting from plant deactivations,
increased outages and the asset transfer discussed above as well as higher unit pricing and capacity expense. The
increase in unit pricing primarily resulted from market conditions associated with the extreme weather events in the first
quarter of 2014, which included the polar vortex.
• Other operating expenses increased $369 million primarily resulting from higher costs at Regulated Distribution associated
with network transmission expenses, increased vegetation management expenses in West Virginia, as well as higher
operating and maintenance associated with reliability improvements, storm restoration costs and the Harrison/Pleasants
10
11
asset transfer. CES' increase in other operating expenses was primarily attributable to higher transmission costs, which
resulted from the market conditions associated with the extreme weather events in the first quarter of 2014, and higher
mark-to-market expenses on derivative contracts, partially offset by lower generation operating and maintenance costs
primarily resulting from the deactivation of generating plants and the Harrison/Pleasants asset transfer.
Summary of Results of Operations — 2015 Compared with 2014
Financial results for FirstEnergy’s business segments in 2015 and 2014 were as follows:
FirstEnergy’s other expenses decreased $121 million year-over-year, primarily resulting from the absence of a loss on debt
redemptions of $124 million recognized in 2013. Higher interest expense was offset by higher investment income and capitalized
financing costs, primarily attributable to Regulated Transmission’s Energizing the Future investment plan.
FirstEnergy’s effective tax rate on income from continuing operations was (24.6)% compared to 34.2% in 2013. The decrease in the
effective tax rate was attributable to tax benefits recognized in 2014 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 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.
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 18, 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 2015, management concluded that FEV's 33-1/3% equity investment in Global Holding was no longer a
strategic asset to CES. Because of this decision, the segment reporting was modified to reflect how management now views and
makes investment decisions regarding CES and Global Holding. 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 2014 and 2013 have been
reclassified to conform to the current presentation reflecting the activity of FEV's investment in Global Holding in Corporate/Other.
Net income by business segment was as follows:
Net Income (Loss) By Business Segment:
Regulated Distribution
Regulated Transmission
Competitive Energy Services
Corporate/Other (1)
Net Income
Basic Earnings Per Share:
Continuing operations
Discontinued operations (Note 19)
Earnings per basic share
Diluted Earnings Per Share:
Continuing operations
Discontinued operations (Note 19)
Earnings per diluted share
2015
618 $
298
89
(427 )
578 $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
$
$
$
$
$
$
2014
2015 vs 2014
(In millions, except per share amounts)
2013
2014 vs 2013
Increase (Decrease)
Operating Income
465 $
223
(331 )
(58 )
299 $
0.51 $
0.20
0.71 $
0.51 $
0.20
0.71 $
501 $
214
(218 )
(105 )
392 $
0.90 $
0.04
0.94 $
0.90 $
0.04
0.94 $
153 $
75
420
(369 )
279 $
0.86 $
(0.20 )
0.66 $
0.86 $
(0.20 )
0.66 $
(36 )
9
(113 )
47
(93 )
(0.39 )
0.16
(0.23 )
(0.39 )
0.16
(0.23 )
(1) Consists primarily of interest on stand-alone holding company debt, none-core business related activity and corporate income taxes.
12
13
2015 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Other Income (Expense):
Loss on debt redemptions
Investment income (loss)
Interest expense
Capitalized financing costs
Total Other Expense
Impairment of equity method investment
Income From Continuing Operations Before
Income Taxes
Income taxes
Income From Continuing Operations
Discontinued Operations, net of tax
Net Income
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
$
9,429 $
196
—
9,625
1,011 $
—
—
1,011
4,493 $
205
686
5,384
(173 ) $
(135 )
(686 )
(994 )
533
3,548
2,242
179
672
261
703
8
8,146
1,479
—
42
—
(586 )
25
(519 )
960
342
618
—
—
—
154
3
156
7
102
—
422
589
—
—
—
(161 )
44
(117 )
472
174
298
—
1,322
1,456
1,670
60
394
—
140
34
5,076
308
—
(16 )
—
(192 )
39
(169 )
139
50
89
—
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
—
(686 )
(317 )
—
60
—
33
—
(910 )
(84 )
—
(48 )
(362 )
(193 )
9
(594 )
(678 )
(251 )
(427 )
—
$
618 $
298 $
89 $
(427 ) $
asset transfer. CES' increase in other operating expenses was primarily attributable to higher transmission costs, which
resulted from the market conditions associated with the extreme weather events in the first quarter of 2014, and higher
Summary of Results of Operations — 2015 Compared with 2014
mark-to-market expenses on derivative contracts, partially offset by lower generation operating and maintenance costs
Financial results for FirstEnergy’s business segments in 2015 and 2014 were as follows:
primarily resulting from the deactivation of generating plants and the Harrison/Pleasants asset transfer.
2015 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
makes investment decisions regarding CES and Global Holding. The external segment reporting is consistent with the internal
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Increase (Decrease)
Operating Income
Other Income (Expense):
Loss on debt redemptions
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total Other Expense
FirstEnergy’s other expenses decreased $121 million year-over-year, primarily resulting from the absence of a loss on debt
redemptions of $124 million recognized in 2013. Higher interest expense was offset by higher investment income and capitalized
financing costs, primarily attributable to Regulated Transmission’s Energizing the Future investment plan.
FirstEnergy’s effective tax rate on income from continuing operations was (24.6)% compared to 34.2% in 2013. The decrease in the
effective tax rate was attributable to tax benefits recognized in 2014 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 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.
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 18, 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 2015, management concluded that FEV's 33-1/3% equity investment in Global Holding was no longer a
strategic asset to CES. Because of this decision, the segment reporting was modified to reflect how management now views and
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 2014 and 2013 have been
reclassified to conform to the current presentation reflecting the activity of FEV's investment in Global Holding in Corporate/Other.
Net income by business segment was as follows:
Net Income (Loss) By Business Segment:
Regulated Distribution
Regulated Transmission
Competitive Energy Services
Corporate/Other (1)
Net Income
Basic Earnings Per Share:
Continuing operations
Discontinued operations (Note 19)
Earnings per basic share
Diluted Earnings Per Share:
Continuing operations
Discontinued operations (Note 19)
Earnings per diluted share
2015
2014
2013
2015 vs 2014
2014 vs 2013
(In millions, except per share amounts)
$
618 $
465 $
501 $
298
89
(427 )
223
(331 )
(58 )
214
(218 )
(105 )
578 $
299 $
392 $
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 $
$
$
$
$
$
153 $
75
420
(369 )
279 $
0.86 $
(0.20 )
0.66 $
0.86 $
(0.20 )
0.66 $
(36 )
9
(113 )
47
(93 )
(0.39 )
0.16
(0.23 )
(0.39 )
0.16
(0.23 )
(1) Consists primarily of interest on stand-alone holding company debt, none-core business related activity and corporate income taxes.
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
$
9,429 $
196
—
9,625
1,011 $
—
—
1,011
4,493 $
205
686
5,384
(173 ) $
(135 )
(686 )
(994 )
533
3,548
2,242
179
672
261
703
8
8,146
1,479
—
42
—
(586 )
25
(519 )
—
—
154
3
156
7
102
—
422
589
—
—
—
(161 )
44
(117 )
1,322
1,456
1,670
60
394
—
140
34
5,076
308
—
(16 )
—
(192 )
39
(169 )
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
—
(686 )
(317 )
—
60
—
33
—
(910 )
(84 )
—
(48 )
(362 )
(193 )
9
(594 )
(678 )
(251 )
(427 )
—
(427 ) $
Income From Continuing Operations Before
Income Taxes
Income taxes
Income From Continuing Operations
Discontinued Operations, net of tax
Net Income
$
960
342
618
—
618 $
472
174
298
—
298 $
139
50
89
—
89 $
12
13
2014 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Loss on debt redemptions
Investment income
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total Other Expense
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
Changes Between 2015 and 2014 Financial
Results Increase (Decrease)
Regulated
Distribution
Regulated
Transmission
Corporate/Other
and
Reconciling
Adjustments
FirstEnergy
Consolidated
Competitive
Energy
Services
(In millions)
$
8,898 $
204
—
9,102
769 $
—
—
769
5,281 $
189
819
6,289
(193 ) $
(99 )
(819 )
(1,111 )
567
3,385
2,081
506
658
1
693
—
7,891
1,211
—
56
—
(589 )
14
(519 )
—
—
139
2
127
11
70
—
349
420
—
—
—
(131 )
55
(76 )
1,713
2,150
2,075
327
387
—
171
—
6,823
(534 )
(8 )
54
—
(189 )
37
(106 )
14,755
294
—
15,049
2,280
4,716
3,962
835
1,220
12
962
—
13,987
1,062
(8 )
72
—
(1,073 )
118
(891 )
171
(42 )
213
86
299
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Loss on debt redemptions
Investment income
Interest expense
Capitalized financing costs
Total Other Expense
Impairment of equity method investment
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)
$
531 $
(8 )
—
523
242 $
—
—
242
(788 ) $
16
(133 )
(905 )
20 $
(36 )
133
117
5
(28 )
—
(23 )
(425 )
(398 )
(213 )
(593 )
62
256
16
42
(1,253 )
1,230
8
(94 )
(362 )
(59 )
(1 )
(508 )
722
357
365
(86 )
279
—
133
16
—
12
—
5
—
166
(49 )
—
(10 )
(362 )
(29 )
(3 )
(404 )
(453 )
(84 )
(369 )
—
(34 )
163
161
(327 )
14
260
10
8
255
268
—
(14 )
—
3
11
—
268
115
153
—
—
—
15
1
29
(4 )
32
—
73
169
—
—
—
(30 )
(11 )
(41 )
128
53
75
—
(391 )
(694 )
(405 )
(267 )
7
—
(31 )
34
(1,747 )
842
8
(70 )
—
(3 )
2
(63 )
779
273
506
(86 )
$
153 $
75 $
420 $
(369 ) $
—
(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)
$
692
227
465
—
465 $
344
121
223
—
223 $
(640 )
(223 )
(417 )
86
(331 ) $
14
15
2014 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Loss on debt redemptions
Investment income
Interest expense
Capitalized financing costs
Total Other Expense
Impairment of equity method investment
Income (Loss) From Continuing Operations
Before Income Taxes (Benefits)
Income taxes (benefits)
Income (Loss) From Continuing Operations
Discontinued Operations, net of tax
$
8,898 $
769 $
5,281 $
(193) $
14,755
204
—
9,102
567
3,385
2,081
506
658
1
693
—
7,891
1,211
—
56
—
14
(589)
(519)
692
227
465
—
—
—
769
—
—
139
2
127
11
70
—
349
420
—
—
—
(131)
55
(76)
344
121
223
—
189
819
6,289
1,713
2,150
2,075
327
387
—
171
—
(8)
54
—
(189)
37
(106)
(640)
(223)
(417)
86
(99)
(819)
(1,111)
—
(819)
(333)
—
48
—
28
—
—
(38)
—
(164)
12
(190)
(225)
(167)
(58)
—
294
—
15,049
2,280
4,716
3,962
835
1,220
12
962
—
(8)
72
—
(1,073)
118
(891)
171
(42)
213
86
299
6,823
(1,076)
13,987
(534)
(35)
1,062
Net Income (Loss)
$
465 $
223 $
(331) $
(58) $
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
Changes Between 2015 and 2014 Financial
Results Increase (Decrease)
Regulated
Distribution
Regulated
Transmission
Corporate/Other
and
Reconciling
Adjustments
FirstEnergy
Consolidated
Competitive
Energy
Services
(In millions)
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Loss on debt redemptions
Investment income
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total Other Expense
$
531 $
(8 )
—
523
242 $
—
—
242
(788 ) $
16
(133 )
(905 )
20 $
(36 )
133
117
(34 )
163
161
(327 )
14
260
10
8
255
268
—
(14 )
—
3
11
—
—
—
15
1
29
(4 )
32
—
73
(391 )
(694 )
(405 )
(267 )
7
—
(31 )
34
(1,747 )
169
842
—
—
—
(30 )
(11 )
(41 )
128
53
75
—
75 $
8
(70 )
—
(3 )
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
8
(94 )
(362 )
(59 )
(1 )
(508 )
722
357
365
(86 )
279
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)
$
268
115
153
—
153 $
14
15
Regulated Distribution — 2015 Compared with 2014
The following table summarizes the price and volume factors contributing to the $107 million increase in generation revenues in 2015
compared to 2014:
Regulated Distribution's net income increased $153 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 operating companies.
Revenues —
The $523 million increase in total revenues resulted from the following sources:
Revenues by Type of Service
2015
2014
(Decrease)
For the Years Ended
December 31,
Increase
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Transmission sales:
Retail
Wholesale
Total transmission sales
Other
Total Revenues
$
3,993 $
3,694 $
299
(In millions)
4,303
508
4,811
513
112
625
196
9,625 $
4,043
661
4,704
352
148
500
204
9,102 $
260
(153 )
107
161
(36 )
125
(8 )
523
$
Distribution services revenues increased $299 million primarily resulting from approved base distribution rate increases in
Pennsylvania, effective May 3, 2015, and for 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
services revenues increased resulting from the Ohio Companies' Rider DCR and higher cost recovery for above market NUG costs
and certain energy efficiency programs for the Pennsylvania Companies, which was impacted by a rate increase in 2015. 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:
conditions in 2014.
Operating Expenses —
For the Years Ended
December 31,
Increase
energy prices.
Electric Distribution MWH Deliveries
2015
2014
(Decrease)
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 mandates 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 usage due, in part, to increasing energy efficiency mandates. 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.
Source of Change in Generation Revenues
Retail:
Change in prices
Effect of increase in sales volumes
$
Increase
(Decrease)
(In millions)
Wholesale:
Effect of decrease in sales volumes
Change in prices
Capacity revenue
Increase in Generation Revenues
$
146
114
260
(133 )
(75 )
55
(153 )
107
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 results.
Wholesale generation revenues decreased $153 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.
The increase in retail transmission revenues of $161 million was primarily due to an increase in the Ohio Companies' NMB
transmission rider revenues. The NMB rider recovers network transmission integration service costs from all distribution customers at
the Ohio Companies, with no material impact to earnings. The decrease in wholesale transmission revenues of $36 million primarily
relates to lower congestion revenue resulting from the impact of market conditions associated with the extreme weather and market
Total operating expenses increased $255 million primarily due to the following:
• Fuel expense decreased $34 million in 2015 primarily related to lower economic dispatch resulting from low spot market
• 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 results, and higher capacity
expense at MP, partially offset by lower purchases resulting from the termination of certain NUG contracts at JCP&L and PN.
16
17
Regulated Distribution — 2015 Compared with 2014
Regulated Distribution's net income increased $153 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 operating companies.
Revenues —
The $523 million increase in total revenues resulted from the following sources:
Revenues by Type of Service
2015
2014
(Decrease)
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Transmission sales:
Retail
Wholesale
Total transmission sales
Other
Total Revenues
For the Years Ended
December 31,
Increase
$
3,993 $
3,694 $
299
(In millions)
4,303
508
4,811
513
112
625
196
4,043
661
4,704
352
148
500
204
$
9,625 $
9,102 $
260
(153 )
107
161
(36 )
125
(8 )
523
Distribution services revenues increased $299 million primarily resulting from approved base distribution rate increases in
Pennsylvania, effective May 3, 2015, and for 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
services revenues increased resulting from the Ohio Companies' Rider DCR and higher cost recovery for above market NUG costs
and certain energy efficiency programs for the Pennsylvania Companies, which was impacted by a rate increase in 2015. 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)
Residential
Commercial
Industrial
Other
Total Electric Distribution MWH Deliveries
For the Years Ended
December 31,
Increase
(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 mandates 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 usage due, in part, to increasing energy efficiency mandates. 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.
The following table summarizes the price and volume factors contributing to the $107 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
(133 )
(75 )
55
(153 )
107
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 results.
Wholesale generation revenues decreased $153 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.
The increase in retail transmission revenues of $161 million was primarily due to an increase in the Ohio Companies' NMB
transmission rider revenues. The NMB rider recovers network transmission integration service costs from all distribution customers at
the Ohio Companies, with no material impact to earnings. The decrease in wholesale transmission revenues of $36 million primarily
relates to lower congestion revenue resulting from the impact of market conditions associated with the extreme weather and market
conditions in 2014.
Operating Expenses —
Total operating expenses increased $255 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 results, and higher capacity
expense at MP, partially offset by lower purchases resulting from the termination of certain NUG contracts at JCP&L and PN.
16
17
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 expense was flat in 2015 as compared to 2014, as lower investment income was offset by lower interest expense and higher
Other Expense —
capitalized financing costs.
Income Taxes —
Regulated Distribution’s effective tax rate was 35.6% and 32.8% 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.
Regulated Transmission — 2015 Compared with 2014
Net income increased $75 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 $242 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 calculation transitioned to a "forward looking" approach, where
transmission revenues are based on actual costs.
• Other operating expenses increased $161 million primarily due to:
Revenues by transmission asset owner are shown in the following table:
• 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, reflecting higher net benefit costs before the pension and OPEB
mark-to-market adjustment described below.
• Higher distribution operating and maintenance expenses of $54 million, reflecting increased reliability maintenance
in New Jersey and the Pennsylvania companies and other employee benefit costs, partially offset by lower storm
restoration costs.
Revenues by Transmission Asset Owner
2015
2014
Increase
For the Years Ended
December 31,
(In millions)
$
446 $
252
13
300
242 $
214
13
300
769 $
204
38
—
—
242
Total Revenues
$
1,011 $
• Pension and OPEB mark-to-market adjustment 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.
Total operating expenses increased $73 million principally due to higher operating and maintenance expenses, depreciation, and
property taxes at ATSI, which are recovered through ATSI's "forward looking" rate.
• Depreciation expense increased $14 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),
•
• 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).
Lower deferral of West Virginia vegetation management expenses ($31 million),
• General taxes increased $10 million primarily due to higher revenue-related taxes in Pennsylvania, partially offset by lower
related to coal and transportation contracts, and the absence of a $78 million after-tax gain on the sale of certain hydroelectric
property taxes in Ohio.
ATSI
TrAIL
PATH
Utilities
Operating Expenses —
Other Expenses —
Income Taxes —
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.
Regulated Transmission’s effective tax rate was 36.9% and 35.2% 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.
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 termination costs
facilities recognized in February 2014.
Revenues —
Total revenues decreased $905 million in 2015, compared to 2014, primarily due to decreased sales volumes in line with CES'
strategy to more effectively hedge its generation. 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.
18
19
Source of Change in Purchased Power
Purchases from non-affiliates:
Change due to increased unit costs
$
Change due to increased volumes
Increase
(Decrease)
(In millions)
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 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 32.8% 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.
Regulated Transmission — 2015 Compared with 2014
Net income increased $75 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 $242 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 calculation transitioned to a "forward looking" approach, where
transmission revenues are based on actual costs.
• Other operating expenses increased $161 million primarily due to:
Revenues by transmission asset owner are shown in the following table:
• 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, reflecting higher net benefit costs before the pension and OPEB
mark-to-market adjustment described below.
• Higher distribution operating and maintenance expenses of $54 million, reflecting increased reliability maintenance
in New Jersey and the Pennsylvania companies and other employee benefit costs, partially offset by lower storm
restoration costs.
Revenues by Transmission Asset Owner
2015
2014
Increase
For the Years Ended
December 31,
ATSI
TrAIL
PATH
Utilities
Total Revenues
Operating Expenses —
(In millions)
$
$
446 $
252
13
300
1,011 $
242 $
214
13
300
769 $
204
38
—
—
242
• Pension and OPEB mark-to-market adjustment 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.
Total operating expenses increased $73 million principally due to higher operating and maintenance expenses, depreciation, and
property taxes at ATSI, which are recovered through ATSI's "forward looking" rate.
• Depreciation expense increased $14 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
Other Expenses —
Pennsylvania based on updated asset life studies approved by the PPUC.
• Net regulatory asset amortization increased $260 million primarily due to:
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.
• Recovery of storm costs in New Jersey, Pennsylvania, and West Virginia effective with the implementation of new
Income Taxes —
Regulated Transmission’s effective tax rate was 36.9% and 35.2% 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.
• Higher amortizations of above-market NUG costs in Pennsylvania and New Jersey ($36 million),
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 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 in line with CES'
strategy to more effectively hedge its generation. 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.
18
19
rates as discussed above ($66 million),
• Higher energy efficiency program cost recovery ($66 million),
•
Lower deferral of TTS costs in West Virginia ($37 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 $10 million primarily due to higher revenue-related taxes in Pennsylvania, partially offset by lower
property taxes in Ohio.
The decrease in total revenues resulted from the following sources:
from lower year-over-year market prices. The Direct, Governmental Aggregation and Mass Market customer base was 1.6 million as
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,
2015
2014
(In millions)
Increase
(Decrease)
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 )
For the Years Ended
December 31,
2015
2014
(In thousands)
Increase
(Decrease)
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 )%
977.4 %
(24.6 )%
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
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 recent 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 higher capacity prices, 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 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.
• Nuclear operating costs increased $84 million as a result of higher planned outage costs and higher employee benefit
expenses. There were three planned refueling outages in 2015 as compared to two planned 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 decreased retail sales
volumes.
• Pension and OPEB mark-to-market adjustment 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 $212 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.
•
Impairments of long-lived assets increased $34 million due to impairment charges associated with non-core assets.
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 incurred in 2014.
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.
Other Expense —
Discontinued Operations —
Income Taxes (Benefits) —
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 reflect CES' efforts to more
effectively hedge its generation by reducing exposure to weather-sensitive load. 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
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.
20
21
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,
2015
2014
(In millions)
Increase
(Decrease)
$
1,269 $
1,012
2,359 $
1,184
265
712
558
3,816
1,225
138
205
452
902
522
5,419
461
220
189
$
5,384 $
6,289 $
(1,090 )
(1,603 )
(172 )
(187 )
(190 )
36
764
(82 )
16
(905 )
For the Years Ended
December 31,
2015
2014
(In thousands)
Increase
(Decrease)
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 )%
977.4 %
(24.6 )%
The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Revenues
Increase (Decrease)
Gain on
Settled
Contracts
(In millions)
MWH Sales Channel:
Sales
Volumes
Prices
Capacity
Revenue
Total
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Wholesale
$
(1,095 )
$
5 $
— $
— $ (1,090 )
(249 )
(193 )
(216 )
3
197
77
6
26
33
(8 )
—
—
—
—
107
—
—
—
—
468
(172 )
(187 )
(190 )
36
764
Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflect CES' efforts to more
effectively hedge its generation by reducing exposure to weather-sensitive load. 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 recent 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 higher capacity prices, 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 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.
• Nuclear operating costs increased $84 million as a result of higher planned outage costs and higher employee benefit
expenses. There were three planned refueling outages in 2015 as compared to two planned 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 decreased retail sales
volumes.
• Pension and OPEB mark-to-market adjustment 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 $212 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.
•
Impairments of long-lived assets increased $34 million 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 incurred 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 Taxes (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.
20
21
Corporate/Other — 2015 Compared with 2014
Financial results from 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 a $1 billion term loan entered into in
March 2014 and a gain on the termination of interest rate swap arrangements recognized 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.
Summary of Results of Operations — 2014 Compared with 2013
Financial results for FirstEnergy’s business segments in 2014 and 2013 were as follows:
2014 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (loss)
Other Income (Expense):
Loss on debt redemptions
Investment income
Interest expense
Capitalized interest
Total Other Expense
Income (Loss) From Continuing Operations
Before Income Taxes (Benefits)
Income taxes (benefits)
Income (Loss) From Continuing Operations
Discontinued Operations, net of tax
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
$
8,898 $
769 $
5,281 $
(193) $
14,755
204
—
9,102
567
3,385
2,081
506
658
1
693
—
7,891
1,211
—
56
14
(589)
(519)
692
227
465
—
—
—
769
—
—
139
2
127
11
70
—
349
420
—
—
(131)
55
(76)
344
121
223
—
189
819
6,289
1,713
2,150
2,075
327
387
—
171
—
(8)
54
(189)
37
(106)
(640)
(223)
(417)
86
(99)
(819)
(1,111)
—
(819)
(333)
—
48
—
28
—
—
(38)
(164)
12
(190)
(225)
(167)
(58)
—
294
—
15,049
2,280
4,716
3,962
835
1,220
12
962
—
(8)
72
(1,073)
118
(891)
171
(42)
213
86
299
6,823
(1,076)
13,987
(534)
(35)
1,062
Net Income (Loss)
$
465 $
223 $
(331) $
(58) $
22
23
Corporate/Other — 2015 Compared with 2014
Financial results from 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 a $1 billion term loan entered into in
March 2014 and a gain on the termination of interest rate swap arrangements recognized 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.
Summary of Results of Operations — 2014 Compared with 2013
Financial results for FirstEnergy’s business segments in 2014 and 2013 were as follows:
2014 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (loss)
Other Income (Expense):
Loss on debt redemptions
Investment income
Interest expense
Capitalized interest
Total Other Expense
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
$
8,898 $
204
—
9,102
769 $
—
—
769
5,281 $
189
819
6,289
(193 ) $
(99 )
(819 )
(1,111 )
567
3,385
2,081
506
658
1
693
—
7,891
1,211
—
56
(589 )
14
(519 )
—
—
139
2
127
11
70
—
349
420
—
—
(131 )
55
(76 )
344
121
223
—
223 $
1,713
2,150
2,075
327
387
—
171
—
6,823
(534 )
(8 )
54
(189 )
37
(106 )
—
(819 )
(333 )
—
48
—
28
—
(1,076 )
(35 )
—
(38 )
(164 )
12
(190 )
(640 )
(223 )
(417 )
86
(331 ) $
(225 )
(167 )
(58 )
—
(58 ) $
14,755
294
—
15,049
2,280
4,716
3,962
835
1,220
12
962
—
13,987
1,062
(8 )
72
(1,073 )
118
(891 )
171
(42 )
213
86
299
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)
$
692
227
465
—
465 $
22
23
2013 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Gain (loss) on debt redemptions
Investment income
Interest expense
Capitalized interest
Total Other Expense
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
(In millions)
$
8,499 $
221
—
8,720
731 $
—
—
731
5,542 $
186
770
6,498
(161 ) $
(126 )
(770 )
(1,057 )
377
3,308
1,773
(149 )
606
529
697
322
7,463
1,257
—
57
(543 )
31
(455 )
—
—
131
—
114
10
54
—
309
422
—
—
(93 )
14
(79 )
2,119
1,425
2,007
(107 )
439
—
202
473
6,558
(60 )
(149 )
14
(222 )
42
(315 )
14,611
281
—
14,892
2,496
3,963
3,593
(256 )
1,202
539
978
795
13,310
1,582
(132 )
33
(1,016 )
103
(1,012 )
570
195
375
17
392
—
(770 )
(318 )
—
43
—
25
—
(1,020 )
(37 )
17
(38 )
(158 )
16
(163 )
(200 )
(95 )
(105 )
—
(105 ) $
Income (Loss) From Continuing Operations
Before Income Taxes (Benefits)
Income taxes (benefits)
Income From Continuing Operations
Discontinued Operations, net of tax
Net Income (Loss)
$
802
301
501
—
501 $
343
129
214
—
214 $
(375 )
(140 )
(235 )
17
(218 ) $
24
2013 Financial Results
Revenues:
External
Electric
Other
Internal
Total Revenues
Operating Expenses:
Fuel
Purchased power
Other operating expenses
Pension and OPEB mark-to-market
Provision for depreciation
Amortization of regulatory assets, net
General taxes
Impairment of long-lived assets
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Gain (loss) on debt redemptions
Investment income
Interest expense
Capitalized interest
Total Other Expense
Income (Loss) From Continuing Operations
Before Income Taxes (Benefits)
Income taxes (benefits)
Income From Continuing Operations
Discontinued Operations, net of tax
Net Income (Loss)
$
8,499 $
221
—
8,720
731 $
—
—
731
5,542 $
186
770
6,498
(161 ) $
(126 )
(770 )
(1,057 )
377
3,308
1,773
(149 )
606
529
697
322
7,463
1,257
—
57
(543 )
31
(455 )
802
301
501
—
—
—
131
—
114
10
54
—
309
422
—
—
(93 )
14
(79 )
343
129
214
—
2,119
1,425
2,007
(107 )
439
—
202
473
6,558
(60 )
(149 )
14
(222 )
42
(315 )
(375 )
(140 )
(235 )
17
—
(770 )
(318 )
—
43
—
25
—
(1,020 )
(37 )
17
(38 )
(158 )
16
(163 )
(200 )
(95 )
(105 )
—
14,611
281
—
14,892
2,496
3,963
3,593
(256 )
1,202
539
978
795
13,310
1,582
(132 )
33
(1,016 )
103
(1,012 )
570
195
375
17
392
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/Other
and Reconciling
Adjustments
FirstEnergy
Consolidated
Changes Between 2014 and 2013 Financial Results
Increase (Decrease)
Changes Between 2014 and 2013 Financial Results
Increase (Decrease)
Regulated
Distribution
Regulated
Distribution
Regulated
Regulated
Transmission
Transmission
Competitive
Competitive
Energy
Energy
Services
Services
Corporate/Other
Corporate/Other
and Reconciling
and Reconciling
Adjustments
Adjustments
FirstEnergy
Consolidated
FirstEnergy
Consolidated
(In millions)
(In millions)
(In millions)
Revenues:
Revenues:
External
External
Electric
Electric
Other
Other
Internal
Internal
Total Revenues
Total Revenues
Operating Expenses:
Operating Expenses:
Fuel
Fuel
Purchased power
Purchased power
Other operating expenses
Other operating expenses
Pension and OPEB mark-to-market
Pension and OPEB mark-to-market
Provision for depreciation
Provision for depreciation
Amortization of regulatory assets, net
Amortization of regulatory assets, net
General taxes
General taxes
Impairment of long-lived assets
Impairment of long-lived assets
Total Operating Expenses
Total Operating Expenses
$
$
399 $
399 $
(17 )
(17 )
—
—
382
382
38 $
38 $
—
—
—
—
38
38
(261 ) $
(261 ) $
3
3
49
49
(209 )
(209 )
(32 ) $
(32 ) $
27
27
(49 )
(49 )
(54 )
(54 )
190
190
77
77
308
308
655
655
52
52
(528 )
(528 )
(4 )
(4 )
(322 )
(322 )
428
428
—
—
—
—
8
8
2
2
13
13
1
1
16
16
—
—
40
40
(406 )
(406 )
725
725
68
68
434
434
(52 )
(52 )
—
—
(31 )
(31 )
(473 )
(473 )
265
265
144
144
13
13
—
—
157
157
(216 )
(216 )
753
753
369
369
1,091
1,091
18
18
(527 )
(527 )
(16 )
(16 )
(795 )
677
(795 )
677
(520 )
(520 )
124
124
39
39
(57 )
(57 )
15
15
121
121
(399 )
(399 )
(237 )
(237 )
(162 )
(162 )
69
69
(93 )
(93 )
—
—
(49 )
(49 )
(15 )
(15 )
—
—
5
5
—
—
3
3
—
—
(56 )
(56 )
2
2
(17 )
(17 )
—
—
(6 )
(6 )
(4 )
(4 )
(27 )
(27 )
(25 )
(25 )
(72 )
(72 )
47
47
—
—
47 $
47 $
Operating Income (Loss)
Operating Income (Loss)
(46 )
(46 )
(2 )
(2 )
(474 )
(474 )
Other Income (Expense):
Other Income (Expense):
Loss on debt redemptions
Loss on debt redemptions
Investment income
Investment income
Interest expense
Interest expense
Capitalized interest
Capitalized interest
Total Other Expense
Total Other Expense
Income (Loss) From Continuing Operations Before
Income (Loss) From Continuing Operations Before
Income Taxes (Benefits)
Income Taxes (Benefits)
$
501 $
214 $
(218 ) $
(105 ) $
Net Income (Loss)
Net Income (Loss)
$
$
Income taxes (benefits)
Income taxes (benefits)
Income (Loss) From Continuing Operations
Income (Loss) From Continuing Operations
Discontinued Operations, net of tax
Discontinued Operations, net of tax
—
—
(1 )
(1 )
(46 )
(46 )
(17 )
(17 )
(64 )
(64 )
(110 )
(110 )
(74 )
(74 )
(36 )
(36 )
—
—
(36 ) $
(36 ) $
—
—
—
—
(38 )
(38 )
41
41
3
3
1
1
(8 )
(8 )
9
9
—
—
9 $
9 $
141
141
40
40
33
33
(5 )
(5 )
209
209
(265 )
(265 )
(83 )
(83 )
(182 )
(182 )
69
69
(113 ) $
(113 ) $
24
25
25
Regulated Distribution — 2014 Compared with 2013
The following table summarizes the price and volume factors contributing to the $415 million increase in generation revenues in 2014
compared to 2013:
Regulated Distribution's net income decreased $36 million in 2014 compared to 2013. Regulated Distribution's Pension and OPEB
mark-to-market adjustment increased $655 million which was partially offset by a reduction in regulatory asset impairment charges of
$305 million and an impairment of long-lived assets of $322 million incurred in 2013. Excluding the impact of these charges, year-
over-year earnings were impacted by higher distribution operating and maintenance costs, including the impact of higher benefit
costs, higher depreciation and property taxes, and higher interest expense from debt issuances. These items were partially offset by
slightly higher distribution deliveries, higher earnings associated with the October 2013 Harrison/Pleasants asset transfer, and a lower
effective tax rate.
Revenues —
The $382 million increase in total revenues resulted from the following sources:
Revenues by Type of Service
2014
2013
(Decrease)
For the Years Ended
December 31,
Increase
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Transmission sales:
Retail
Wholesale
Total transmission sales
Other
Total Revenues
$
3,694 $
3,762 $
(68 )
(In millions)
4,043
661
4,704
352
148
500
204
9,102 $
3,959
330
4,289
347
101
448
221
8,720 $
84
331
415
5
47
52
(17 )
382
$
The decrease in distribution services revenue is primarily related to a decrease in revenues from ME and PN NUG riders as a result
of the expiration of certain NUG contracts in 2013 and a rider rate decrease associated with the recovery of energy efficiency and
other customer program costs for the Pennsylvania Companies. This was partially offset by higher electric distribution MWH deliveries
of 1.1% as described below, rate increases for the Ohio Companies associated with energy efficiency performance shared savings
and the Rider DCR, and higher revenues for the Pennsylvania Companies associated with the recovery of Smart Meter program
costs. Certain Ohio energy efficiency programs permit the Ohio Companies to bill and collect shared savings revenues if energy
efficiency programs meet or exceed the state mandates. Additionally, the Rider DCR provides for recovery of incremental operating
expenses and a return on rate base associated with incremental distribution plant investments in Ohio. Distribution deliveries by
customer class are summarized in the following table:
For the Years Ended
December 31,
Electric Distribution MWH Deliveries
2014
2013
Increase
• Fuel expense was $190 million higher in 2014 primarily related to increased generation as a result of the October 2013
Residential
Commercial
Industrial
Other
Total Electric Distribution MWH Deliveries
(In thousands)
54,766
42,925
51,276
586
149,553
54,479
42,582
50,243
584
147,888
0.5 %
0.8 %
2.1 %
0.3 %
1.1 %
Higher deliveries to residential customers primarily reflect increased weather-related usage resulting from heating degree days that
were 7% above 2013, and 9% above normal, partially offset by cooling degree days that were 15% below 2013, and 12% below
normal. Increased deliveries to commercial customers reflect improving economic conditions across FirstEnergy's service territories.
In the industrial sector, increased sales to steel, automotive and shale gas customers were partially offset by lower sales to chemical
and paper customers.
26
27
Source of Change in Generation Revenues
Increase
(In millions)
Retail:
Change in prices
Effect of increase in sales volumes
$
Wholesale:
Effect of increase in sales volumes
Change in prices
Capacity revenue
Increase in Generation Revenues
$
14
70
84
166
79
86
331
415
The increase in retail generation sales volume was primarily due to weather-related usage, as described above, and improving
economic conditions, partially offset by increased customer shopping in Pennsylvania. The increase in retail generation prices reflects
higher Pennsylvania PTC prices, the completion of marginal transmission loss refunds to ME and PN customers in the second
quarter of 2013 and a higher generation rate at WP, which includes the recovery of transmission costs effective June 2013.
Additionally, the impact on retail generation prices of MP's Temporary Transaction Surcharge (TTS) associated with the October 2013
Harrison/Pleasants asset transfer was offset by a rate reduction associated with the recovery of deferred energy costs. As part of the
TTS, MP earns a return on and of the Harrison plant costs.
The increase in wholesale generation revenues of $331 million in 2014 resulted from increased volume and energy prices associated
with market conditions related to extreme weather events in January 2014 and increased capacity revenue related to the October
2013 Harrison/Pleasants asset transfer whereby MP acquired from AE Supply 1,476 MWs of net capacity. During January 2014,
unprecedented customer demand associated with prolonged periods of bitterly cold temperatures and unit unavailability across the
PJM footprint resulted in severe market price volatility for electricity and natural gas throughout PJM. Eight of the ten highest winter
demands for electricity on the PJM system occurred in January 2014. The difference between wholesale generation revenues,
primarily associated with MP's regulated generation, and certain energy costs are deferred for future recovery, with no material impact
to earnings.
The increase in transmission revenues of $52 million reflects higher PJM revenues at MP associated with market conditions related to
extreme weather events described above and an increase in the Ohio Companies' NMB transmission rider revenues, partially offset
by the termination of WP's network transmission rider effective June 2013 as discussed above. Network transmission costs are now
recovered through WP's generation rate.
Other revenues decreased $17 million primarily due to less customer requested work in 2014 compared to 2013.
Operating Expenses —
Total operating expenses increased by $428 million primarily due to the following:
Harrison/Pleasants asset transfer.
• Purchased power costs were $77 million higher in 2014 primarily due to increased unit prices and capacity expense
reflecting higher auction clearing prices, partially offset by a decrease in purchased volumes required.
Regulated Distribution — 2014 Compared with 2013
Regulated Distribution's net income decreased $36 million in 2014 compared to 2013. Regulated Distribution's Pension and OPEB
mark-to-market adjustment increased $655 million which was partially offset by a reduction in regulatory asset impairment charges of
$305 million and an impairment of long-lived assets of $322 million incurred in 2013. Excluding the impact of these charges, year-
over-year earnings were impacted by higher distribution operating and maintenance costs, including the impact of higher benefit
costs, higher depreciation and property taxes, and higher interest expense from debt issuances. These items were partially offset by
slightly higher distribution deliveries, higher earnings associated with the October 2013 Harrison/Pleasants asset transfer, and a lower
effective tax rate.
Revenues —
The $382 million increase in total revenues resulted from the following sources:
Revenues by Type of Service
2014
2013
(Decrease)
For the Years Ended
December 31,
Increase
$
3,694 $
3,762 $
(68 )
(In millions)
Distribution services
Generation sales:
Retail
Wholesale
Total generation sales
Transmission sales:
Retail
Wholesale
Total transmission sales
Other
Total Revenues
4,043
661
4,704
352
148
500
204
3,959
330
4,289
347
101
448
221
$
9,102 $
8,720 $
The decrease in distribution services revenue is primarily related to a decrease in revenues from ME and PN NUG riders as a result
of the expiration of certain NUG contracts in 2013 and a rider rate decrease associated with the recovery of energy efficiency and
other customer program costs for the Pennsylvania Companies. This was partially offset by higher electric distribution MWH deliveries
of 1.1% as described below, rate increases for the Ohio Companies associated with energy efficiency performance shared savings
and the Rider DCR, and higher revenues for the Pennsylvania Companies associated with the recovery of Smart Meter program
costs. Certain Ohio energy efficiency programs permit the Ohio Companies to bill and collect shared savings revenues if energy
efficiency programs meet or exceed the state mandates. Additionally, the Rider DCR provides for recovery of incremental operating
expenses and a return on rate base associated with incremental distribution plant investments in Ohio. Distribution deliveries by
customer class are summarized in the following table:
Residential
Commercial
Industrial
Other
For the Years Ended
December 31,
(In thousands)
54,766
42,925
51,276
586
54,479
42,582
50,243
584
Total Electric Distribution MWH Deliveries
149,553
147,888
Higher deliveries to residential customers primarily reflect increased weather-related usage resulting from heating degree days that
were 7% above 2013, and 9% above normal, partially offset by cooling degree days that were 15% below 2013, and 12% below
normal. Increased deliveries to commercial customers reflect improving economic conditions across FirstEnergy's service territories.
In the industrial sector, increased sales to steel, automotive and shale gas customers were partially offset by lower sales to chemical
and paper customers.
84
331
415
5
47
52
(17 )
382
0.5 %
0.8 %
2.1 %
0.3 %
1.1 %
The following table summarizes the price and volume factors contributing to the $415 million increase in generation revenues in 2014
compared to 2013:
Source of Change in Generation Revenues
Increase
(In millions)
Retail:
Effect of increase in sales volumes
$
Change in prices
Wholesale:
Effect of increase in sales volumes
Change in prices
Capacity revenue
Increase in Generation Revenues
$
14
70
84
166
79
86
331
415
The increase in retail generation sales volume was primarily due to weather-related usage, as described above, and improving
economic conditions, partially offset by increased customer shopping in Pennsylvania. The increase in retail generation prices reflects
higher Pennsylvania PTC prices, the completion of marginal transmission loss refunds to ME and PN customers in the second
quarter of 2013 and a higher generation rate at WP, which includes the recovery of transmission costs effective June 2013.
Additionally, the impact on retail generation prices of MP's Temporary Transaction Surcharge (TTS) associated with the October 2013
Harrison/Pleasants asset transfer was offset by a rate reduction associated with the recovery of deferred energy costs. As part of the
TTS, MP earns a return on and of the Harrison plant costs.
The increase in wholesale generation revenues of $331 million in 2014 resulted from increased volume and energy prices associated
with market conditions related to extreme weather events in January 2014 and increased capacity revenue related to the October
2013 Harrison/Pleasants asset transfer whereby MP acquired from AE Supply 1,476 MWs of net capacity. During January 2014,
unprecedented customer demand associated with prolonged periods of bitterly cold temperatures and unit unavailability across the
PJM footprint resulted in severe market price volatility for electricity and natural gas throughout PJM. Eight of the ten highest winter
demands for electricity on the PJM system occurred in January 2014. The difference between wholesale generation revenues,
primarily associated with MP's regulated generation, and certain energy costs are deferred for future recovery, with no material impact
to earnings.
The increase in transmission revenues of $52 million reflects higher PJM revenues at MP associated with market conditions related to
extreme weather events described above and an increase in the Ohio Companies' NMB transmission rider revenues, partially offset
by the termination of WP's network transmission rider effective June 2013 as discussed above. Network transmission costs are now
recovered through WP's generation rate.
Other revenues decreased $17 million primarily due to less customer requested work in 2014 compared to 2013.
Operating Expenses —
Total operating expenses increased by $428 million primarily due to the following:
Electric Distribution MWH Deliveries
2014
2013
Increase
• Fuel expense was $190 million higher in 2014 primarily related to increased generation as a result of the October 2013
Harrison/Pleasants asset transfer.
• Purchased power costs were $77 million higher in 2014 primarily due to increased unit prices and capacity expense
reflecting higher auction clearing prices, partially offset by a decrease in purchased volumes required.
26
27
Source of Change in Purchased Power
Increase
(Decrease)
(In millions)
Purchases from non-affiliates:
Change due to increased unit costs
$
Change due to decreased volumes
Purchases from affiliates:
Change due to increased unit costs
Change due to increased volumes
Capacity expense
Increase in costs deferred
Increase in Purchased Power Costs
$
127
(134 )
(7 )
39
2
41
58
(15 )
77
Other operating expenses increased $308 million primarily due to:
• Higher transmission expenses of $130 million primarily due to PJM transmission costs associated with higher
congestion rates at MP as a result of market conditions related to extreme weather events in January 2014 and
higher PJM transmission costs resulting from the October 2013 Harrison/Pleasants asset transfer. The differences
between current transmission revenues and transmission costs incurred are deferred for future recovery, resulting
in no material impact on current period earnings.
• Higher distribution operating and maintenance expenses of $75 million resulting from higher maintenance activities
and storm related restoration expenses, including $26 million of storm expenses deferred for future recovery.
• Higher vegetation management expenses in West Virginia of $33 million, which were deferred for future recovery
per authorization of the WVPSC.
• Higher retirement benefit costs of $33 million primarily reflecting higher net periodic benefit costs before the
pension and OPEB mark-to-market adjustments discussed below.
•
Increased regulated generation operating and maintenance expenses of $23 million, reflecting increased costs
associated with the October 2013 Harrison/Pleasants asset transfer and a planned outage at Fort Martin.
Operating Expenses —
• Pension and OPEB mark-to-market adjustments increased $655 million to $506 million, primarily reflecting a lower discount
rate and revisions to mortality assumptions extending the expected life in key demographics used to measure related
obligations in 2014.
Other Expenses —
• Depreciation expense increased $52 million due to a higher asset base, including $22 million at MP associated with the
October 2013 Harrison/Pleasants asset transfer.
• Net regulatory asset amortization decreased $528 million primarily due to:
•
Impairment charges on regulatory assets of $305 million associated with the recovery of marginal transmission
losses at ME and PN ($254 million) and the recovery of RECs for the Ohio Companies ($51 million) that occurred
in 2013,
• Decreased energy efficiency amortization reflecting a rate decrease associated with certain programs for the
•
•
Pennsylvania Companies ($67 million),
Lower default generation service and NUG costs recovery in Pennsylvania ($48 million),
Increased deferral of West Virginia vegetation management expenses ($33 million) and customer refunds
associated with the gain on the Pleasants plant resulting from the October 2013 Harrison/Pleasants asset transfer
($36 million), and
• Higher storm cost deferrals ($26 million).
• General taxes decreased $4 million primarily due to lower revenue-related taxes, partially offset by higher property taxes
and an increase in the West Virginia business and occupation tax as a result of the October 2013 Harrison/Pleasants asset
transfer.
• The 2013 impairment of long-lived assets of $322 million reflects MP's charge to reduce the net book value of the Harrison
plant to the amount permitted to be included in rate base as part of the October 2013 Harrison/Pleasants asset transfer.
28
29
Other expense increased $64 million in 2014 primarily due to higher interest expense at MP resulting from new debt issuances of
$580 million associated with the financing of the October 2013 Harrison/Pleasants asset transfer, a new debt issuance of $500 million
in August 2013 at JCP&L and lower capitalized financing costs related primarily to a decrease in the rate used for borrowed funds.
Regulated Distribution's effective tax rate was 32.8% and 37.5% for 2014 and 2013, respectively. The decrease in the effective tax
rate primarily resulted from changes in state apportionment factors, an increase in state flow through income tax benefits and other
Regulated Transmission — 2014 Compared with 2013
Net income increased $9 million in 2014 compared to 2013. Higher Transmission revenues associated with increased capital
investments and higher capitalized financing costs were partially offset by higher operating expenses and interest expense.
Other Expense —
Income Taxes —
realized tax benefits.
Revenues —
Total revenues increased $38 million principally due to higher revenue at ATSI and TrAIL, reflecting recovery of incremental operating
expenses and a higher rate base as included in their annual rate filings effective June 2013 and June 2014.
Revenues by transmission asset owner are shown in the following table:
Revenues by Transmission Asset Owner
2014
2013
For the Years Ended
December 31,
Increase
(Decrease)
(In millions)
$
$
242 $
214
13
300
769 $
209 $
207
20
295
731 $
33
7
(7 )
5
38
ATSI
TrAIL
PATH
Utilities
Total Revenues
Total operating expenses increased $40 million principally due to higher property taxes, depreciation and other operating expenses.
Total other expenses decreased $3 million principally due to higher capitalized financing costs of $41 million related to increased
construction work in progress balances associated with the Energizing the Future investment plan, partially offset by increased
interest expense resulting from new debt issuances of $1.0 billion at FET and $400 million at ATSI, the proceeds of which, in part,
paid off short term borrowings.
Income Taxes —
Regulated Transmission's effective tax rate was 35.2% and 37.6% for 2014 and 2013, respectively. The decrease in the effective tax
rate primarily resulted from an increase in AFUDC equity flow through.
CES — 2014 Compared with 2013
Operating results decreased $113 million in 2014, compared to 2013. Lower impairment charges of $473 million associated with the
deactivation of the Hatfield and Mitchell generating units and a lower loss on debt redemptions of $141 million were partially offset
with higher Pension and OPEB mark-to-market adjustments of $434 million. Excluding the impact of these charges, year-over-year
earnings were impacted by lower sales volumes, reflecting CES' selling efforts discussed below and an increase in purchased power
and transmission costs incurred to serve contract sales due to market conditions associated with the extreme weather events in
January 2014. Partially offsetting these items were lower operating expenses due to lower retail-related costs, lower generation costs
resulting from plant deactivations and asset transfers, and higher capacity revenues from higher auction prices. Additionally, operating
results were impacted by a $78 million after-tax gain on the sale of certain hydro facilities in February 2014.
Other Expense —
Other expense increased $64 million in 2014 primarily due to higher interest expense at MP resulting from new debt issuances of
$580 million associated with the financing of the October 2013 Harrison/Pleasants asset transfer, a new debt issuance of $500 million
in August 2013 at JCP&L and lower capitalized financing costs related primarily to a decrease in the rate used for borrowed funds.
Income Taxes —
Regulated Distribution's effective tax rate was 32.8% and 37.5% for 2014 and 2013, respectively. The decrease in the effective tax
rate primarily resulted from changes in state apportionment factors, an increase in state flow through income tax benefits and other
realized tax benefits.
Regulated Transmission — 2014 Compared with 2013
Net income increased $9 million in 2014 compared to 2013. Higher Transmission revenues associated with increased capital
investments and higher capitalized financing costs were partially offset by higher operating expenses and interest expense.
Revenues —
Total revenues increased $38 million principally due to higher revenue at ATSI and TrAIL, reflecting recovery of incremental operating
expenses and a higher rate base as included in their annual rate filings effective June 2013 and June 2014.
Revenues by transmission asset owner are shown in the following table:
Revenues by Transmission Asset Owner
2014
2013
Increase
(Decrease)
For the Years Ended
December 31,
ATSI
TrAIL
PATH
Utilities
Total Revenues
Operating Expenses —
$
$
(In millions)
242 $
214
13
300
769 $
209 $
207
20
295
731 $
33
7
(7 )
5
38
Total operating expenses increased $40 million principally due to higher property taxes, depreciation and other operating expenses.
Other Expenses —
Total other expenses decreased $3 million principally due to higher capitalized financing costs of $41 million related to increased
construction work in progress balances associated with the Energizing the Future investment plan, partially offset by increased
interest expense resulting from new debt issuances of $1.0 billion at FET and $400 million at ATSI, the proceeds of which, in part,
paid off short term borrowings.
Income Taxes —
Regulated Transmission's effective tax rate was 35.2% and 37.6% for 2014 and 2013, respectively. The decrease in the effective tax
rate primarily resulted from an increase in AFUDC equity flow through.
CES — 2014 Compared with 2013
Operating results decreased $113 million in 2014, compared to 2013. Lower impairment charges of $473 million associated with the
deactivation of the Hatfield and Mitchell generating units and a lower loss on debt redemptions of $141 million were partially offset
with higher Pension and OPEB mark-to-market adjustments of $434 million. Excluding the impact of these charges, year-over-year
earnings were impacted by lower sales volumes, reflecting CES' selling efforts discussed below and an increase in purchased power
and transmission costs incurred to serve contract sales due to market conditions associated with the extreme weather events in
January 2014. Partially offsetting these items were lower operating expenses due to lower retail-related costs, lower generation costs
resulting from plant deactivations and asset transfers, and higher capacity revenues from higher auction prices. Additionally, operating
results were impacted by a $78 million after-tax gain on the sale of certain hydro facilities in February 2014.
29
Revenues —
Total revenues decreased $209 million in 2014, compared to 2013, primarily due to decreased sales volumes in the Direct and
Governmental Aggregation sales channels, partially offset by higher volume in the Structured Sales channel. Revenues were also
impacted by higher unit prices as a result of increased channel pricing and higher capacity revenues, as described below.
The decrease in total revenues resulted from the following sources:
Revenues by Type of Service
2014
2013
(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)
2,359 $
1,184
452
902
522
5,419
461
220
189
6,289 $
2,913 $
1,185
448
858
421
5,825
343
144
186
6,498 $
$
$
(554 )
(1 )
4
44
101
(406 )
118
76
3
(209 )
MWH Sales by Channel
2014
2013
(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
(In thousands)
44,012
19,569
6,773
15,708
12,814
98,876
680
99,556
56,145
20,859
6,761
15,758
9,047
108,570
1,250
109,820
(21.6 )%
(6.2 )%
0.2 %
(0.3 )%
41.6 %
(8.9 )%
(45.6 )%
(9.3 )%
The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Revenues
Increase (Decrease)
Gain on
Settled
Contracts
(In millions)
MWH Sales Channel:
Sales
Volumes
Prices
Capacity
Revenue Total
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Wholesale
$
(629 ) $
75 $
— $
— $ (554 )
(73 )
1
(3 )
176
(17 )
72
3
47
(75 )
—
—
—
—
—
(21 )
—
—
—
—
156
(1 )
4
44
101
118
Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflects CES' efforts to more
effectively hedge its generation by reducing exposure to weather sensitive load. Additionally, although unit pricing was higher year-
over-year in the Direct, Governmental Aggregation and Mass Market channels noted above, the increase was primarily attributable to
higher capacity expense as discussed below, which is a component of the retail price. The increase in prices associated with capacity
was partially offset by lower energy pricing built into the retail product at the time customers were acquired for 2014 sales. Beginning
in the fourth quarter of 2011, when there was a significant decline in energy prices, CES’ 2014 retail sales position was approximately
30% committed, whereas its 2013 retail sales position was approximately 60% committed, resulting in a greater proportion of 2014
sales and unit prices being impacted by the decline in the energy prices.
The increase in POLR revenues of $44 million was due to higher rates associated with the capacity expense component of the rate
discussed above, partially offset by lower sales volumes. The increase in Structured Sales revenues of $101 million was due to higher
sales volumes, partially offset by lower unit prices primarily due to market conditions related to extreme weather events in 2014 that
reduced the gains on various structured financial sales contracts.
Wholesale revenues increased $118 million primarily due to an increase in capacity revenue from higher capacity prices, partially
offset by a decrease in short-term (net hourly positions) transactions. The decrease in Wholesale sales volumes was due to lower
generation available to sell primarily as a result of the Harrison/Pleasants asset transfer and the deactivation of certain power plants
in 2013.
Transmission revenue increased $76 million due to higher congestion revenue driven by market conditions related to extreme
weather events in 2014, as discussed above.
Other revenue increased $3 million in 2014 as compared to 2013 as higher lease revenues from additional repurchased equity
interests in affiliated sale and leasebacks since 2013, partially offset by a $17 million pre-tax gain recognized in 2013 on the sale of
property to a regulated affiliate. CES earns lease revenue associated with the equity interests it has purchased.
Operating Expenses —
Total operating expenses increased $265 million in 2014 due to the following:
• Fuel costs decreased $406 million primarily due to lower generation volumes resulting from the October 2013
Harrison/Pleasants asset transfer, the deactivation of certain power plants in 2013 and increased outages as compared to
the same period of 2013. Higher unit prices, primarily driven by increased peaking generation, was partially offset by the
suspension of the DOE nuclear disposal fee, which was effective May 2014. Additionally, fuel costs were impacted by an
increase in settlement and termination costs related to coal and transportation contracts. Terminations and settlements
associated with damages on coal and transportation contracts were approximately $166 million and $128 million in 2014
and 2013, respectively.
• Purchased power costs increased $725 million due to higher volumes ($252 million), increased unit prices ($565 million)
and higher capacity expenses ($311 million), partially offset by lower losses on financially settled contracts ($403 million).
Higher purchased volumes were primarily due to lower available generation due to outages, the October 2013
Harrison/Pleasants asset transfer and the deactivation of certain power plants in 2013, partially offset by lower contract
sales as described above. The increase in unit prices was primarily a result of market conditions related to extreme weather
events in January 2014, partially offset by lower losses on financially settled contracts. The increase in capacity expense,
which is a component of the segment's retail price, was primarily the result of higher capacity rates associated with the
segment's retail sales obligations.
30
31
Revenues —
Total revenues decreased $209 million in 2014, compared to 2013, primarily due to decreased sales volumes in the Direct and
Governmental Aggregation sales channels, partially offset by higher volume in the Structured Sales channel. Revenues were also
impacted by higher unit prices as a result of increased channel pricing and higher capacity revenues, as described below.
The decrease in total revenues resulted from the following sources:
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
Revenues by Type of Service
2014
2013
(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
Contract Sales:
Direct
Governmental Aggregation
Mass Market
POLR
Structured Sales
Total Contract Sales
Wholesale
Total MWH Sales
(In millions)
$
2,359 $
1,184
2,913 $
1,185
452
902
522
5,419
461
220
189
448
858
421
5,825
343
144
186
$
6,289 $
6,498 $
(In thousands)
44,012
19,569
6,773
15,708
12,814
98,876
680
99,556
56,145
20,859
6,761
15,758
9,047
108,570
1,250
109,820
(554 )
(1 )
4
44
101
(406 )
118
76
3
(209 )
(21.6 )%
(6.2 )%
0.2 %
(0.3 )%
41.6 %
(8.9 )%
(45.6 )%
(9.3 )%
MWH Sales by Channel
2014
2013
(Decrease)
For the Years Ended
December 31,
Increase
(In millions)
Direct
$
Governmental Aggregation
Mass Market
POLR
Structured Sales
Wholesale
(629 ) $
(73 )
1
(3 )
176
(17 )
75 $
72
3
47
(75 )
—
— $
—
—
—
—
(21 )
— $ (554 )
—
(1 )
4
—
44
—
101
—
118
156
Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflects CES' efforts to more
effectively hedge its generation by reducing exposure to weather sensitive load. Additionally, although unit pricing was higher year-
over-year in the Direct, Governmental Aggregation and Mass Market channels noted above, the increase was primarily attributable to
higher capacity expense as discussed below, which is a component of the retail price. The increase in prices associated with capacity
was partially offset by lower energy pricing built into the retail product at the time customers were acquired for 2014 sales. Beginning
in the fourth quarter of 2011, when there was a significant decline in energy prices, CES’ 2014 retail sales position was approximately
30% committed, whereas its 2013 retail sales position was approximately 60% committed, resulting in a greater proportion of 2014
sales and unit prices being impacted by the decline in the energy prices.
The increase in POLR revenues of $44 million was due to higher rates associated with the capacity expense component of the rate
discussed above, partially offset by lower sales volumes. The increase in Structured Sales revenues of $101 million was due to higher
sales volumes, partially offset by lower unit prices primarily due to market conditions related to extreme weather events in 2014 that
reduced the gains on various structured financial sales contracts.
Wholesale revenues increased $118 million primarily due to an increase in capacity revenue from higher capacity prices, partially
offset by a decrease in short-term (net hourly positions) transactions. The decrease in Wholesale sales volumes was due to lower
generation available to sell primarily as a result of the Harrison/Pleasants asset transfer and the deactivation of certain power plants
in 2013.
Transmission revenue increased $76 million due to higher congestion revenue driven by market conditions related to extreme
weather events in 2014, as discussed above.
Other revenue increased $3 million in 2014 as compared to 2013 as higher lease revenues from additional repurchased equity
interests in affiliated sale and leasebacks since 2013, partially offset by a $17 million pre-tax gain recognized in 2013 on the sale of
property to a regulated affiliate. CES earns lease revenue associated with the equity interests it has purchased.
Operating Expenses —
Total operating expenses increased $265 million in 2014 due to the following:
• Fuel costs decreased $406 million primarily due to lower generation volumes resulting from the October 2013
Harrison/Pleasants asset transfer, the deactivation of certain power plants in 2013 and increased outages as compared to
the same period of 2013. Higher unit prices, primarily driven by increased peaking generation, was partially offset by the
suspension of the DOE nuclear disposal fee, which was effective May 2014. Additionally, fuel costs were impacted by an
increase in settlement and termination costs related to coal and transportation contracts. Terminations and settlements
associated with damages on coal and transportation contracts were approximately $166 million and $128 million in 2014
and 2013, respectively.
• Purchased power costs increased $725 million due to higher volumes ($252 million), increased unit prices ($565 million)
and higher capacity expenses ($311 million), partially offset by lower losses on financially settled contracts ($403 million).
Higher purchased volumes were primarily due to lower available generation due to outages, the October 2013
Harrison/Pleasants asset transfer and the deactivation of certain power plants in 2013, partially offset by lower contract
sales as described above. The increase in unit prices was primarily a result of market conditions related to extreme weather
events in January 2014, partially offset by lower losses on financially settled contracts. The increase in capacity expense,
which is a component of the segment's retail price, was primarily the result of higher capacity rates associated with the
segment's retail sales obligations.
30
31
• Fossil operating costs decreased $73 million primarily due to lower contractor, labor and materials and equipment costs
resulting from previously deactivated units and the October 2013 Harrison/Pleasants asset transfer.
• Nuclear operating costs increased $6 million as a result of higher labor, contractor, materials and equipment costs. There
were two refueling outages in each of 2014 and 2013, however, the duration of the outages in 2014 exceeded the prior year.
• Transmission expenses increased $80 million primarily due to higher operating reserve and market-based ancillary costs
associated with market conditions related to extreme weather events in 2014. Additionally, effective June 1, 2013, network
expenses associated with POLR sales in Pennsylvania became the responsibility of suppliers.
• General taxes decreased $31 million primarily due to lower gross receipts taxes resulting from reduced retail sales volumes,
lower payroll taxes as a result of lower labor costs noted above, lower property taxes due to the October 2013
Harrison/Pleasants asset transfer, and reduced Ohio personal property taxes.
•
Impairments of long-lived assets decreased $473 million due to the impairment of two unregulated, coal-fired generating
plants recognized in 2013.
• Depreciation expense decreased $52 million primarily due to a reduction in the asset base as a result of the plant
deactivations and the October 2013 Harrison/Pleasants asset transfer noted above.
• Pension and OPEB mark-to-market adjustments increased $434 million to $327 million, primarily reflecting a lower discount
rate and revisions to mortality assumptions extending the expected life in key demographics used to measure related
obligations in 2014.
• Other operating expenses increased $55 million primarily due to an increase in mark-to-market expenses on commodity
contract positions, and an impairment of deferred advertising costs of $23 million associated with the elimination of future
selling efforts in the Mass Market and certain Direct sales channels, partially offset by lower retail and marketing related
costs.
Other Expense —
Total other expense in 2014 decreased $209 million compared to 2013 due to the absence of a $141 million loss on debt redemptions
in connection with senior notes that were repurchased in 2013, higher investment income primarily on the NDT investments, lower
OTTI and lower net interest expense of $28 million due to debt redemptions.
Income Tax Benefits —
CES' effective tax rate was 34.8% and 37.3% for 2014 and 2013, respectively. The decrease in the effective tax rate, which resulted
in a lower tax benefit on pre-tax losses, primarily resulted from changes in state apportionment factors and higher valuation
allowances on certain NOL carryforwards.
Discontinued Operations —
Discontinued operations increased $69 million in 2014 compared to the same period of last year primarily due to a pre-tax gain of
approximately $142 million ($78 million after-tax) associated with the sale of hydro assets in February 2014.
other conditions.
Corporate/Other — 2014 Compared with 2013
Financial results from Corporate/Other resulted in a $47 million increase in net income in 2014 compared to 2013 primarily due to
higher tax benefits, partially offset by $17 million of gains on debt redemptions in 2013. The higher tax benefits primarily resulted from
an IRS-approved change in accounting method that increased the tax basis of certain assets resulting in higher future tax deductions,
and the resolution of state tax benefits resulting from the expiration of the statute of limitation on certain state tax positions. Additional
income tax benefits of $25 million were recognized in 2014 that relate to prior periods. The out-of-period adjustment primarily related
to the correction of amounts included on FirstEnergy's tax basis balance sheet. Management has determined that these adjustments
are not material to the current or any prior period. The 2013 effective tax rate benefited from reductions to valuation allowances
against state NOL carryforwards, as well as changes in state apportionment factors, which reduced deferred tax liabilities.
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, 2015 and December 31, 2014, and the changes during the year ended December 31, 2015:
Regulatory Assets (Liabilities) by Source
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
December 31,
December 31,
2015
2014
Increase
(Decrease)
$
185 $
240 $
(In millions)
355
(272 )
(372 )
115
243
335
186
403
170
370
(305 )
(254 )
90
281
182
153
465
189
(55 )
(15 )
33
(118 )
25
(38 )
153
33
(62 )
(19 )
(63 )
Net Regulatory Assets included on the Consolidated Balance Sheets
$
1,348
$
1,411
$
Regulatory assets that do not earn a current return totaled approximately $148 million and $488 million as of December 31, 2015 and
2014, respectively, primarily related to storm damage costs. JCP&L's regulatory asset related to 2011 and 2012 storm damage costs
began earning a return on April 1, 2015. Effective with the approved settlement on April 9, 2015, associated with their general base
rate case, the Pennsylvania Companies transferred the net book value of legacy meters from plant-in-service to regulatory assets,
which is being recovered over five years.
As of December 31, 2015 and December 31, 2014, FirstEnergy had approximately $116 million and $243 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.
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries.
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. During 2015, FirstEnergy
received $630 million of cash dividends and capital returned from its subsidiaries and paid $607 million in cash dividends to common
shareholders. In addition to internal sources to fund liquidity and capital requirements for 2016 and beyond, FirstEnergy expects to
rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied
through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt and/or equity. FirstEnergy
expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with
continued access to long-term capital markets. Additionally, FirstEnergy also expects to issue long-term debt at certain Utilities and
certain other subsidiaries to, among other things, refinance short-term and maturing debt in the ordinary course, subject to market and
Additionally in 2016, FirstEnergy has minimum required funding obligations of $381 million to its qualified pension plan, of which $160
million has been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash,
equity or a combination thereof, depending on, among other things, market conditions.
FirstEnergy's longer term strategic outlook for its regulated and competitive businesses will be determined following resolution of the
Ohio Companies' ESP IV, including the proposed PPA between FES and the Ohio Companies. Once the ESP IV is finalized,
FirstEnergy expects to be in a position to more fully understand the longer-term outlook of its competitive businesses and the longer
term growth rate of its regulated businesses, including planned capital investments and any additional equity to fund growth in its
regulated businesses. With the exception of Regulated Transmission's 2016 projected capital expenditures discussed below, planned
capital expenditures for 2016 for Regulated Distribution, CES, and Corporate/Other will depend on the outcome of the Ohio
Companies' ESP IV and remain subject to Board approval.
FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is a $4.2 billion
Energizing the Future investment plan that began in 2014 and will continue through 2017 to upgrade and expand 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 2015,
FirstEnergy's capital expenditures under this plan were $2.4 billion and in 2016 capital expenditures under this plan are currently
projected to be approximately $1 billion. In total, FirstEnergy has identified at least $15 billion in transmission investment opportunities
across the 24,000 mile transmission system, making this a continuing platform for investment in the years beyond 2017.
32
33
• Nuclear operating costs increased $6 million as a result of higher labor, contractor, materials and equipment costs. There
were two refueling outages in each of 2014 and 2013, however, the duration of the outages in 2014 exceeded the prior year.
•
Transmission expenses increased $80 million primarily due to higher operating reserve and market-based ancillary costs
associated with market conditions related to extreme weather events in 2014. Additionally, effective June 1, 2013, network
expenses associated with POLR sales in Pennsylvania became the responsibility of suppliers.
• General taxes decreased $31 million primarily due to lower gross receipts taxes resulting from reduced retail sales volumes,
lower payroll taxes as a result of lower labor costs noted above, lower property taxes due to the October 2013
Harrison/Pleasants asset transfer, and reduced Ohio personal property taxes.
•
Impairments of long-lived assets decreased $473 million due to the impairment of two unregulated, coal-fired generating
plants recognized in 2013.
• Depreciation expense decreased $52 million primarily due to a reduction in the asset base as a result of the plant
deactivations and the October 2013 Harrison/Pleasants asset transfer noted above.
•
Pension and OPEB mark-to-market adjustments increased $434 million to $327 million, primarily reflecting a lower discount
rate and revisions to mortality assumptions extending the expected life in key demographics used to measure related
obligations in 2014.
• Other operating expenses increased $55 million primarily due to an increase in mark-to-market expenses on commodity
contract positions, and an impairment of deferred advertising costs of $23 million associated with the elimination of future
selling efforts in the Mass Market and certain Direct sales channels, partially offset by lower retail and marketing related
costs.
Other Expense —
Income Tax Benefits —
Total other expense in 2014 decreased $209 million compared to 2013 due to the absence of a $141 million loss on debt redemptions
in connection with senior notes that were repurchased in 2013, higher investment income primarily on the NDT investments, lower
OTTI and lower net interest expense of $28 million due to debt redemptions.
CES' effective tax rate was 34.8% and 37.3% for 2014 and 2013, respectively. The decrease in the effective tax rate, which resulted
in a lower tax benefit on pre-tax losses, primarily resulted from changes in state apportionment factors and higher valuation
allowances on certain NOL carryforwards.
Discontinued Operations —
Discontinued operations increased $69 million in 2014 compared to the same period of last year primarily due to a pre-tax gain of
approximately $142 million ($78 million after-tax) associated with the sale of hydro assets in February 2014.
Corporate/Other — 2014 Compared with 2013
Financial results from Corporate/Other resulted in a $47 million increase in net income in 2014 compared to 2013 primarily due to
higher tax benefits, partially offset by $17 million of gains on debt redemptions in 2013. The higher tax benefits primarily resulted from
an IRS-approved change in accounting method that increased the tax basis of certain assets resulting in higher future tax deductions,
and the resolution of state tax benefits resulting from the expiration of the statute of limitation on certain state tax positions. Additional
income tax benefits of $25 million were recognized in 2014 that relate to prior periods. The out-of-period adjustment primarily related
to the correction of amounts included on FirstEnergy's tax basis balance sheet. Management has determined that these adjustments
are not material to the current or any prior period. The 2013 effective tax rate benefited from reductions to valuation allowances
against state NOL carryforwards, as well as changes in state apportionment factors, which reduced deferred tax liabilities.
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, 2015 and December 31, 2014, and the changes during the year ended December 31, 2015:
•
Fossil operating costs decreased $73 million primarily due to lower contractor, labor and materials and equipment costs
resulting from previously deactivated units and the October 2013 Harrison/Pleasants asset transfer.
Regulatory Assets (Liabilities) by Source
December 31,
2015
December 31,
2014
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
185 $
355
(272 )
(372 )
115
243
335
186
403
170
240 $
370
(305 )
(254 )
90
281
182
153
465
189
Net Regulatory Assets included on the Consolidated Balance Sheets
$
1,348 $
1,411 $
(55 )
(15 )
33
(118 )
25
(38 )
153
33
(62 )
(19 )
(63 )
Regulatory assets that do not earn a current return totaled approximately $148 million and $488 million as of December 31, 2015 and
2014, respectively, primarily related to storm damage costs. JCP&L's regulatory asset related to 2011 and 2012 storm damage costs
began earning a return on April 1, 2015. Effective with the approved settlement on April 9, 2015, associated with their general base
rate case, the Pennsylvania Companies transferred the net book value of legacy meters from plant-in-service to regulatory assets,
which is being recovered over five years.
As of December 31, 2015 and December 31, 2014, FirstEnergy had approximately $116 million and $243 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.
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries.
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. During 2015, FirstEnergy
received $630 million of cash dividends and capital returned from its subsidiaries and paid $607 million in cash dividends to common
shareholders. In addition to internal sources to fund liquidity and capital requirements for 2016 and beyond, FirstEnergy expects to
rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied
through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt and/or equity. FirstEnergy
expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with
continued access to long-term capital markets. Additionally, FirstEnergy also expects to issue long-term debt at certain Utilities and
certain other subsidiaries to, among other things, refinance short-term and maturing debt in the ordinary course, subject to market and
other conditions.
Additionally in 2016, FirstEnergy has minimum required funding obligations of $381 million to its qualified pension plan, of which $160
million has been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash,
equity or a combination thereof, depending on, among other things, market conditions.
FirstEnergy's longer term strategic outlook for its regulated and competitive businesses will be determined following resolution of the
Ohio Companies' ESP IV, including the proposed PPA between FES and the Ohio Companies. Once the ESP IV is finalized,
FirstEnergy expects to be in a position to more fully understand the longer-term outlook of its competitive businesses and the longer
term growth rate of its regulated businesses, including planned capital investments and any additional equity to fund growth in its
regulated businesses. With the exception of Regulated Transmission's 2016 projected capital expenditures discussed below, planned
capital expenditures for 2016 for Regulated Distribution, CES, and Corporate/Other will depend on the outcome of the Ohio
Companies' ESP IV and remain subject to Board approval.
FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is a $4.2 billion
Energizing the Future investment plan that began in 2014 and will continue through 2017 to upgrade and expand 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 2015,
FirstEnergy's capital expenditures under this plan were $2.4 billion and in 2016 capital expenditures under this plan are currently
projected to be approximately $1 billion. In total, FirstEnergy has identified at least $15 billion in transmission investment opportunities
across the 24,000 mile transmission system, making this a continuing platform for investment in the years beyond 2017.
32
33
In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments and the
repositioning of the CES segment, FirstEnergy is also focused on improving the balance sheet over time consistent with its business
profile, maintaining investment grade metrics at each business unit, and maintaining strong liquidity for an overall stable financial
position. Specifically, at the regulated businesses, authority has been obtained for various regulated distribution and transmission
subsidiaries to issue and/or refinance debt.
As part of an ongoing effort to manage costs, FirstEnergy identified both immediate and long-term savings opportunities through its
cash flow improvement plan. The cash flow improvement plan identified targeted cash savings of approximately $58 million in 2015,
$155 million in 2016 and $240 million annually by 2017, with reductions in operating expenses representing approximately 65% of the
savings over the three-year period.
Any financing plans by FirstEnergy, including the issuance of equity, refinancing of maturing debt and reductions in short-term
borrowings, are subject to market conditions and other factors. No assurance can be given that any such issuances, financings,
refinancings, or reductions in short-term debt, as the case may be, will be completed as anticipated. In addition, FirstEnergy expects
to continually evaluate any planned financings, which may result in changes from time to time.
As of December 31, 2015, 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, 2015, included the
following:
Currently Payable Long-Term Debt
PCRBs supported by bank LOCs (1)
FMBs
Unsecured notes
Unsecured PCRBs (1)
Collateralized lease obligation bonds
Sinking fund requirements
Other notes
(In millions)
92
245
300
391
23
87
28
1,166
$
$
(1)
These PCRBs are classified as currently payable long-term debt because the applicable interest rate
mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
Short-Term Borrowings / Revolving Credit Facilities
FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of
$6.0 billion (Facilities), which are available until March 31, 2019. FirstEnergy had $1,708 million and $1,799 million of short-term
borrowings as of December 31, 2015 and 2014, respectively. FirstEnergy’s available liquidity under the Facilities as of January 31,
2016 was as follows:
Borrower(s)
Type
Maturity
Commitment
Available
Liquidity
FirstEnergy(1)
FES / AE Supply
FET(2)
Revolving March 2019 $
Revolving March 2019
Revolving March 2019
Subtotal $
Cash
Total $
(1)
(2)
FE and the Utilities.
Includes FET, ATSI and TrAIL.
(In millions)
3,500 $
1,500
1,000
6,000 $
—
6,000 $
1,595
1,442
1,000
4,037
63
4,100
Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days
from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains
financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio (as defined under each of the
Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
34
35
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, 2015:
Borrower
AE Supply
JCP&L
FE
FES
FET
OE
CEI
TE
ME
PN
WP
MP
PE
ATSI
Penn
TrAIL
FirstEnergy
Revolving
Credit Facility
Sub-Limit
FES/AE Supply
Revolving
Credit Facility
Sub-Limit
FET Revolving
Credit Facility
Sub-Limit
Regulatory and
Other Short-Term
Debt Limitations
$
3,500
$
$
$
(In millions)
—
1,500
1,000
—
—
—
500
500
500
600
300
300
200
500
150
—
50
—
1,000
—
—
—
—
—
—
—
—
—
—
—
—
500
—
400
—
—
—
—
—
—
—
—
—
—
—
—
—
— (1)
— (2)
— (2)
— (1)
500 (3)
500 (3)
500 (3)
500 (3)
500 (3)
300 (3)
200 (3)
500 (3)
150 (3)
500 (3)
100 (3)
400 (3)
No limitations.
(1)
(2)
(3)
No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.
Includes amounts which may be borrowed under the regulated companies' money pool.
The entire amount of the FES/AE Supply Facility, $600 million of the FE Facility and $225 million of the FET Facility, subject to each
borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year
from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the
Facilities and against the applicable borrower’s borrowing sub-limit.
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, 2015, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants under the
respective Facilities.
Term Loans
FE has a $1 billion variable rate term loan credit agreement with a maturity date of March 31, 2019. The initial borrowing under the
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. The proceeds from this term loan reduced borrowings under the FE Facility.
Additionally, FE has a $200 million variable rate term loan with a maturity date of May 29, 2020. Each of the term loans contains
covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same
consolidated debt to total capitalization ratio requirement.
As of December 31, 2015, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants under
each of these term loans.
In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments and the
repositioning of the CES segment, FirstEnergy is also focused on improving the balance sheet over time consistent with its business
profile, maintaining investment grade metrics at each business unit, and maintaining strong liquidity for an overall stable financial
position. Specifically, at the regulated businesses, authority has been obtained for various regulated distribution and transmission
subsidiaries to issue and/or refinance debt.
As part of an ongoing effort to manage costs, FirstEnergy identified both immediate and long-term savings opportunities through its
cash flow improvement plan. The cash flow improvement plan identified targeted cash savings of approximately $58 million in 2015,
$155 million in 2016 and $240 million annually by 2017, with reductions in operating expenses representing approximately 65% of the
savings over the three-year period.
Any financing plans by FirstEnergy, including the issuance of equity, refinancing of maturing debt and reductions in short-term
borrowings, are subject to market conditions and other factors. No assurance can be given that any such issuances, financings,
refinancings, or reductions in short-term debt, as the case may be, will be completed as anticipated. In addition, FirstEnergy expects
to continually evaluate any planned financings, which may result in changes from time to time.
As of December 31, 2015, 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, 2015, included the
following:
Currently Payable Long-Term Debt
PCRBs supported by bank LOCs (1)
FMBs
Unsecured notes
Unsecured PCRBs (1)
Collateralized lease obligation bonds
Sinking fund requirements
Other notes
(In millions)
$
92
245
300
391
23
87
28
$
1,166
(1)
These PCRBs are classified as currently payable long-term debt because the applicable interest rate
mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
Short-Term Borrowings / Revolving Credit Facilities
FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of
$6.0 billion (Facilities), which are available until March 31, 2019. FirstEnergy had $1,708 million and $1,799 million of short-term
borrowings as of December 31, 2015 and 2014, respectively. FirstEnergy’s available liquidity under the Facilities as of January 31,
2016 was as follows:
Borrower(s)
Type
Maturity
Commitment
FirstEnergy(1)
Revolving March 2019 $
3,500 $
FES / AE Supply
Revolving March 2019
FET(2)
Revolving March 2019
1,500
1,000
Available
Liquidity
(In millions)
Subtotal $
6,000 $
Cash
Total $
—
6,000 $
1,595
1,442
1,000
4,037
63
4,100
(1)
(2)
FE and the Utilities.
Includes FET, ATSI and TrAIL.
Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days
from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains
financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio (as defined under each of the
Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
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, 2015:
Borrower
FE
FES
AE Supply
FET
OE
CEI
TE
JCP&L
ME
PN
WP
MP
PE
ATSI
Penn
TrAIL
FirstEnergy
Revolving
Credit Facility
Sub-Limit
FES/AE Supply
Revolving
Credit Facility
Sub-Limit
FET Revolving
Credit Facility
Sub-Limit
Regulatory and
Other Short-Term
Debt Limitations
(In millions)
$
3,500
—
—
—
500
500
500
600
300
300
200
500
150
—
50
—
$
—
1,500
1,000
—
—
—
—
—
—
—
—
—
—
—
—
—
$
—
—
—
1,000
—
—
—
—
—
—
—
—
—
500
—
400
$
— (1)
— (2)
— (2)
— (1)
500 (3)
500 (3)
500 (3)
500 (3)
500 (3)
300 (3)
200 (3)
500 (3)
150 (3)
500 (3)
100 (3)
400 (3)
(1)
(2)
(3)
No limitations.
No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.
Includes amounts which may be borrowed under the regulated companies' money pool.
The entire amount of the FES/AE Supply Facility, $600 million of the FE Facility and $225 million of the FET Facility, subject to each
borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year
from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the
Facilities and against the applicable borrower’s borrowing sub-limit.
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, 2015, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants under the
respective Facilities.
Term Loans
FE has a $1 billion variable rate term loan credit agreement with a maturity date of March 31, 2019. The initial borrowing under the
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. The proceeds from this term loan reduced borrowings under the FE Facility.
Additionally, FE has a $200 million variable rate term loan with a maturity date of May 29, 2020. Each of the term loans contains
covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same
consolidated debt to total capitalization ratio requirement.
As of December 31, 2015, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants under
each of these term loans.
34
35
FirstEnergy Money Pools
Changes in Cash Position
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 2015 was 0.84% per annum for the regulated companies’ money pool
and 1.64% per annum for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of December 31, 2015, FirstEnergy’s currently payable long-term debt included approximately $92 million of FES variable interest
rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the
PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase
price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay
LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to
honor its LOC for any reason, must itself pay the purchase price. The LOCs for FirstEnergy's variable interest rate PCRBs
outstanding as of December 31, 2015 were issued by the following bank:
Bank
Aggregate
Amount(1)
(In millions)
Termination Date
Reimbursements
of Draws Due
The Bank of Nova Scotia
$
92 March 2017
March 2017
(1)
Excludes approximately $1 million of applicable interest coverage.
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 December 31, 2015:
As of December 31, 2015, FirstEnergy had $131 million of cash and cash equivalents compared to $85 million of cash and cash
equivalents as of December 31, 2014. As of December 31, 2015 and 2014, FirstEnergy had approximately $82 million and $79
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 services provided by its utility operating subsidiaries and the
sale 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, interest, employees, tax authorities, lenders
and others for a wide range of materials and services.
Net cash provided from operating activities was $3,447 million during 2015, $2,713 million during 2014 and $2,662 million during
2013. 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
• Higher transmission revenue and earnings, reflecting recovery of incremental operating expenses, a higher rate base
in distribution deliveries;;
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 the 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 2015, cash used for financing activities was $279 million compared to $513 million and $477 million of net cash provided from
financing activities during 2014 and 2013, respectively. The following table summarizes new debt financing (net of any discounts),
redemptions and common stock dividend payments:
Securities Issued or Redeemed / Repaid
2015
2014
2013
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
—
BBB-
BBB-
—
—
Moody’s
—
—
—
—
—
BBB+
Baa1
—
—
—
BBB+
BBB+
—
—
BBB+
BBB
—
BBB+
—
—
—
A3
A2
—
A2
A3
Baa1
—
A2
S&P
BB+
BBB-
BBB-
BBB-
BBB-
BBB-
BB+
BBB-
BBB-
—
BBB-
BBB-
—
—
—
BBB-
—
Moody’s
Baa3
Baa3
Baa3
Baa3
Baa2
Baa3
Baa3
Baa2
Baa1
—
Baa1
Baa2
—
—
—
A3
—
Fitch
BB+
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Debt capacity is subject to the consolidated debt to total capitalization limits in the Facilities previously discussed. As of December 31,
2015, FE and its subsidiaries could issue additional debt of approximately $5.1 billion and remain within the limitations of the financial
covenants required by the Facilities. As of December 31, 2015, FES' incremental debt capacity under its consolidated debt to total
capitalization financial covenant is also $5.1 billion given FE's consolidated debt to total capitalization ratio under the FE Facility.
Tender premiums paid on debt redemptions
— $
— $
(110)
Short-term borrowings, net
(91) $
(1,605) $
1,435
Common stock dividend payments
(607) $
(604) $
(920)
36
37
New Issues
Unsecured notes
PCRBs
FMBs
Term loan
Senior secured notes
Redemptions / Repayments
Unsecured notes
PCRBs
FMBs
Term loan
Senior secured notes
Long-term revolving credit
For the Years Ended December 31,
(In millions)
$
475 $
2,400 $
2,300
878
200
1,050
—
—
1,000
—
445
1,311 $
4,528 $
3,745
— $
(600) $
(2,284)
(793)
(175)
(191)
—
—
(470)
(420)
—
(376)
(50)
(879) $
(1,759) $
(3,600)
339
295
200
2
(313)
(215)
(200)
(151)
—
$
$
$
$
$
$
FirstEnergy Money Pools
Changes in Cash Position
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 2015 was 0.84% per annum for the regulated companies’ money pool
and 1.64% per annum for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of December 31, 2015, FirstEnergy’s currently payable long-term debt included approximately $92 million of FES variable interest
rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the
PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase
price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay
LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to
honor its LOC for any reason, must itself pay the purchase price. The LOCs for FirstEnergy's variable interest rate PCRBs
outstanding as of December 31, 2015 were issued by the following bank:
Bank
Aggregate
Amount(1)
(In millions)
Termination Date
Reimbursements
of Draws Due
The Bank of Nova Scotia
$
92 March 2017
March 2017
(1) Excludes approximately $1 million of applicable interest coverage.
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 December 31, 2015:
As of December 31, 2015, FirstEnergy had $131 million of cash and cash equivalents compared to $85 million of cash and cash
equivalents as of December 31, 2014. As of December 31, 2015 and 2014, FirstEnergy had approximately $82 million and $79
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 services provided by its utility operating subsidiaries and the
sale 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, interest, employees, tax authorities, lenders
and others for a wide range of materials and services.
Net cash provided from operating activities was $3,447 million during 2015, $2,713 million during 2014 and $2,662 million during
2013. 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;;
•
•
• A $143 million contribution to the qualified pension plan in 2015.
Lower disbursements for fuel and purchased power resulting from the lower sales volumes;; and
Lower posted collateral;; partially offset by,
Cash Flows From Financing Activities
In 2015, cash used for financing activities was $279 million compared to $513 million and $477 million of net cash provided from
financing activities during 2014 and 2013, respectively. The following table summarizes new debt financing (net of any discounts),
redemptions and common stock dividend payments:
Securities Issued or Redeemed / Repaid
2015
2014
2013
For the Years Ended December 31,
Issuer
FE
FES
AE Supply
JCP&L
AGC
ATSI
CEI
FET
ME
MP
OE
PN
Penn
PE
TE
TrAIL
WP
Senior Secured
S&P
Moody’s
Senior Unsecured
Moody’s
BBB+
Baa1
—
BBB-
BBB-
—
—
—
—
—
—
—
BBB+
BBB+
BBB+
BBB
—
BBB+
—
—
—
—
—
—
—
—
A3
A2
—
A2
A3
—
A2
Baa1
S&P
BB+
BBB-
BBB-
BBB-
BBB-
BBB-
BB+
BBB-
BBB-
—
BBB-
BBB-
—
—
—
—
BBB-
Baa3
Baa3
Baa3
Baa3
Baa2
Baa3
Baa3
Baa2
Baa1
—
Baa1
Baa2
—
—
—
A3
—
Fitch
BB+
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Debt capacity is subject to the consolidated debt to total capitalization limits in the Facilities previously discussed. As of December 31,
2015, FE and its subsidiaries could issue additional debt of approximately $5.1 billion and remain within the limitations of the financial
covenants required by the Facilities. As of December 31, 2015, FES' incremental debt capacity under its consolidated debt to total
capitalization financial covenant is also $5.1 billion given FE's consolidated debt to total capitalization ratio under the FE Facility.
New Issues
Unsecured notes
PCRBs
FMBs
Term loan
Senior secured notes
Redemptions / Repayments
Unsecured notes
PCRBs
FMBs
Term loan
Senior secured notes
Long-term revolving credit
Tender premiums paid on debt redemptions
Short-term borrowings, net
Common stock dividend payments
(In millions)
475 $
339
295
200
2
1,311 $
2,400 $
878
200
1,050
—
4,528 $
2,300
—
1,000
—
445
3,745
— $
(313 )
(215 )
(200 )
(151 )
—
(879 ) $
(600 ) $
(793 )
(175 )
—
(191 )
—
(1,759 ) $
(2,284 )
(470 )
(420 )
—
(376 )
(50 )
(3,600 )
— $
— $
(110 )
(91 ) $
(1,605 ) $
1,435
(607 ) $
(604 ) $
(920 )
$
$
$
$
$
$
$
36
37
During the second quarter of 2015, FE refinanced a $200 million variable interest term loan, maturing on December 31, 2016 with a
new $200 million variable interest term loan maturing on May 29, 2020.
CONTRACTUAL OBLIGATIONS
On July 1, 2015, FG and NG remarketed approximately $43 million and $296 million, respectively, of PCRBs. The PCRBs were
remarketed with fixed interest rates ranging from 3.125% to 4.00% and mandatory put dates ranging from July 2, 2018 to July 1,
2021.
as follows:
As of December 31, 2015, our estimated cash payments under existing contractual obligations that we consider firm obligations are
Contractual Obligations
Total
2016
2017-2018 2019-2020 Thereafter
In August 2015, JCP&L issued $250 million of 4.30% senior notes due January 2026. The proceeds received from the issuance of the
senior notes were used to repay a portion of JCP&L’s short-term borrowings under the FirstEnergy regulated companies' money pool
and an external revolving credit facility.
Also, in the second quarter of 2015, WP agreed to sell $150 million of new 4.45% FMBs due September 2045 and PE agreed to sell
$145 million of new 4.47% FMBs due August 2045. The transactions closed on September 17, 2015 and August 17, 2015,
respectively. The proceeds resulting from the issuance of the WP FMBs were used to repay WP’s borrowings under the FirstEnergy
regulated companies' money pool and for other general corporate purposes. The proceeds resulting from the issuance of the PE
FMBs were used to repay PE’s $145 million 5.125% FMBs that matured on August 15, 2015.
In October 2015, TrAIL issued $75 million of 3.76% senior notes due May 2025. The proceeds resulting from the issuance of the
senior notes were used: (i) to fund capital expenditures, including with respect to TrAIL's transmission expansion plans;; and (ii) for
working capital needs and other general business purposes.
Additionally, in October 2015, ATSI issued in total $150 million of senior notes: $75 million of 4.00% senior notes due April 2026 and
$75 million of 5.23% senior notes due October 2045. The proceeds resulting from the issuance of the senior notes were used: (i) to
fund capital expenditures, including with respect to ATSI's transmission expansion plans;; (ii) for working capital needs and other
general business purposes;; and (iii) to repay borrowings under the FirstEnergy regulated companies' money pool.
Cash Flows From Investing Activities
Cash used for investing activities in 2015 principally represented cash used for property additions. The following table summarizes
investing activities for 2015, 2014 and 2013:
Cash Used for Investing Activities
2015
2014
2013
For the Years Ended December 31,
Property Additions:
Regulated distribution
Regulated transmission
Competitive energy services
Other and reconciling adjustments
Nuclear fuel
Proceeds from asset sales
Investments
Asset removal costs
Other
(In millions)
1,108 $
952
588
56
190
(20 )
107
142
(1 )
3,122 $
972 $
1,329
939
72
233
(394 )
68
153
(13 )
3,359 $
$
$
1,272
461
827
78
250
(4 )
72
146
(9 )
3,093
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 $377 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 $136 million at Regulated Distribution relating to utility specific project investments and costs associated with
the Pennsylvania smart meter program.
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
$
20,238 $
1,039 $
3,435 $
3,499 $
12,265
(In millions)
1,708
12,523
2,083
150
13,578
2,213
3,564
1,708
1,015
184
36
1,812
877
381
—
1,839
254
55
2,539
938
1,122
—
1,500
207
32
2,117
398
787
$
56,057 $
7,052 $
10,182 $
8,540 $
—
8,169
1,438
27
7,110
—
1,274
30,283
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and capital leases.
(2)
Interest on variable-rate debt based on rates as of December 31, 2015.
(3) See Note 6, 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, 2015.
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 $3.5 billion in 2016, $0.5 billion of which are expected to relate to the
Utilities' contracts with FES.
The table above also excludes regulatory liabilities (see Note 14, Regulatory Matters), AROs (see Note 13, Asset Retirement
Obligations), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including
nuclear insurance (see Note 15, 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 $13.5 billion
(assuming 103 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to
$375 million;; and (ii) $13.1 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-$501 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, FirstEnergy has also obtained insurance
coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of
NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of
nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable annually, corresponding to their respective nuclear
interests, which provide an aggregate indemnity of up to approximately $1.96 billion (NG-$1.93 billion) for replacement power costs
incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to
assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment
for incidents at any covered nuclear facility occurring during a policy year would be approximately $15 million (NG-$15.1 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating
company for each plant. 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. FirstEnergy pays annual premiums for this coverage and
is liable for retrospective assessments of up to approximately $83 million (NG-$81 million).
38
39
During the second quarter of 2015, FE refinanced a $200 million variable interest term loan, maturing on December 31, 2016 with a
new $200 million variable interest term loan maturing on May 29, 2020.
CONTRACTUAL OBLIGATIONS
On July 1, 2015, FG and NG remarketed approximately $43 million and $296 million, respectively, of PCRBs. The PCRBs were
remarketed with fixed interest rates ranging from 3.125% to 4.00% and mandatory put dates ranging from July 2, 2018 to July 1,
2021.
In August 2015, JCP&L issued $250 million of 4.30% senior notes due January 2026. The proceeds received from the issuance of the
senior notes were used to repay a portion of JCP&L’s short-term borrowings under the FirstEnergy regulated companies' money pool
and an external revolving credit facility.
Also, in the second quarter of 2015, WP agreed to sell $150 million of new 4.45% FMBs due September 2045 and PE agreed to sell
$145 million of new 4.47% FMBs due August 2045. The transactions closed on September 17, 2015 and August 17, 2015,
respectively. The proceeds resulting from the issuance of the WP FMBs were used to repay WP’s borrowings under the FirstEnergy
regulated companies' money pool and for other general corporate purposes. The proceeds resulting from the issuance of the PE
FMBs were used to repay PE’s $145 million 5.125% FMBs that matured on August 15, 2015.
In October 2015, TrAIL issued $75 million of 3.76% senior notes due May 2025. The proceeds resulting from the issuance of the
senior notes were used: (i) to fund capital expenditures, including with respect to TrAIL's transmission expansion plans;; and (ii) for
working capital needs and other general business purposes.
Additionally, in October 2015, ATSI issued in total $150 million of senior notes: $75 million of 4.00% senior notes due April 2026 and
$75 million of 5.23% senior notes due October 2045. The proceeds resulting from the issuance of the senior notes were used: (i) to
fund capital expenditures, including with respect to ATSI's transmission expansion plans;; (ii) for working capital needs and other
general business purposes;; and (iii) to repay borrowings under the FirstEnergy regulated companies' money pool.
Cash Flows From Investing Activities
Cash used for investing activities in 2015 principally represented cash used for property additions. The following table summarizes
investing activities for 2015, 2014 and 2013:
Cash Used for Investing Activities
2015
2014
2013
For the Years Ended December 31,
Property Additions:
Regulated distribution
Regulated transmission
Competitive energy services
Other and reconciling adjustments
Nuclear fuel
Proceeds from asset sales
Investments
Asset removal costs
Other
(In millions)
$
1,108 $
952
588
56
190
(20 )
107
142
(1 )
972 $
1,329
939
72
233
(394 )
68
153
(13 )
1,272
461
827
78
250
(4 )
72
146
(9 )
$
3,122 $
3,359 $
3,093
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 $377 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 $136 million at Regulated Distribution relating to utility specific project investments and costs associated with
the Pennsylvania smart meter program.
As of December 31, 2015, our estimated cash payments under existing contractual obligations that we consider firm obligations are
as follows:
Contractual Obligations
Total
2016
2017-2018 2019-2020 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
$
$
20,238 $
1,708
12,523
2,083
150
13,578
2,213
3,564
56,057 $
(In millions)
1,039 $
1,708
1,015
184
36
1,812
877
381
7,052 $
3,435 $
—
1,839
254
55
2,539
938
1,122
10,182 $
3,499 $
—
1,500
207
32
2,117
398
787
8,540 $
12,265
—
8,169
1,438
27
7,110
—
1,274
30,283
Interest on variable-rate debt based on rates as of December 31, 2015.
(1) Excludes unamortized discounts and premiums, fair value accounting adjustments and capital leases.
(2)
(3) See Note 6, 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, 2015.
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 $3.5 billion in 2016, $0.5 billion of which are expected to relate to the
Utilities' contracts with FES.
The table above also excludes regulatory liabilities (see Note 14, Regulatory Matters), AROs (see Note 13, Asset Retirement
Obligations), reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, including
nuclear insurance (see Note 15, 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 $13.5 billion
(assuming 103 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to
$375 million;; and (ii) $13.1 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-$501 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, FirstEnergy has also obtained insurance
coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of
NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of
nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable annually, corresponding to their respective nuclear
interests, which provide an aggregate indemnity of up to approximately $1.96 billion (NG-$1.93 billion) for replacement power costs
incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to
assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment
for incidents at any covered nuclear facility occurring during a policy year would be approximately $15 million (NG-$15.1 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating
company for each plant. 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. FirstEnergy pays annual premiums for this coverage and
is liable for retrospective assessments of up to approximately $83 million (NG-$81 million).
38
39
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 FirstEnergy’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, 2015, was approximately $3.7 billion, as summarized below:
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
Other(2)
$
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts(3)
FES’ guarantee of NG’s nuclear property insurance
FES' guarantee of nuclear decommissioning costs
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
Surety Bonds
FES' LOC (long-term tax-exempt debt)(4)
LOCs(5)
Total Guarantees and Other Assurances
$
33
533
17
583
251
98
21
1,767
2,137
300
398
22
93
154
667
3,687
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
Includes guarantees of $4 million for nuclear decommissioning funding assurances, $7 million for railcar leases, and $6 million for various leases.
Includes energy and energy-related contracts associated with FES of approximately $248 million.
(1)
(2)
(3)
(4) Reflects the $1 million of interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities and the principal
amount of floating-rate PCRBs of $92 million, all of which is reflected in currently payable long-term debt on FirstEnergy's consolidated balance
sheets.
Includes $54 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facilities, $88 million issued
in connection with energy and energy related contracts, $2 million issued in connection with railcar leases, $7 million pledged in connection with
the sale and leaseback of the Beaver Valley Unit 2 by OE and $3 million pledged in connection with the sale and leaseback of Perry by OE.
(5)
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, 2015, FES has posted collateral of $188 million and AE
Supply has posted no collateral. The Regulated Distribution segment has posted collateral of $1 million.
These credit-risk-related contingent features 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 could be required.
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material
adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following
table discloses the additional credit contingent contractual obligations that may be required under certain events as of December 31,
2015:
Collateral Provisions
Split Rating (One rating agency's rating below investment grade)
BB+/Ba1 Credit Ratings
Full impact of credit contingent contractual obligations
FES
AE Supply
Utilities
Total
$
$
$
198 $
231 $
363 $
(In millions)
6 $
6 $
16 $
41 $
41 $
41 $
245
278
420
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, 2015, neither FES nor AE Supply had any collateral posted with their
affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to
post $8 million with affiliated parties.
Other Commitments and Contingencies
FirstEnergy 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, have also provided their joint and several guaranties of the
obligations of Global Holding under the facility.
In connection with Global Holding's term loan facility, a portion of Global Holding's direct and indirect membership interests in Signal
Peak, Global Rail and their affiliates along with each of FEV's and WMB Marketing Ventures,LLC's 33-1/3% membership interests in
Global Holding, are pledged to the lenders under Global Holding's facility as collateral. Failure by Global Holding to meet the terms
and conditions under its term loan facility could require FirstEnergy to be obligated under the provisions of its guarantee, resulting in
consolidation of Global Holding by FE.
During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the
Signal Peak mine to FG in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term
loan facility through 2020, resulting in a pre-tax charge of $24 million. See Note 8, Variable Interest Entities, and Note 1, Organization,
Basis of Presentation and Significant Accounting Policies - Investments, for additional information regarding FEV's investment in
Global Holding.
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 $950 million as of December 31, 2015 and primarily relates to the 2007 Bruce Mansfield Unit 1 sale and leaseback
40
41
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 FirstEnergy’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
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.
becomes unavailable in the future, FirstEnergy would remain at risk for such costs.
Collateral and Contingent-Related Features
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, 2015, was approximately $3.7 billion, as summarized below:
Guarantees and Other Assurances
FE's Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts(1)
Deferred compensation arrangements
Other(2)
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts(3)
FES’ guarantee of NG’s nuclear property insurance
FES' guarantee of nuclear decommissioning costs
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
FES' LOC (long-term tax-exempt debt)(4)
Surety Bonds
LOCs(5)
Maximum
Exposure
(In millions)
$
33
533
17
583
251
98
21
1,767
2,137
300
398
22
93
154
667
Total Guarantees and Other Assurances
$
3,687
(1)
(2)
(3)
(5)
sheets.
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
Includes guarantees of $4 million for nuclear decommissioning funding assurances, $7 million for railcar leases, and $6 million for various leases.
Includes energy and energy-related contracts associated with FES of approximately $248 million.
(4) Reflects the $1 million of interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities and the principal
amount of floating-rate PCRBs of $92 million, all of which is reflected in currently payable long-term debt on FirstEnergy's consolidated balance
Includes $54 million issued for various terms pursuant to LOC capacity available under FirstEnergy's revolving credit facilities, $88 million issued
in connection with energy and energy related contracts, $2 million issued in connection with railcar leases, $7 million pledged in connection with
the sale and leaseback of the Beaver Valley Unit 2 by OE and $3 million pledged in connection with the sale and leaseback of Perry by OE.
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, 2015, FES has posted collateral of $188 million and AE
Supply has posted no collateral. The Regulated Distribution segment has posted collateral of $1 million.
These credit-risk-related contingent features 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 could be required.
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material
adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following
table discloses the additional credit contingent contractual obligations that may be required under certain events as of December 31,
2015:
Collateral Provisions
Split Rating (One rating agency's rating below investment grade)
BB+/Ba1 Credit Ratings
Full impact of credit contingent contractual obligations
FES
AE Supply
Utilities
Total
$
$
$
198 $
231 $
363 $
(In millions)
6 $
6 $
16 $
41 $
41 $
41 $
245
278
420
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, 2015, neither FES nor AE Supply had any collateral posted with their
affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to
post $8 million with affiliated parties.
Other Commitments and Contingencies
FirstEnergy 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, have also provided their joint and several guaranties of the
obligations of Global Holding under the facility.
In connection with Global Holding's term loan facility, a portion of Global Holding's direct and indirect membership interests in Signal
Peak, Global Rail and their affiliates along with each of FEV's and WMB Marketing Ventures,LLC's 33-1/3% membership interests in
Global Holding, are pledged to the lenders under Global Holding's facility as collateral. Failure by Global Holding to meet the terms
and conditions under its term loan facility could require FirstEnergy to be obligated under the provisions of its guarantee, resulting in
consolidation of Global Holding by FE.
During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the
Signal Peak mine to FG in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term
loan facility through 2020, resulting in a pre-tax charge of $24 million. See Note 8, Variable Interest Entities, and Note 1, Organization,
Basis of Presentation and Significant Accounting Policies - Investments, for additional information regarding FEV's investment in
Global Holding.
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 $950 million as of December 31, 2015 and primarily relates to the 2007 Bruce Mansfield Unit 1 sale and leaseback
40
41
arrangement expiring in 2040. From time to time FirstEnergy and these companies enter into discussions with certain parties to the
arrangements regarding acquisition of owner participant and other interests. However, FirstEnergy cannot provide assurance that any
such acquisitions will occur on satisfactory terms or at all.
In February 2014, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for approximately
$94 million. In November 2014, NG repurchased lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for
approximately $87 million. As of December 31, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce
Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.
NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of
December 31, 2015, approximately 68% of the funds were invested in fixed income securities, 25% of the funds were invested in
equity securities and 7% 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 $1,552 million, $576 million and $147 million for fixed
income securities, equity securities and short-term investments, respectively, as of December 31, 2015, excluding $7 million of net
receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $58
million reduction in fair value as of December 31, 2015. Certain FirstEnergy subsidiaries recognize in earnings the unrealized 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 2015, FirstEnergy contributed approximately $15
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. Additionally, on June
24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining
non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term.
million to the NDT.
Interest Rate Risk
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.
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.
Assets:
Investments Other Than Cash
and Cash Equivalents:
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 9, 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, 2015 are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
2016
2017
2018
2019
2020
Thereafter
Total
Prices actively quoted(1)
Other external sources(2)
Prices based on models
Total(3)
$
$
(6 ) $
18
(4 )
8 $
1 $
(1 )
2
2 $
(In millions)
— $
(21 )
—
(21 ) $
— $
(26 )
—
(26 ) $
— $
—
(7 )
(7 ) $
— $
—
—
— $
(5 )
(30 )
(9 )
(44 )
Liabilities:
Long-term Debt:
Fixed rate
Average interest rate
Variable rate
Average interest rate
CREDIT RISK
credit risk.
Wholesale Credit 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 6, 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
2016
2017
2018
2019
2020
There-
after
Total
Fair
Value
(In millions)
Fixed Income
$
5
$
2
$
Average interest rate
8.9 %
8.9 %
—
$
— %
—
$
— %
—
$ 1,794
$ 1,801
$
1,802
— %
3.6 %
3.6 %
$
$
660
$ 1,517
$ 1,330
$ 1,035
$
541
$ 13,867
$ 18,950
$ 20,225
5.5 %
—
$
— %
6.1 %
2
$
3.5 %
4.8 %
6.5 %
6
$ 1,000
$
— %
2.2 %
5.5 %
200
$
1.9 %
5.2 %
5.3 %
86
$ 1,294
$
1,294
— %
2.0 %
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
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.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative
contracts as of December 31, 2015, not subject to regulatory accounting, an increase in commodity prices of 10% would decrease net
income by approximately $30 million during the next 12 months.
Equity Price Risk
As of December 31, 2015, the FirstEnergy pension and OPEB plan assets were approximately allocated as follows: 41% in equity
securities, 35% in fixed income securities, 6% in absolute return strategies, 10% in real estate and 8% 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. During the year ended December 31, 2015, FirstEnergy made a
$143 million contribution to its qualified pension plan. See Note 3, Pension and Other Postemployment Benefits, of the Combined
Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension plans and OPEB. In 2015, FirstEnergy's
pension plan and OPEB assets incurred losses of $(172) million, or (2.7)%, as compared to an expected return on plan assets of
7.75%.
42
43
Includes $(136) 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.
(1)
(2) Primarily represents contracts based on broker and ICE quotes.
(3)
Represents exchange traded New York Mercantile Exchange futures and options.
arrangement expiring in 2040. From time to time FirstEnergy and these companies enter into discussions with certain parties to the
arrangements regarding acquisition of owner participant and other interests. However, FirstEnergy cannot provide assurance that any
such acquisitions will occur on satisfactory terms or at all.
In February 2014, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for approximately
$94 million. In November 2014, NG repurchased lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for
approximately $87 million. As of December 31, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce
Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.
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. Additionally, on June
24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining
non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term.
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.
MARKET RISK INFORMATION
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 9, 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, 2015 are summarized by year in the following table:
Source of Information-
Fair Value by Contract Year
Prices actively quoted(1)
Other external sources(2)
Prices based on models
Total(3)
(1)
(3)
Equity Price Risk
2016
2017
2018
2019
2020
Thereafter
Total
$
$
(6 ) $
18
(4 )
8 $
1 $
(1 )
2
2 $
(In millions)
— $
— $
(21 )
—
(26 )
—
(21 ) $
(26 ) $
— $
—
(7 )
(7 ) $
— $
—
—
— $
(5 )
(30 )
(9 )
(44 )
Represents exchange traded New York Mercantile Exchange futures and options.
(2) Primarily represents contracts based on broker and ICE quotes.
Includes $(136) 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, 2015, not subject to regulatory accounting, an increase in commodity prices of 10% would decrease net
income by approximately $30 million during the next 12 months.
As of December 31, 2015, the FirstEnergy pension and OPEB plan assets were approximately allocated as follows: 41% in equity
securities, 35% in fixed income securities, 6% in absolute return strategies, 10% in real estate and 8% 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. During the year ended December 31, 2015, FirstEnergy made a
$143 million contribution to its qualified pension plan. See Note 3, Pension and Other Postemployment Benefits, of the Combined
Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension plans and OPEB. In 2015, FirstEnergy's
pension plan and OPEB assets incurred losses of $(172) million, or (2.7)%, as compared to an expected return on plan assets of
7.75%.
NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of
December 31, 2015, approximately 68% of the funds were invested in fixed income securities, 25% of the funds were invested in
equity securities and 7% 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 $1,552 million, $576 million and $147 million for fixed
income securities, equity securities and short-term investments, respectively, as of December 31, 2015, excluding $7 million of net
receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $58
million reduction in fair value as of December 31, 2015. Certain FirstEnergy subsidiaries recognize in earnings the unrealized 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 2015, FirstEnergy contributed approximately $15
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 6, 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
2016
2017
2018
2019
2020
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
$
$
$
5
8.9 %
$
2
8.9 %
$
—
— %
$
—
— %
—
— %
$ 1,794
3.6 %
$ 1,801
$
3.6 %
1,802
660
5.5 %
—
— %
$
$ 1,517
$ 1,330
$ 1,035
$
$ 13,867
$ 18,950
$ 20,225
6.1 %
2
3.5 %
$
4.8 %
6
— %
$ 1,000
$
6.5 %
2.2 %
5.2 %
86
— %
$ 1,294
5.3 %
$
2.0 %
1,294
541
5.5 %
200
1.9 %
$
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.
42
43
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.
NEW JERSEY
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 by 10%
and reduce electricity demand by 15%, in each case by 2015, 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. The costs of the 2015-
2017 plan are expected to be approximately $66 million for that three-year period, of which $19 million was incurred through
December 2015. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond,
beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%.
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 January 28, 2016, PE filed a request to increase plan spending by $2
million in order to reach the new goals for 2017 set in the July 16, 2015 order.
On February 27, 2013, the MDPSC issued an order (the February 27 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. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to
propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs
customer information. 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 27 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 27 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. The Staff of the MDPSC also recommended 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 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 March 3, 2014, pursuant to the MDPSC's regulations, PE filed its recommendations for SAIDI and SAIFI standards to apply during
the period 2016-2019. The MDPSC directed the Staff of the MDPSC to file an analysis and recommendations with respect to the
proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which the Staff of the MDPSC recommended. The
Staff of the MDPSC made its filing on July 10, 2015, and recommended that PE be required to improve its SAIDI results by
approximately 20% by 2019. The MDPSC held a hearing on the Staff's analysis and recommendations on September 1-2, 2015, and
approved PE's revised proposal for an improvement of 8.6% in its SAIDI standard by 2019 and maintained its SAIFI standard at 2015
levels. The proposed regulations incorporating the new SAIDI and SAIFI standards were approved as final in December 2015.
On April 1, 2015, PE filed its annual report on its performance relative to various service reliability standards set forth in the MDPSC’s
regulations. The MDPSC conducted hearings on the reports filed by PE and the other electric utilities in Maryland on August 24, 2015
and subsequently closed its 2014 service reliability review.
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.
On March 26, 2015, the NJBPU entered final orders which together provided an overall reduction in JCP&L's annual revenues of
approximately $34 million, effective April 1, 2015. The final order in JCP&L's base rate case proceeding directed an annual base rate
revenue reduction of approximately $115 million, including recovery of 2011 storm costs and the application of the NJBPU's modified
CTA policy approved in the generic CTA proceeding referred to below. Additionally, the final order in the generic proceeding
established to review JCP&L's major storm events of 2011 and 2012 approved the recovery of 2012 storm costs of $580 million
resulting in an increase in annual revenues of approximately $81 million. JCP&L is required to file another base rate case no later
than April 1, 2017. The NJBPU also directed that certain studies be completed. On July 22, 2015, the NJBPU approved the NJBPU
staff's recommendation to implement such studies, which will include operational and financial components and is expected to take
approximately one year to complete.
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 has filed to participate as a respondent in
that proceeding. Briefing has been completed, and oral argument has not yet been scheduled.
On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On
January 8, 2016, the NJBPU President issued an Order granting Rate Counsel’s Motion on the legal issue of whether MAIT can be
designated as a public utility. The procedural schedule has been suspended until a decision is made on this issue. See Transfer of
Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
OHIO
prior ESP;;
The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include:
• A base distribution rate freeze through May 31, 2016;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• Economic development and assistance to low-income customers for the two-year plan period at levels established in the
• A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral
wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);;
• A requirement to provide power to non-shopping customers at a market-based price set through an auction process;;
• Rider DCR that allows continued investment in the distribution system for the benefit of customers;;
• A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the
five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain
types of products totals $360 million, subject to the outcome of certain FERC proceedings;;
• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-
year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility
customers who do not switch to a competitive generation supplier;; and
• Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy
and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly
renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the
entire ESP period.
Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy
Council and the ELPC. The oral argument in this matter occurred on January 6, 2016.
The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's
Progress. The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and
recommendations on May 28, 2015, and June 4, 2015.The evidentiary hearing on the ESP IV commenced on August 31, 2015 and
concluded on October 29, 2015. On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and
Recommendation, which included PUCO Staff as a signatory party in addition to other signatories. The PUCO completed a hearing
44
45
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
NEW JERSEY
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 by 10%
and reduce electricity demand by 15%, in each case by 2015, 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. The costs of the 2015-
2017 plan are expected to be approximately $66 million for that three-year period, of which $19 million was incurred through
December 2015. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond,
beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%.
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 January 28, 2016, PE filed a request to increase plan spending by $2
million in order to reach the new goals for 2017 set in the July 16, 2015 order.
On February 27, 2013, the MDPSC issued an order (the February 27 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. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to
propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs
customer information. 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 27 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 27 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. The Staff of the MDPSC also recommended 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 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 March 3, 2014, pursuant to the MDPSC's regulations, PE filed its recommendations for SAIDI and SAIFI standards to apply during
the period 2016-2019. The MDPSC directed the Staff of the MDPSC to file an analysis and recommendations with respect to the
proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which the Staff of the MDPSC recommended. The
Staff of the MDPSC made its filing on July 10, 2015, and recommended that PE be required to improve its SAIDI results by
approximately 20% by 2019. The MDPSC held a hearing on the Staff's analysis and recommendations on September 1-2, 2015, and
approved PE's revised proposal for an improvement of 8.6% in its SAIDI standard by 2019 and maintained its SAIFI standard at 2015
levels. The proposed regulations incorporating the new SAIDI and SAIFI standards were approved as final in December 2015.
On April 1, 2015, PE filed its annual report on its performance relative to various service reliability standards set forth in the MDPSC’s
regulations. The MDPSC conducted hearings on the reports filed by PE and the other electric utilities in Maryland on August 24, 2015
and subsequently closed its 2014 service reliability review.
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.
On March 26, 2015, the NJBPU entered final orders which together provided an overall reduction in JCP&L's annual revenues of
approximately $34 million, effective April 1, 2015. The final order in JCP&L's base rate case proceeding directed an annual base rate
revenue reduction of approximately $115 million, including recovery of 2011 storm costs and the application of the NJBPU's modified
CTA policy approved in the generic CTA proceeding referred to below. Additionally, the final order in the generic proceeding
established to review JCP&L's major storm events of 2011 and 2012 approved the recovery of 2012 storm costs of $580 million
resulting in an increase in annual revenues of approximately $81 million. JCP&L is required to file another base rate case no later
than April 1, 2017. The NJBPU also directed that certain studies be completed. On July 22, 2015, the NJBPU approved the NJBPU
staff's recommendation to implement such studies, which will include operational and financial components and is expected to take
approximately one year to complete.
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 has filed to participate as a respondent in
that proceeding. Briefing has been completed, and oral argument has not yet been scheduled.
On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On
January 8, 2016, the NJBPU President issued an Order granting Rate Counsel’s Motion on the legal issue of whether MAIT can be
designated as a public utility. The procedural schedule has been suspended until a decision is made on this issue. See Transfer of
Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
OHIO
The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include:
• A base distribution rate freeze through May 31, 2016;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• Economic development and assistance to low-income customers for the two-year plan period at levels established in the
prior ESP;;
• A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral
wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);;
• A requirement to provide power to non-shopping customers at a market-based price set through an auction process;;
• Rider DCR that allows continued investment in the distribution system for the benefit of customers;;
• A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the
five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain
types of products totals $360 million, subject to the outcome of certain FERC proceedings;;
• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-
year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility
customers who do not switch to a competitive generation supplier;; and
• Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy
and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly
renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the
entire ESP period.
Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy
Council and the ELPC. The oral argument in this matter occurred on January 6, 2016.
The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's
Progress. The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and
recommendations on May 28, 2015, and June 4, 2015.The evidentiary hearing on the ESP IV commenced on August 31, 2015 and
concluded on October 29, 2015. On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and
Recommendation, which included PUCO Staff as a signatory party in addition to other signatories. The PUCO completed a hearing
44
45
on the Third Supplemental Stipulation and Recommendation in January 2016. Initial briefs are due on February 16, 2016 and reply
briefs are due on February 26, 2016. A final PUCO decision is expected in March 2016.
specified in those applications.
plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters
The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to
deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving
electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:
On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013
Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the
PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss
• An eight-year term (June 1, 2016 - May 31, 2024);;
• Contemplates continuing a base distribution rate freeze through May 31, 2024;;
• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the
price paid to FES through a proposed eight-year FERC-jurisdictional PPA for the output of the Sammis and Davis-Besse
plants and FES’ share of OVEC against the revenues received from selling such output into the PJM markets over the same
period, subject to the PUCO’s termination of Rider RRS charges/credits associated with any plants or units that may be sold
or transferred;;
• Continuing to provide power to non-shopping customers at a market-based price set through an auction process;;
• Continuing Rider DCR 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 that supports continued investment related to the distribution system for the benefit of customers;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers
as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;;
• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for
the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided
by customers for certain types of products totals $360 million, including such costs from MISO along with such costs
from PJM, subject to the outcome of certain FERC proceedings;;
• Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new
renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;;
• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential
the appeal, which is still pending. The matter has not been scheduled for oral argument.
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, subject to legislative amendments discussed above, 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.
customers;;
PENNSYLVANIA
• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval;;
• A contribution of $3 million per year ($24 million over the eight year term) to fund energy conservation programs,
economic development and job retention in the Ohio Companies service territory;;
• Contributions of $2.4 million per year ($19 million over the eight year term) to fund a fuel-fund in each of the Ohio
Companies service territories to assist low-income customers;; and
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
• A contribution of $1 million per year ($8 million over the eight year term) to establish a Customary Advisory Council to
energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn.
ensure preservation and growth of the competitive market in Ohio.
On January 27, 2016, certain parties filed a complaint at FERC against FES, OE, CEI, and TE that requests FERC review of the ESP
IV PPA under Section 205 of the FPA. In addition to such proceeding, parties have expressed an intention to challenge in the courts
and/or before FERC, the PPA or PUCO approval of the ESP IV, if approved. Management intends to vigorously defend against such
challenges.
Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans,
the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of
2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative
amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak
demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject
to legislative amendments to the peak demand reduction standards discussed below.
On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy
mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an
expedited process for review of utility proposed energy efficiency plans;; (ii) ensuring maximum credit for all of Ohio's Energy
Initiatives;; (iii) a switch from energy mandates to energy incentives;; and (iv) a declaration be made that the General Assembly may
determine energy policy of the state. No legislation has yet been introduced to change the standards described above.
On March 20, 2013, the PUCO approved the three-year energy efficiency portfolio plans for 2013-2015, originally estimated to cost
the Ohio Companies approximately $250 million over the three-year period, which is expected to be recovered in rates. Actual costs
may be lower for a number of reasons including the approval of the amended portfolio plan under SB310. On July 17, 2013, the
PUCO modified the plan to authorize the Ohio Companies to receive 20% of any revenues obtained from offering energy efficiency
and DR reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable
penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to
the extent that such costs or penalties are prudently incurred. ELPC and OCC filed applications for rehearing, which were granted for
the sole purpose of further consideration of the issue. On September 24, 2014, the Ohio Companies filed an amendment to their
portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the
plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio
On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery
period, which would 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 proposed programs, the supply would
be provided by wholesale suppliers though 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 proposal includes modifications to the Pennsylvania Companies’ existing POR
programs in order to reduce the level of uncollectibles 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 are effective through May 31, 2016. Total
costs of these plans are expected to be approximately $234 million and 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 filed their Phase III EE&C
plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in
the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On
February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint
settlement that resolves all issues in the proceeding and is subject to PPUC approval.
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. These amounts include all qualifying distribution capital
additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania
Companies as discussed below. 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. The DSIC riders are expected to be effective July 1, 2016.
46
47
The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to
deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving
electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:
• An eight-year term (June 1, 2016 - May 31, 2024);;
• Contemplates continuing a base distribution rate freeze through May 31, 2024;;
• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the
price paid to FES through a proposed eight-year FERC-jurisdictional PPA for the output of the Sammis and Davis-Besse
plants and FES’ share of OVEC against the revenues received from selling such output into the PJM markets over the same
period, subject to the PUCO’s termination of Rider RRS charges/credits associated with any plants or units that may be sold
or transferred;;
• Continuing to provide power to non-shopping customers at a market-based price set through an auction process;;
• Continuing Rider DCR 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 that supports continued investment related to the distribution system for the benefit of customers;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers
as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;;
• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for
the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided
by customers for certain types of products totals $360 million, including such costs from MISO along with such costs
from PJM, subject to the outcome of certain FERC proceedings;;
• Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new
renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;;
• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential
• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval;;
• A contribution of $3 million per year ($24 million over the eight year term) to fund energy conservation programs,
economic development and job retention in the Ohio Companies service territory;;
• Contributions of $2.4 million per year ($19 million over the eight year term) to fund a fuel-fund in each of the Ohio
Companies service territories to assist low-income customers;; and
• A contribution of $1 million per year ($8 million over the eight year term) to establish a Customary Advisory Council to
ensure preservation and growth of the competitive market in Ohio.
On January 27, 2016, certain parties filed a complaint at FERC against FES, OE, CEI, and TE that requests FERC review of the ESP
IV PPA under Section 205 of the FPA. In addition to such proceeding, parties have expressed an intention to challenge in the courts
and/or before FERC, the PPA or PUCO approval of the ESP IV, if approved. Management intends to vigorously defend against such
challenges.
Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans,
the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of
2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative
amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak
demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject
to legislative amendments to the peak demand reduction standards discussed below.
On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy
mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an
expedited process for review of utility proposed energy efficiency plans;; (ii) ensuring maximum credit for all of Ohio's Energy
Initiatives;; (iii) a switch from energy mandates to energy incentives;; and (iv) a declaration be made that the General Assembly may
determine energy policy of the state. No legislation has yet been introduced to change the standards described above.
On March 20, 2013, the PUCO approved the three-year energy efficiency portfolio plans for 2013-2015, originally estimated to cost
the Ohio Companies approximately $250 million over the three-year period, which is expected to be recovered in rates. Actual costs
may be lower for a number of reasons including the approval of the amended portfolio plan under SB310. On July 17, 2013, the
PUCO modified the plan to authorize the Ohio Companies to receive 20% of any revenues obtained from offering energy efficiency
and DR reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable
penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to
the extent that such costs or penalties are prudently incurred. ELPC and OCC filed applications for rehearing, which were granted for
the sole purpose of further consideration of the issue. On September 24, 2014, the Ohio Companies filed an amendment to their
portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the
plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio
on the Third Supplemental Stipulation and Recommendation in January 2016. Initial briefs are due on February 16, 2016 and reply
briefs are due on February 26, 2016. A final PUCO decision is expected in March 2016.
plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters
specified in those applications.
On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013
Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the
PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss
the appeal, which is still pending. The matter has not been scheduled for oral argument.
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, subject to legislative amendments discussed above, 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.
customers;;
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.
On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery
period, which would 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 proposed programs, the supply would
be provided by wholesale suppliers though 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 proposal includes modifications to the Pennsylvania Companies’ existing POR
programs in order to reduce the level of uncollectibles 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 are effective through May 31, 2016. Total
costs of these plans are expected to be approximately $234 million and 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 filed their Phase III EE&C
plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in
the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On
February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint
settlement that resolves all issues in the proceeding and is subject to PPUC approval.
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. These amounts include all qualifying distribution capital
additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania
Companies as discussed below. 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. The DSIC riders are expected to be effective July 1, 2016.
46
47
Each of the Pennsylvania Companies currently offer distribution rates under their respective Joint Petitions for Settlement approved
on April 9, 2015 by the PPUC, which, among other things, provided for a total increase in annual revenues for all Pennsylvania
Companies of $292.8 million, ($89.3 million for ME, $90.8 million for PN, $15.9 million for Penn and $96.8 million for WP), including
the recovery of $87.7 million of additional annual operating expenses, including costs associated with service reliability
enhancements to the distribution system, amortization of deferred storm costs and the remaining net book value of legacy meters,
assistance for providing service to low-income customers, and the creation of a storm reserve for each utility. Additionally, the
approved settlements include commitments to meet certain wait times for call centers and service reliability standards. The new rates
were effective May 3, 2015.
On July 16, 2013, the PPUC's Bureau of Audits initiated a focused management and operations audit of the Pennsylvania Companies
as required every eight years by statute. The PPUC issued a report on its findings and recommendations on February 12, 2015, at
which time the Pennsylvania Companies' associated implementation plan was also made public. In an order issued on March 30,
2015, the Pennsylvania Companies were directed to develop and file by May 29, 2015 a revised implementation plan regarding
certain of the operational topics addressed in the report, including addressing certain reliability matters. The Pennsylvania Companies
filed their revised implementation plan in compliance with this order. A final order adopting the plan, as revised, was entered on
November 5, 2015. The cost of compliance for the Pennsylvania Companies is currently expected to range from approximately $200
million to $230 million.
On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.
Evidentiary hearings are scheduled to commence before the PPUC on February 29, 2016. A final decision from the PPUC is expected
by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
WEST VIRGINIA
MP and PE currently operate under a Joint Stipulation and Agreement of Settlement approved by the WVPSC on February 3, 2015,
that provided for: a $15 million increase in annual base rate revenues effective February 25, 2015;; the implementation of a Vegetation
Management Surcharge to recover all costs related to both new and existing vegetation maintenance programs;; authority to establish
a regulatory asset for MATS investments placed into service in 2016 and 2017;; authority to defer, amortize and recover over a five-
year period through base rates approximately $46 million of storm restoration costs;; and elimination of the TTS for costs associated
with MP's acquisition of the Harrison plant in October 2013 and movement of those costs into base rates.
On August 14, 2015, MP and PE filed their annual ENEC case with the WVPSC proposing an approximate $165.1 million annual
increase in rates effective January 1, 2016 or before, which would be a 12.5% overall increase over existing rates. The original
proposed increase was comprised of a $97 million under-recovered balance as of June 30, 2015, a projected $23.7 million under-
recovery for the 2016 calendar year, and an actual under-recovered balance from MP and PE's TTS for Harrison Power Station of
$44.4 million. On September 10, 2015, MP and PE filed an amendment addressing the results of the recent PJM Transitional
Auctions for Capacity Performance, which resulted in a net decrease of $20.6 million from the initial requested increase to $144.5
million. A settlement was reached among all the parties increasing revenues $96.9 million and deferring other costs for recovery into
2017. The settlement was presented to the WVPSC on November 19, 2015 and a final order approving the settlement without
changes was issued on December 22, 2015, with rates effective on January 1, 2016.
On August 31, 2015, MP and PE filed with the WVPSC their biennial petition for reconciliation of the Vegetation Management
Program Surcharge and regular review of the program proposing an approximate $37.7 million annual increase in rates over a two
year period, which is a 2.8% overall increase over existing rates. The proposed increase was comprised of a $2.1 million under-
recovered balance as of June 30, 2015, a projected $23.9 million in under-recovery for the 2016/2017 rate effective period, and
recovery of previously authorized deferred vegetation management costs from April 14, 2014 through February 24, 2015 in the
amount of $49.9 million. A settlement was reached among all the parties increasing revenues $36.7 million annually for the 2016-
2017 two year rate recovery period, and was presented to the WVPSC on November 19, 2015. A final order approving the settlement
without changes was issued on December 21, 2015, with rates effective on January 1, 2016.
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, AE Supply, FG, FENOC, NG, 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 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 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 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 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
PJM Transmission Rates
PJM and its stakeholders have been debating the proper method to allocate costs for new 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. Settlement discussions
under a FERC-appointed settlement judge are ongoing.
In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent
“right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of
PJM’s RTEP process. FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether
FirstEnergy and the PJM transmission owners have a "right of first refusal" is now pending before the U.S. Court of Appeals for the
D.C. Circuit in an appeal of FERC's order approving PJM's Order No. 1000 compliance filing.
The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.
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. FirstEnergy's request for rehearing of FERC's order rejecting the settlement agreement remains
pending.
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 is pending at FERC. In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek
recovery of these charges through its formula rate. On a related issue, FirstEnergy joined certain other PJM transmission owners in a
protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On January
22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any
limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent. Certain PJM
transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP
export charge on transactions into PJM was correct and should be re-affirmed on remand. The briefs and replies thereto are now
before FERC for consideration.
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.
48
49
Each of the Pennsylvania Companies currently offer distribution rates under their respective Joint Petitions for Settlement approved
on April 9, 2015 by the PPUC, which, among other things, provided for a total increase in annual revenues for all Pennsylvania
Companies of $292.8 million, ($89.3 million for ME, $90.8 million for PN, $15.9 million for Penn and $96.8 million for WP), including
the recovery of $87.7 million of additional annual operating expenses, including costs associated with service reliability
enhancements to the distribution system, amortization of deferred storm costs and the remaining net book value of legacy meters,
assistance for providing service to low-income customers, and the creation of a storm reserve for each utility. Additionally, the
approved settlements include commitments to meet certain wait times for call centers and service reliability standards. The new rates
were effective May 3, 2015.
On July 16, 2013, the PPUC's Bureau of Audits initiated a focused management and operations audit of the Pennsylvania Companies
as required every eight years by statute. The PPUC issued a report on its findings and recommendations on February 12, 2015, at
which time the Pennsylvania Companies' associated implementation plan was also made public. In an order issued on March 30,
2015, the Pennsylvania Companies were directed to develop and file by May 29, 2015 a revised implementation plan regarding
certain of the operational topics addressed in the report, including addressing certain reliability matters. The Pennsylvania Companies
filed their revised implementation plan in compliance with this order. A final order adopting the plan, as revised, was entered on
November 5, 2015. The cost of compliance for the Pennsylvania Companies is currently expected to range from approximately $200
million to $230 million.
On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.
Evidentiary hearings are scheduled to commence before the PPUC on February 29, 2016. A final decision from the PPUC is expected
by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
WEST VIRGINIA
MP and PE currently operate under a Joint Stipulation and Agreement of Settlement approved by the WVPSC on February 3, 2015,
that provided for: a $15 million increase in annual base rate revenues effective February 25, 2015;; the implementation of a Vegetation
Management Surcharge to recover all costs related to both new and existing vegetation maintenance programs;; authority to establish
a regulatory asset for MATS investments placed into service in 2016 and 2017;; authority to defer, amortize and recover over a five-
year period through base rates approximately $46 million of storm restoration costs;; and elimination of the TTS for costs associated
with MP's acquisition of the Harrison plant in October 2013 and movement of those costs into base rates.
On August 14, 2015, MP and PE filed their annual ENEC case with the WVPSC proposing an approximate $165.1 million annual
increase in rates effective January 1, 2016 or before, which would be a 12.5% overall increase over existing rates. The original
proposed increase was comprised of a $97 million under-recovered balance as of June 30, 2015, a projected $23.7 million under-
recovery for the 2016 calendar year, and an actual under-recovered balance from MP and PE's TTS for Harrison Power Station of
$44.4 million. On September 10, 2015, MP and PE filed an amendment addressing the results of the recent PJM Transitional
Auctions for Capacity Performance, which resulted in a net decrease of $20.6 million from the initial requested increase to $144.5
million. A settlement was reached among all the parties increasing revenues $96.9 million and deferring other costs for recovery into
2017. The settlement was presented to the WVPSC on November 19, 2015 and a final order approving the settlement without
changes was issued on December 22, 2015, with rates effective on January 1, 2016.
On August 31, 2015, MP and PE filed with the WVPSC their biennial petition for reconciliation of the Vegetation Management
Program Surcharge and regular review of the program proposing an approximate $37.7 million annual increase in rates over a two
year period, which is a 2.8% overall increase over existing rates. The proposed increase was comprised of a $2.1 million under-
recovered balance as of June 30, 2015, a projected $23.9 million in under-recovery for the 2016/2017 rate effective period, and
recovery of previously authorized deferred vegetation management costs from April 14, 2014 through February 24, 2015 in the
amount of $49.9 million. A settlement was reached among all the parties increasing revenues $36.7 million annually for the 2016-
2017 two year rate recovery period, and was presented to the WVPSC on November 19, 2015. A final order approving the settlement
without changes was issued on December 21, 2015, with rates effective on January 1, 2016.
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, AE Supply, FG, FENOC, NG, 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 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 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 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 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
PJM Transmission Rates
PJM and its stakeholders have been debating the proper method to allocate costs for new 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. Settlement discussions
under a FERC-appointed settlement judge are ongoing.
In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent
“right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of
PJM’s RTEP process. FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether
FirstEnergy and the PJM transmission owners have a "right of first refusal" is now pending before the U.S. Court of Appeals for the
D.C. Circuit in an appeal of FERC's order approving PJM's Order No. 1000 compliance filing.
The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.
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. FirstEnergy's request for rehearing of FERC's order rejecting the settlement agreement remains
pending.
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 is pending at FERC. In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek
recovery of these charges through its formula rate. On a related issue, FirstEnergy joined certain other PJM transmission owners in a
protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On January
22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any
limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent. Certain PJM
transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP
export charge on transactions into PJM was correct and should be re-affirmed on remand. The briefs and replies thereto are now
before FERC for consideration.
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.
48
49
2014 ATSI Formula Rate Filing
On October 31, 2014, ATSI filed a proposal with FERC to change the structure of its formula rate from an “historical looking”
approach, where transmission rates reflect actual costs for the prior year, to a “forward looking” approach, where transmission rates
would be based on the estimated costs for the coming year, with an annual true up. On December 31, 2014, FERC issued an order
accepting ATSI's filing effective January 1, 2015, subject to refund and the outcome of hearing and settlement proceedings. FERC
subsequently issued an order on October 29, 2015, accepting a settlement agreement on the forward-looking formula rate, subject to
minor compliance requirements. The settlement agreement provides for certain changes to ATSI's formula rate template and
protocols, and also changes ATSI's ROE from 12.38% to the following values: (i) 12.38% from January 1, 2015 through June 30,
2015;; (ii) 11.06% from July 1, 2015 through December 31, 2015;; and (iii) 10.38% from January 1, 2016, unless changed pursuant to
section 205 or 206 of the FPA, provided the effective date for any change cannot be earlier than January 1, 2018.
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. On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the
NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. Additionally,
the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way
associated with the utilities' transmission assets;; (ii) a Mutual Assistance Agreement;; (iii) MAIT being deemed a public utility under
state law;; (iv) MAIT's participation in FE's regulated companies' money pool;; and (v) certain affiliated interest agreements. If
approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-
free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL. MAIT's
transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities
under the PJM Tariff. During the third quarter of 2015, FirstEnergy responded to FERC Staff's request for additional information
regarding the application. FERC approval is expected during the first quarter of 2016 with final decisions expected from the NJBPU
and PPUC by mid-2016. Following FERC approval of the transfer, MAIT expects to file a Section 204 application with FERC, and
other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their
respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application with FERC to establish its
transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve
alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001.
The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was
made in the context of mediation efforts by FERC and the Ninth Circuit in several pending proceedings to resolve all outstanding
refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The
Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California parties in May
2011. The California parties appealed FERC's decision back to the Ninth Circuit. AE Supply joined with other intervenors in the case
and filed a brief in support of FERC's dismissal of the case. On April 29, 2015, the Ninth Circuit remanded the case to FERC for
further proceedings. On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any
individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and
unreasonable rate for that particular seller in California during the 2000-2001 period. Settlement discussions under a FERC-appointed
settlement judge are ongoing. Requests for rehearing or clarification of FERC’s November 3, 2015 order by various parties, including
AE Supply, remain pending.
In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a complaint with
FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during
2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply and
other parties filed motions to dismiss, which FERC granted. The California Attorney General appealed FERC's dismissal of its
complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and
stayed the proceedings pending further order.
The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.
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 (an equity method
investment for FE), 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
50
2014 ATSI Formula Rate Filing
On October 31, 2014, ATSI filed a proposal with FERC to change the structure of its formula rate from an “historical looking”
approach, where transmission rates reflect actual costs for the prior year, to a “forward looking” approach, where transmission rates
would be based on the estimated costs for the coming year, with an annual true up. On December 31, 2014, FERC issued an order
accepting ATSI's filing effective January 1, 2015, subject to refund and the outcome of hearing and settlement proceedings. FERC
subsequently issued an order on October 29, 2015, accepting a settlement agreement on the forward-looking formula rate, subject to
minor compliance requirements. The settlement agreement provides for certain changes to ATSI's formula rate template and
protocols, and also changes ATSI's ROE from 12.38% to the following values: (i) 12.38% from January 1, 2015 through June 30,
2015;; (ii) 11.06% from July 1, 2015 through December 31, 2015;; and (iii) 10.38% from January 1, 2016, unless changed pursuant to
section 205 or 206 of the FPA, provided the effective date for any change cannot be earlier than January 1, 2018.
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. On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the
NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. Additionally,
the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way
associated with the utilities' transmission assets;; (ii) a Mutual Assistance Agreement;; (iii) MAIT being deemed a public utility under
state law;; (iv) MAIT's participation in FE's regulated companies' money pool;; and (v) certain affiliated interest agreements. If
approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-
free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL. MAIT's
transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities
under the PJM Tariff. During the third quarter of 2015, FirstEnergy responded to FERC Staff's request for additional information
regarding the application. FERC approval is expected during the first quarter of 2016 with final decisions expected from the NJBPU
and PPUC by mid-2016. Following FERC approval of the transfer, MAIT expects to file a Section 204 application with FERC, and
other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their
respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application with FERC to establish its
transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve
alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001.
The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was
refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The
Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California parties in May
2011. The California parties appealed FERC's decision back to the Ninth Circuit. AE Supply joined with other intervenors in the case
and filed a brief in support of FERC's dismissal of the case. On April 29, 2015, the Ninth Circuit remanded the case to FERC for
further proceedings. On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any
individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and
unreasonable rate for that particular seller in California during the 2000-2001 period. Settlement discussions under a FERC-appointed
settlement judge are ongoing. Requests for rehearing or clarification of FERC’s November 3, 2015 order by various parties, including
AE Supply, remain pending.
In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a complaint with
FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during
2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply and
other parties filed motions to dismiss, which FERC granted. The California Attorney General appealed FERC's dismissal of its
complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and
stayed the proceedings pending further order.
The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.
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 (an equity method
investment for FE), 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 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. The initial decision and exceptions thereto are now before FERC for review and a final order. FirstEnergy continues to
believe the costs are recoverable, subject to final ruling from FERC.
FERC Opinion No. 531
On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow
element of FERC’s ROE methodology, and announced the potential for a qualitative adjustment to the ROE methodology results.
Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth
variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight);; and (b) a long-term dividend growth forecast
based on a forecast for the U.S. economy (1/3 weight). Regarding the qualitative adjustment, for single-utility rate cases FERC
formerly pegged ROE at the median of the “zone of reasonableness” that came out of the ROE formula, whereas going forward,
FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level
sufficient to attract future investment. On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE
methodology to certain ISO New England transmission owners, and on March 3, 2015, FERC issued Opinion No. 531-B affirming its
prior rulings. Appeals of Opinion Nos. 531, 532-A and 531-B are pending before the U.S. Court of Appeals for the D.C. Circuit.
FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities
and the cost-of-service wholesale power generation transactions of MP.
MISO Capacity Portability
On June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regarding whether existing
rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FirstEnergy and other parties submitted
filings arguing that MISO's concerns largely are without foundation, FERC did not mandate a solution in response to MISO's
concerns. At FERC's direction, in May, 2015, PJM, MISO, and their respective independent market monitors provided additional
information on their various joint issues surrounding the PJM/MISO seam to assist FERC's understanding of the issues and what, if
any, additional steps FERC should take to improve the efficiency of operations at the PJM/MISO seam. Stakeholders, including FESC
on behalf of certain of its affiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions. The
various submissions and responses are now before FERC for consideration.
Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the
outcome of those auctions, including a negative impact on the prices at which those auctions would clear.
made in the context of mediation efforts by FERC and the Ninth Circuit in several pending proceedings to resolve all outstanding
FTR Underfunding Complaint
In PJM, FTRs are a mechanism to hedge congestion and operate as a financial replacement for physical firm transmission service.
FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price
differences across a specific transmission path in the PJM Day-ahead Energy Market. Due to certain language in the PJM Tariff, the
funds that are set aside to pay FTRs can be diverted to other uses, which may result in “underfunding” of FTR payments. On
February 15, 2013, FES and AE Supply filed a renewed complaint with FERC for the purpose of changing the PJM Tariff to eliminate
FTR underfunding. On June 5, 2013, FERC issued an order denying the complaint, and on June 8, 2015, denied a request for
rehearing of the June 5, 2013 order.
PJM Market Reform: PJM Capacity Performance Proposal
In December 2014, PJM submitted proposed “Capacity Performance” reforms of its RPM capacity and energy markets. On June 9,
2015, FERC issued an order conditionally approving the bulk of the proposed Capacity Performance reforms with an effective date of
April 1, 2015, and directed PJM to make a compliance filing reflecting the mandate of FERC’s order. On July 9, 2015, several parties,
including FESC on behalf of certain of its affiliates, submitted requests for rehearing for FERC's June 9, 2015 order, and PJM
submitted its compliance filing as directed by the order. The requests for rehearing and PJM's compliance filing are pending before
FERC.
In August and September 2015, PJM conducted RPM auctions pursuant to the new Capacity Performance rules. FirstEnergy’s net
competitive capacity position as a result of the BRA and Capacity Performance transition auctions is as follows:
50
51
**
35
20
($/MWD)
($/MWD)
(MW)
($/MWD)
($/MWD)
$164.77
$164.77
**
(MW)
($/MWD)
(MW)
2,765 $114.23 4,210
$59.37 3,675
875
$119.13 —
135
($/MWD)
$134.00
$134.00
$134.00
ATSI
RTO
All Other
Zones
(MW)
(MW)
(MW)
375 $120.00 6,245 $151.50 —
$149.98 6,245
985 $120.00 3,565 $151.50 240 $149.98 3,930
$151.50
150 $120.00 —
2016 - 2017
2017 - 2018
2018 - 2019*
Legacy
Obligation
Capacity
Performance
Legacy
Obligation
Capacity
Performance
Base
Generation
Capacity
Performance
3,775
7,885
1,510
9,810
275
10,195
*Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year.
**Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at
$215.00/MWD and 15 MWs cleared at $164.77/MWD.
PJM Market Reform: FERC Order No. 745 - DR
On May 23, 2014, a divided three-judge panel of the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating FERC
Order No. 745, which required that, under certain parameters, DR participating in organized wholesale energy markets be
compensated at LMP. The majority concluded that DR is a retail service, and therefore falls under state, and not federal, jurisdiction,
and that FERC, therefore, lacks jurisdiction to regulate DR. The majority also found that even if FERC had jurisdiction over DR, Order
No. 745 would be arbitrary and capricious because, under its requirements, DR was inappropriately receiving a double payment (LMP
plus the savings of foregone energy purchases). On January 25, 2016, the United States Supreme Court reversed the opinion of the
U.S. Court of Appeals for the D.C. Circuit and remanded for further action, finding FERC has statutory authority under the FPA to
regulate compensation of demand response resources in FERC-jurisdictional wholesale power markets. The United States Supreme
Court also reversed the holding that FERC's Order No. 745 was arbitrary and capricious, finding that the order included detailed
support of the chosen compensation method.
On May 23, 2014, as amended September 22, 2014, FESC, on behalf of its affiliates with market-based rate authorization, filed a
complaint asking FERC to issue an order requiring the removal of all portions of the PJM Tariff allowing or requiring DR to be included
in the PJM capacity market, with a refund effective date of May 23, 2014. FESC also requested that the results of the May 2014 PJM
BRA be considered void and legally invalid to the extent that DR cleared that auction because the participation of DR in that auction
was unlawful. However, in light of the United States Supreme Court's January 25, 2016 decision discussed above, on January 29,
2016, FESC withdrew the complaint.
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 proposed a CSAPR update rule on
November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including
Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future
cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.
EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015.
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 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 substantial and changes to FirstEnergy’s and
FES’ operations may result.
52
53
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. Under the CAA, state permitting authorities can
grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where
electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16,
2016 for MATS compliance at the Fort Martin, Harrison and Pleasants plants. On March 20, 2013, the PA DEP granted an extension
through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Bruce Mansfield plants. On February 5, 2015, the OEPA
granted an extension through April 16, 2016 for MATS compliance at the Bay Shore and Sammis plants. Nearly all spending for
MATS compliance at Bay Shore and Sammis has been completed through 2014. In addition, an EPA enforcement policy document
contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical
units. On June 29, 2015, the United States Supreme Court reversed a U.S. Court of Appeals for the D.C. Circuit decision that upheld
MATS, rejecting EPA’s regulatory approach that costs are not relevant to the decision of whether or not to regulate power plant
emissions under Section 112 of the Clean Air Act and remanded the case back to the U.S. Court of Appeals for the D.C. Circuit for
further proceedings. The U.S. Court of Appeals for the D.C. Circuit later remanded MATS back to EPA, who represented to such court
that the EPA is on track to issue a finalized MATS by April 15, 2016. Subject to the outcome of any further proceedings before the
U.S. Court of Appeals for the D.C. Circuit and how the MATS are ultimately implemented, 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 $202 million has been spent through December 31, 2015 ($80 million
at CES and $122 million at Regulated Distribution).
As a result of MATS, Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 were deactivated in April 2015, which completes
the deactivation of 5,429 MW of coal-fired plants since 2012.
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 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, those plants 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 including, but not limited to, lost profits under the contract through 2025. As part of its statement of claim, a right to
liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to
begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is
expected to be issued within sixty days from the end of the liability hearings. 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. FirstEnergy and FES intend to vigorously assert their 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. FirstEnergy and FES are unable to estimate the loss or range of loss.
FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of
which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a
defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FirstEnergy and FES fail to
reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s
and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results
of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are
unable to estimate the loss or range of loss.
As to both coal transportation agreements referenced above, FES paid in settlement approximately $70 million in liquidated damages
for delivery shortfalls in 2014 related to its deactivated plants.
As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to
notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient
justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the
termination. This matter is currently in the discovery phase of litigation and no trial date has been established. There are 6 million tons
remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going
litigation with respect to this agreement.
In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania
and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and
Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-
construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, and March 27, 2013,
EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its
operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114
request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance,
2016 - 2017
2017 - 2018
2018 - 2019*
Legacy
Obligation
Capacity
Performance
Legacy
Obligation
Capacity
Performance
Base
Generation
Capacity
Performance
(MW)
($/MWD)
(MW)
($/MWD)
(MW)
(MW)
($/MWD)
($/MWD)
(MW)
($/MWD)
($/MWD)
(MW)
2,765 $114.23 4,210
$134.00
375 $120.00 6,245 $151.50 —
$149.98 6,245
$164.77
$59.37 3,675
$134.00
985 $120.00 3,565 $151.50 240 $149.98 3,930
$164.77
$119.13 —
$134.00
150 $120.00 —
$151.50
35
**
20
**
ATSI
RTO
All Other
Zones
875
135
3,775
7,885
1,510
9,810
275
10,195
*Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year.
**Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at
$215.00/MWD and 15 MWs cleared at $164.77/MWD.
PJM Market Reform: FERC Order No. 745 - DR
On May 23, 2014, a divided three-judge panel of the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating FERC
Order No. 745, which required that, under certain parameters, DR participating in organized wholesale energy markets be
compensated at LMP. The majority concluded that DR is a retail service, and therefore falls under state, and not federal, jurisdiction,
and that FERC, therefore, lacks jurisdiction to regulate DR. The majority also found that even if FERC had jurisdiction over DR, Order
No. 745 would be arbitrary and capricious because, under its requirements, DR was inappropriately receiving a double payment (LMP
plus the savings of foregone energy purchases). On January 25, 2016, the United States Supreme Court reversed the opinion of the
U.S. Court of Appeals for the D.C. Circuit and remanded for further action, finding FERC has statutory authority under the FPA to
regulate compensation of demand response resources in FERC-jurisdictional wholesale power markets. The United States Supreme
Court also reversed the holding that FERC's Order No. 745 was arbitrary and capricious, finding that the order included detailed
support of the chosen compensation method.
On May 23, 2014, as amended September 22, 2014, FESC, on behalf of its affiliates with market-based rate authorization, filed a
complaint asking FERC to issue an order requiring the removal of all portions of the PJM Tariff allowing or requiring DR to be included
in the PJM capacity market, with a refund effective date of May 23, 2014. FESC also requested that the results of the May 2014 PJM
BRA be considered void and legally invalid to the extent that DR cleared that auction because the participation of DR in that auction
was unlawful. However, in light of the United States Supreme Court's January 25, 2016 decision discussed above, on January 29,
2016, FESC withdrew the complaint.
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
emission allowances.
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
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 proposed a CSAPR update rule on
November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including
Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future
cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.
EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015.
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 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 substantial and changes to FirstEnergy’s and
FES’ operations may result.
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. Under the CAA, state permitting authorities can
grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where
electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16,
2016 for MATS compliance at the Fort Martin, Harrison and Pleasants plants. On March 20, 2013, the PA DEP granted an extension
through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Bruce Mansfield plants. On February 5, 2015, the OEPA
granted an extension through April 16, 2016 for MATS compliance at the Bay Shore and Sammis plants. Nearly all spending for
MATS compliance at Bay Shore and Sammis has been completed through 2014. In addition, an EPA enforcement policy document
contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical
units. On June 29, 2015, the United States Supreme Court reversed a U.S. Court of Appeals for the D.C. Circuit decision that upheld
MATS, rejecting EPA’s regulatory approach that costs are not relevant to the decision of whether or not to regulate power plant
emissions under Section 112 of the Clean Air Act and remanded the case back to the U.S. Court of Appeals for the D.C. Circuit for
further proceedings. The U.S. Court of Appeals for the D.C. Circuit later remanded MATS back to EPA, who represented to such court
that the EPA is on track to issue a finalized MATS by April 15, 2016. Subject to the outcome of any further proceedings before the
U.S. Court of Appeals for the D.C. Circuit and how the MATS are ultimately implemented, 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 $202 million has been spent through December 31, 2015 ($80 million
at CES and $122 million at Regulated Distribution).
As a result of MATS, Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 were deactivated in April 2015, which completes
the deactivation of 5,429 MW of coal-fired plants since 2012.
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 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, those plants 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 including, but not limited to, lost profits under the contract through 2025. As part of its statement of claim, a right to
liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to
begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is
expected to be issued within sixty days from the end of the liability hearings. 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. FirstEnergy and FES intend to vigorously assert their 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. FirstEnergy and FES are unable to estimate the loss or range of loss.
FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of
which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a
defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FirstEnergy and FES fail to
reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s
and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results
of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are
unable to estimate the loss or range of loss.
As to both coal transportation agreements referenced above, FES paid in settlement approximately $70 million in liquidated damages
for delivery shortfalls in 2014 related to its deactivated plants.
As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to
notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient
justification to terminate the agreement. FirstEnergy and AE Supply have 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 6 million tons
remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going
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, and March 27, 2013,
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,
52
53
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.
operations may result.
implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES'
Climate Change
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. A June 2013, Presidential Climate Action
Plan outlined goals to: (i) cut carbon pollution in America by 17% by 2020 (from 2005 levels);; (ii) prepare the United States for the
impacts of climate change;; and (iii) lead international efforts to combat global climate change and prepare for its impacts. GHG
emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant
deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2015,
exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.
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. The EPA released its final regulations in August 2015, 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. 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.
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, 2015, 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 substantial.
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 must be ratified by at least 55
countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below
two degrees Celsius become effective. 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 significant 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 substantial.
The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating
category (40 CFR Part 423) in April 2013. On September 30, 2015, the EPA finalized new, more stringent effluent limits for arsenic,
mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.
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
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 unexpected, changes in timing and closure plan
requirements in the future could impact our asset retirement obligations significantly.
Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-
closure activities and to complete closure within a 12-year period, but authorizing FE 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 Bruce Mansfield
plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal
options will be sufficient for the ongoing operation of the plant. 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 Notice of Appeals 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, 2015 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
$126 million have been accrued through December 31, 2015. Included in the total are accrued liabilities of approximately $87 million
for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered
by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional
amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
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, 2015, FirstEnergy had approximately $2.3 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 required by the NRC, FirstEnergy annually recalculates and adjusts the
amount of its parental guaranties, as appropriate.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional
twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue
54
55
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.
implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES'
operations may result.
Climate Change
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. A June 2013, Presidential Climate Action
Plan outlined goals to: (i) cut carbon pollution in America by 17% by 2020 (from 2005 levels);; (ii) prepare the United States for the
impacts of climate change;; and (iii) lead international efforts to combat global climate change and prepare for its impacts. GHG
emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant
deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2015,
exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.
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.
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
Regulation of Waste Disposal
pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric
generating plants. The EPA released its final regulations in August 2015, 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. 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.
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, 2015, 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 substantial.
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 must be ratified by at least 55
countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below
two degrees Celsius become effective. 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 significant 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.
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 unexpected, changes in timing and closure plan
requirements in the future could impact our asset retirement obligations significantly.
Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-
closure activities and to complete closure within a 12-year period, but authorizing FE 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 Bruce Mansfield
plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal
options will be sufficient for the ongoing operation of the plant. 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 Notice of Appeals 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, 2015 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
$126 million have been accrued through December 31, 2015. Included in the total are accrued liabilities of approximately $87 million
for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered
by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional
amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
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
OTHER LEGAL PROCEEDINGS
day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a
Nuclear Plant Matters
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 substantial.
The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating
category (40 CFR Part 423) in April 2013. On September 30, 2015, the EPA finalized new, more stringent effluent limits for arsenic,
mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.
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
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of
December 31, 2015, FirstEnergy had approximately $2.3 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 required by the NRC, FirstEnergy annually recalculates and adjusts the
amount of its parental guaranties, as appropriate.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional
twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue
54
55
operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record
and admit a contention on the NRC’s Continued Storage Rule. On August 6, 2015, this intervenor sought review of the NRC
Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC has moved to intervene in that proceeding.
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 related to the Shield Building analysis in 2016.
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. These and other NRC requirements adopted as a result of the accident at
Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FirstEnergy's nuclear
facilities.
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 14,
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.
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 14, 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.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the
year ended December 31, 2015, FirstEnergy made contributions of $143 million to its qualified pension plan. The underfunded status
of FirstEnergy’s qualified and non-qualified pension and OPEB plans as of December 31, 2015 was $4.0 billion.
FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment 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, 2015, 2014, and 2013 were $369 million ($242 million net of amounts capitalized), $1,243 million ($835
million net of amounts capitalized), and $(396) million ($(256) 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 4.50%, 4.25% and 5.00% as of December 31, 2015, 2014 and 2013, respectively. The assumed discount rates for
OPEB were 4.25%, 4.00% and 4.75% as of December 31, 2015, 2014 and 2013, 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 2015, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of
$(172) million or (2.7)% compared to $387 million, or 6.2% in 2014 and losses of $(22) million, or (0.3)% in 2013 and assumed a
7.75% rate of return for both years on plan assets which generated $476 million, $496 million and $535 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 2016 was lowered to 7.50%.
During 2014, the Society of Actuaries published new mortality tables and improvement scales reflecting improved life expectancies
and an expectation that the trend will continue. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of
the RP2014 mortality table with blue collar adjustment for females and projection scale SS2014INT was most appropriate as of
December 31, 2015. As such, the RP2014 mortality table with projection scale SS2014INT was utilized to determine the 2015 benefit
cost and obligation as of December 31, 2015 for the FirstEnergy pension and OPEB plans. The impact of using the RP2014 mortality
table and projection scale SS2014INT resulted in an increase in the projected benefit obligation of $49 million and $1 million for the
pension and OPEB plans, respectively, and was included in the 2015 pension and OPEB mark-to-market adjustment.
Based on discount rates of 4.50% for pension, 4.25% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its
2016 pre-tax net periodic benefit cost (including amounts capitalized) to be approximately $122 million (excluding any actuarial mark-
to-market adjustments that would be recognized in 2016). 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,
2015.
Postemployment Benefits Expense (Credits)
2015
2014
2013
Pension
OPEB
Total
$
$
(In millions)
316 $
(61 )
255 $
939 $
(101 )
838 $
(134 )
(196 )
(330 )
56
57
operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record
and admit a contention on the NRC’s Continued Storage Rule. On August 6, 2015, this intervenor sought review of the NRC
Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC has moved to intervene in that proceeding.
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 related to the Shield Building analysis in 2016.
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. These and other NRC requirements adopted as a result of the accident at
Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FirstEnergy's nuclear
facilities.
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 14,
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.
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 14, 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.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the
year ended December 31, 2015, FirstEnergy made contributions of $143 million to its qualified pension plan. The underfunded status
of FirstEnergy’s qualified and non-qualified pension and OPEB plans as of December 31, 2015 was $4.0 billion.
FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment 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, 2015, 2014, and 2013 were $369 million ($242 million net of amounts capitalized), $1,243 million ($835
million net of amounts capitalized), and $(396) million ($(256) 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 4.50%, 4.25% and 5.00% as of December 31, 2015, 2014 and 2013, respectively. The assumed discount rates for
OPEB were 4.25%, 4.00% and 4.75% as of December 31, 2015, 2014 and 2013, 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 2015, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of
$(172) million or (2.7)% compared to $387 million, or 6.2% in 2014 and losses of $(22) million, or (0.3)% in 2013 and assumed a
7.75% rate of return for both years on plan assets which generated $476 million, $496 million and $535 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 2016 was lowered to 7.50%.
During 2014, the Society of Actuaries published new mortality tables and improvement scales reflecting improved life expectancies
and an expectation that the trend will continue. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of
the RP2014 mortality table with blue collar adjustment for females and projection scale SS2014INT was most appropriate as of
December 31, 2015. As such, the RP2014 mortality table with projection scale SS2014INT was utilized to determine the 2015 benefit
cost and obligation as of December 31, 2015 for the FirstEnergy pension and OPEB plans. The impact of using the RP2014 mortality
table and projection scale SS2014INT resulted in an increase in the projected benefit obligation of $49 million and $1 million for the
pension and OPEB plans, respectively, and was included in the 2015 pension and OPEB mark-to-market adjustment.
Based on discount rates of 4.50% for pension, 4.25% for OPEB and an estimated return on assets of 7.50%, FirstEnergy expects its
2016 pre-tax net periodic benefit cost (including amounts capitalized) to be approximately $122 million (excluding any actuarial mark-
to-market adjustments that would be recognized in 2016). 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,
2015.
Postemployment Benefits Expense (Credits)
2015
2014
2013
Pension
OPEB
Total
$
$
(In millions)
316 $
(61 )
255 $
939 $
(101 )
838 $
(134 )
(196 )
(330 )
56
57
Health care cost trends continue to increase and will affect future OPEB costs. The 2015 composite health care trend rate
assumptions were approximately 6.0-5.5%, compared to 7.5-7.0% in 2014, 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 2016 pension and OPEB net periodic benefit costs from changes in key
assumptions are as follows:
Goodwill
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)
273
13
N/A
19 $
1 $
25 $
292
14
25
Please see Note 3, Pension and Other Postemployment Benefits for additional information.
analysis was not necessary for 2015.
Long-Lived Assets
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of
such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum
of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater
than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to
estimate fair value. See Note 1, Organization and Basis of Presentation.
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, 2015, are described further in Note 13, 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 5, Taxes for additional information.
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.
For 2015, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units,
assessing economic, industry and market considerations in addition to the reporting unit's overall financial performance. It was
determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative
FirstEnergy performed a quantitative assessment of the CES reporting unit as of July 31, 2015. Key assumptions incorporated into
the CES discounted cash flow analysis requiring significant management judgment included the following:
• Future Energy and Capacity Prices: FirstEnergy used observable market information for near term forward power prices,
PJM auction results for near term capacity pricing, and a longer-term 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: FirstEnergy used 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: FirstEnergy used 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
• Discount Rate: A discount rate of 8.25%, based on a capital structure, return on debt and return on equity of selected
performance reforms in the PJM market.
comparable companies.
• 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 results of the quantitative analysis, the fair value of the CES reporting unit exceeded its carrying value by approximately
10%. Continued weak economic conditions, lower than expected power and capacity prices, a higher cost of capital, and revised
environmental requirements could have a negative impact on future goodwill assessments.
See Note 1, Organization and Basis of Presentation for additional details.
NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by
applying a five-step model in accordance with the core principle 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. In
addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue
recognition are expanded. In August 2015, the FASB issued a final Accounting Standards Update deferring the effective date until
fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after
December 15, 2016, (the original effective date). The standard shall be applied retrospectively to each period presented or as a
cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of
adopting this standard.
In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends
current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate
whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15,
2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by
recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments
retrospectively. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
In April 2015, the FASB issued, 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 guidance is effective for financial statements issued for fiscal years beginning after
December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not
been previously issued. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the
58
59
Health care cost trends continue to increase and will affect future OPEB costs. The 2015 composite health care trend rate
assumptions were approximately 6.0-5.5%, compared to 7.5-7.0% in 2014, 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 2016 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
Decrease by .25%
Long-term return on assets
Decrease by .25%
Health care trend rate
Increase by 1.0%
(In millions)
273
13
N/A
19 $
1 $
25 $
292
14
25
Please see Note 3, Pension and Other Postemployment Benefits for additional information.
Long-Lived Assets
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of
such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum
of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater
than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to
estimate fair value. See Note 1, Organization and Basis of Presentation.
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
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
AROs as of December 31, 2015, are described further in Note 13, Asset Retirement Obligations.
asset.
liability recognition.
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 5, 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.
For 2015, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units,
assessing economic, industry and market considerations in addition to the reporting unit's overall financial performance. It was
determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative
analysis was not necessary for 2015.
FirstEnergy performed a quantitative assessment of the CES reporting unit as of July 31, 2015. Key assumptions incorporated into
the CES discounted cash flow analysis requiring significant management judgment included the following:
• Future Energy and Capacity Prices: FirstEnergy used observable market information for near term forward power prices,
PJM auction results for near term capacity pricing, and a longer-term 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: FirstEnergy used 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: FirstEnergy used 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 8.25%, based on a capital structure, return on debt and return on equity of selected
comparable companies.
• 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 results of the quantitative analysis, the fair value of the CES reporting unit exceeded its carrying value by approximately
10%. Continued weak economic conditions, lower than expected power and capacity prices, a higher cost of capital, and revised
environmental requirements could have a negative impact on future goodwill assessments.
See Note 1, Organization and Basis of Presentation for additional details.
NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by
applying a five-step model in accordance with the core principle 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. In
addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue
recognition are expanded. In August 2015, the FASB issued a final Accounting Standards Update deferring the effective date until
fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after
December 15, 2016, (the original effective date). The standard shall be applied retrospectively to each period presented or as a
cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of
adopting this standard.
In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends
current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate
whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15,
2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by
recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments
retrospectively. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
In April 2015, the FASB issued, 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 guidance is effective for financial statements issued for fiscal years beginning after
December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not
been previously issued. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the
58
59
financial statements. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of
Debt Issuance Costs Associated with Line-of-Credit Arrangements", which states given the absence of authoritative guidance within
ASU 2015-03 for debt issuance costs related to the line-of-credit arrangements, the SEC staff would not object to presenting those
deferred debt issuance costs as an asset and subsequently amortizing the costs ratably over the term of the arrangement, regardless
of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy will adopt ASU 2015-15 and ASU 2015-03
beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES debt issuance costs included in Deferred Charges and
Other Assets were $93 million and $17 million, respectively. FirstEnergy will elect to continue presenting debt issuance costs relating
to its revolving credit facilities as an asset.
In August 2015, the FASB issued ASU 2015 -13, "Application of the NPNS Scope Exception to Certain Electricity Contracts within
Nodal Energy Markets", which confirmed that forward physical contracts for the sale or purchase of electricity meet the physical
delivery criterion within the NPNS scope exception when the electricity is transmitted through a grid managed by an ISO. As a result,
an entity can elect the NPNS exception within the derivative accounting guidance for such contracts, provided that the other NPNS
criteria are also met. The ASU was effective on issuance and requires prospective application. There was no material effect on
FirstEnergy's financial statements resulting from the issuance of ASU 2015-13.
In November 2015, the FASB issued ASU 2015 - 17, "Balance Sheet Classification of Deferred Taxes", which requires all deferred tax
assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance
will be effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is
permitted for all entities as of the beginning of an interim or annual reporting period. The guidance may be applied either
prospectively, for all deferred tax assets and liabilities, or retrospectively. FirstEnergy early adopted ASU 2015-17 as of December
2015, and applied the new guidance retrospectively to all prior periods presented in the financial statements. There was no impact
from the early adoption of ASU 2015-17 on the Consolidated Statements of Income. On the Consolidated Balance Sheet as of
December 31, 2014, FirstEnergy and FES reclassified $518 million and $27 million of Accumulated Deferred Income Taxes from
Current Assets to Noncurrent Liabilities.
In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial
Assets and Financial Liabilities". Changes to the current GAAP model primarily affect 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 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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information relating to market risk is set forth in Management's Discussion and Analysis of Financial Condition and Results of
Operations.
firm, as stated in their report which appears herein.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT REPORTS
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 2015 consolidated financial
statements as stated in their audit report included herein.
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 2015.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control - Integrated Framework published in 2013, management conducted an
evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive
Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over
financial reporting was effective as of December 31, 2015. The effectiveness of the Company’s internal control over financial
reporting, as of December 31, 2015, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting
60
61
financial statements. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of
Debt Issuance Costs Associated with Line-of-Credit Arrangements", which states given the absence of authoritative guidance within
ASU 2015-03 for debt issuance costs related to the line-of-credit arrangements, the SEC staff would not object to presenting those
deferred debt issuance costs as an asset and subsequently amortizing the costs ratably over the term of the arrangement, regardless
of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy will adopt ASU 2015-15 and ASU 2015-03
beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES debt issuance costs included in Deferred Charges and
Other Assets were $93 million and $17 million, respectively. FirstEnergy will elect to continue presenting debt issuance costs relating
to its revolving credit facilities as an asset.
In August 2015, the FASB issued ASU 2015 -13, "Application of the NPNS Scope Exception to Certain Electricity Contracts within
Nodal Energy Markets", which confirmed that forward physical contracts for the sale or purchase of electricity meet the physical
delivery criterion within the NPNS scope exception when the electricity is transmitted through a grid managed by an ISO. As a result,
an entity can elect the NPNS exception within the derivative accounting guidance for such contracts, provided that the other NPNS
criteria are also met. The ASU was effective on issuance and requires prospective application. There was no material effect on
FirstEnergy's financial statements resulting from the issuance of ASU 2015-13.
In November 2015, the FASB issued ASU 2015 - 17, "Balance Sheet Classification of Deferred Taxes", which requires all deferred tax
assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance
will be effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is
permitted for all entities as of the beginning of an interim or annual reporting period. The guidance may be applied either
prospectively, for all deferred tax assets and liabilities, or retrospectively. FirstEnergy early adopted ASU 2015-17 as of December
2015, and applied the new guidance retrospectively to all prior periods presented in the financial statements. There was no impact
from the early adoption of ASU 2015-17 on the Consolidated Statements of Income. On the Consolidated Balance Sheet as of
December 31, 2014, FirstEnergy and FES reclassified $518 million and $27 million of Accumulated Deferred Income Taxes from
Current Assets to Noncurrent Liabilities.
In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial
Assets and Financial Liabilities". Changes to the current GAAP model primarily affect 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 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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information relating to market risk is set forth in Management's Discussion and Analysis of Financial Condition and Results of
Operations.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT REPORTS
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 2015 consolidated financial
statements as stated in their audit report included herein.
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 2015.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control - Integrated Framework published in 2013, management conducted an
evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the Chief Executive
Officer and the Chief Financial Officer. Based on that evaluation, management concluded that the Company’s internal control over
financial reporting was effective as of December 31, 2015. The effectiveness of the Company’s internal control over financial
reporting, as of December 31, 2015, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting
firm, as stated in their report which appears herein.
60
61
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
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, comprehensive
income, common stockholders’ equity, and cash flows, present fairly, in all material respects, the financial position of FirstEnergy
Corp. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2015 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 Item15(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, 2015, 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, in 2015 the Company changed the manner in which deferred tax
assets and liabilities, along with any related valuation allowance, are classified on the balance sheet.
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
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2016
(In millions)
REVENUES:
Electric utilities
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 long-lived assets
Total operating expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Loss on debt redemptions
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total other expense
INCOME TAXES (BENEFITS)
INCOME FROM CONTINUING OPERATIONS
NET INCOME
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Net Income
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Net Income
For the Years Ended December 31,
2015
2014
2013
$
10,636 $
4,390
15,026
9,871 $
5,178
15,049
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
—
1.37 $
—
1.37 $
1.37 $
—
1.37 $
422
424
1.44 $
2,280
4,716
3,962
835
1,220
12
962
—
13,987
1,062
(8 )
72
—
(1,073 )
118
(891 )
171
(42 )
213
86
0.51 $
0.20
0.71 $
0.51 $
0.20
0.71 $
420
421
1.44 $
$
$
$
$
$
$
9,451
5,441
14,892
2,496
3,963
3,593
(256 )
1,202
539
978
795
13,310
1,582
(132 )
33
—
(1,016 )
103
(1,012 )
570
195
375
17
392
0.90
0.04
0.94
0.90
0.04
0.94
418
419
1.65
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)
578 $
299 $
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic
Diluted
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
* Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
62
63
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, comprehensive
income, common stockholders’ equity, and cash flows, present fairly, in all material respects, the financial position of FirstEnergy
Corp. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2015 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 Item15(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, 2015, 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, in 2015 the Company changed the manner in which deferred tax
assets and liabilities, along with any related valuation allowance, are classified on the balance sheet.
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
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2016
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
2015
2014
2013
$
10,636 $
4,390
15,026
9,871 $
5,178
15,049
(In millions)
REVENUES:
Electric utilities
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 long-lived assets
Total operating expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Loss on debt redemptions
Investment income (loss)
Impairment of equity method investment
Interest expense
Capitalized financing costs
Total other expense
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
(8 )
72
—
(1,073 )
118
(891 )
171
(42 )
213
86
9,451
5,441
14,892
2,496
3,963
3,593
(256 )
1,202
539
978
795
13,310
1,582
(132 )
33
—
(1,016 )
103
(1,012 )
570
195
375
17
392
0.90
0.04
0.94
0.90
0.04
0.94
418
419
1.65
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
INCOME FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)
NET INCOME
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Net Income
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Net Income
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic
Diluted
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
$
$
$
$
$
$
578 $
299 $
1.37 $
—
1.37 $
1.37 $
—
1.37 $
422
424
1.44 $
0.51 $
0.20
0.71 $
0.51 $
0.20
0.71 $
420
421
1.44 $
* Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
62
63
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs
Amortized gains (losses) 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
For the Years Ended December 31,
2015
2014
2013
$
578 $
299 $
392
(116 )
5
(11 )
(122 )
(47 )
(75 )
(76 )
(2 )
26
(52 )
(14 )
(38 )
(160 )
3
(10 )
(167 )
(66 )
(101 )
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY
CORP.
$
503 $
261 $
291
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
ASSETS
Customers, net of allowance for uncollectible accounts of $69 in 2015 and $59 in 2014
Other, net of allowance for uncollectible accounts of $5 in 2015 and 2014
Materials and supplies, at average cost
December 31,
December 31,
2015
2014
$
131 $
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
CURRENT LIABILITIES:
Currently payable long-term debt
Short-term borrowings
Accounts payable
Accrued taxes
Accrued compensation and benefits
Derivatives
Other
CAPITALIZATION:
Common stockholders’ equity-
Other paid-in capital
Retained earnings
Accumulated other comprehensive income
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
LIABILITIES AND CAPITALIZATION
52,187 $
51,648
$
$
Common stock, $0.10 par value, authorized 490,000,000 shares - 423,560,397 and 421,102,570
shares outstanding as of December 31, 2015 and December 31, 2014, respectively
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 15)
$
52,187 $
51,648
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
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
1,379
9,145
1,166 $
1,708
1,075
519
334
106
694
5,602
42
9,952
171
2,256
12,421
1
12,422
19,192
31,614
6,773
4,245
1,410
791
197
1,555
14,971
85
1,554
225
817
128
159
230
160
3,358
47,484
14,150
33,334
2,449
35,783
2,341
881
3,222
6,418
1,411
1,456
9,285
804
1,799
1,279
490
329
167
693
5,561
42
9,847
246
2,285
12,420
2
12,422
19,176
31,598
6,539
3,932
1,387
824
217
1,590
14,489
64
65
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
ASSETS
Customers, net of allowance for uncollectible accounts of $69 in 2015 and $59 in 2014
Other, net of allowance for uncollectible accounts of $5 in 2015 and 2014
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
Other
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 423,560,397 and 421,102,570
shares outstanding as of December 31, 2015 and December 31, 2014, respectively
Other paid-in capital
Accumulated other comprehensive income
Retained earnings
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
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 15)
December 31,
2015
December 31,
2014
$
$
$
$
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
1,379
9,145
52,187 $
1,166 $
1,708
1,075
519
334
106
694
5,602
42
9,952
171
2,256
12,421
1
12,422
19,192
31,614
6,773
4,245
1,410
791
197
1,555
14,971
52,187 $
85
1,554
225
817
128
159
230
160
3,358
47,484
14,150
33,334
2,449
35,783
2,341
881
3,222
6,418
1,411
1,456
9,285
51,648
804
1,799
1,279
490
329
167
693
5,561
42
9,847
246
2,285
12,420
2
12,422
19,176
31,598
6,539
3,932
1,387
824
217
1,590
14,489
51,648
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
65
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
FIRSTENERGY CORP.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, except share amounts)
Net income
Amortized losses 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 $63 million of income
tax benefits (Note 3)
Stock-based compensation
Cash dividends declared on common stock
Stock issuance - employee benefits
Balance, December 31, 2013
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 3)
Stock-based compensation
Cash dividends declared on common stock
Stock issuance - employee benefits
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 3)
Stock-based compensation
Cash dividends declared on common stock
Common Stock
Number of
Shares
418,216,437 $
Par Value
Other
Paid-In
Capital
Accumulated
Other
Comprehensive
Income
42 $
9,769 $
385 $
Retained
Earnings
2,888
392
2
(6 )
(97 )
412,122
(4 )
11
418,628,559
42
9,776
284
(690 )
2,590
299
(604 )
2,285
578
(1 )
16
(53 )
246
4
(7 )
(72 )
20
51
9,847
45
60
9,952 $
2,474,011
421,102,570
42
Stock issuance - employee benefits
Balance, December 31, 2015
2,457,827
423,560,397 $
42 $
(607 )
171 $
2,256
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
66
67
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible amortization
(In millions)
Net Income
CASH FLOWS FROM OPERATING ACTIVITIES:
Impairments of long-lived assets
Investment impairment, including equity method investment
Pension and OPEB mark-to-market adjustment
Deferred income taxes and investment tax credits, net
Deferred costs on sale leaseback transaction, net
For the Years Ended December 31,
2015
2014
2013
$
578 $
299 $
Deferred purchased power and other costs
Asset removal costs charged to income
Retirement benefits
Commodity derivative transactions, net (Note 10)
Pension trust contributions
Gain on sale of investment securities held in trusts
Loss on debt redemptions
Make-whole premiums paid on debt redemptions
Lease payments on sale and leaseback transaction
Income from discontinued operations (Note 19)
Changes in current assets and liabilities-
Receivables
Materials and supplies
Prepayments and other current assets
Accounts payable
Accrued taxes
Accrued interest
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
Tender premiums paid on debt redemptions
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
Cash investments
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:
Cash paid (received) during the year -
Interest (net of amounts capitalized)
Income taxes (received), net of refunds
1,836
42
464
242
284
48
(105 )
55
(20 )
(73 )
(143 )
(23 )
—
—
(131 )
—
184
(15 )
(10 )
(243 )
29
(6 )
5
75
140
234
3,447
1,311
—
(879 )
(91 )
—
(607 )
(13 )
(279 )
(2,704 )
(190 )
20
1,534
(1,648 )
(142 )
7
1
(3,122 )
1,563
—
37
835
162
48
(115 )
28
(53 )
64
—
(64 )
8
—
(137 )
(86 )
139
(65 )
126
42
(165 )
31
(22 )
23
(54 )
69
2,713
4,528
—
(1,759 )
(1,605 )
—
(604 )
(47 )
513
(3,312 )
(233 )
394
2,133
(2,236 )
35
(153 )
13
(3,359 )
46
85
131 $
(133 )
218
85 $
1,028 $
37 $
931 $
(103 ) $
$
$
$
392
2,022
795
90
(256 )
243
48
(76 )
20
(168 )
(3 )
—
(56 )
132
(187 )
(136 )
(17 )
(114 )
96
(126 )
(25 )
85
(10 )
19
(62 )
(36 )
(8 )
2,662
3,745
1,435
(3,600 )
—
(110 )
(920 )
(73 )
477
(2,638 )
(250 )
4
2,047
(2,096 )
(23 )
(146 )
9
(3,093 )
46
172
218
969
36
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
FIRSTENERGY CORP.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, except share amounts)
Net income
Amortized losses 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 $63 million of income
tax benefits (Note 3)
Stock-based compensation
Cash dividends declared on common stock
Stock issuance - employee benefits
Balance, December 31, 2013
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 3)
Stock-based compensation
Cash dividends declared on common stock
Stock issuance - employee benefits
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 3)
Stock-based compensation
Cash dividends declared on common stock
Stock issuance - employee benefits
Balance, December 31, 2015
Common Stock
Number of
Shares
Par Value
Other
Paid-In
Capital
Accumulated
Other
Comprehensive
Income
418,216,437 $
42 $
9,769 $
385 $
Retained
Earnings
2,888
392
412,122
418,628,559
42
9,776
284
2
(6 )
(97 )
(1 )
16
(53 )
246
4
(7 )
(72 )
(690 )
2,590
299
(604 )
2,285
578
(607 )
(4 )
11
20
51
9,847
45
60
2,474,011
421,102,570
42
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
2,457,827
423,560,397 $
42 $
9,952 $
171 $
2,256
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible amortization
Impairments of long-lived assets
Investment impairment, including equity method investment
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 other costs
Asset removal costs charged to income
Retirement benefits
Commodity derivative transactions, net (Note 10)
Pension trust contributions
Gain on sale of investment securities held in trusts
Loss on debt redemptions
Make-whole premiums paid on debt redemptions
Lease payments on sale and leaseback transaction
Income from discontinued operations (Note 19)
Changes in current assets and liabilities-
Receivables
Materials and supplies
Prepayments and other current assets
Accounts payable
Accrued taxes
Accrued interest
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
Tender premiums paid on debt redemptions
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
Cash investments
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:
Cash paid (received) during the year -
Interest (net of amounts capitalized)
Income taxes (received), net of refunds
For the Years Ended December 31,
2015
2014
2013
$
578 $
299 $
1,836
42
464
242
284
48
(105 )
55
(20 )
(73 )
(143 )
(23 )
—
—
(131 )
—
184
(15 )
(10 )
(243 )
29
(6 )
5
75
140
234
3,447
1,311
—
(879 )
(91 )
—
(607 )
(13 )
(279 )
(2,704 )
(190 )
20
1,534
(1,648 )
7
(142 )
1
(3,122 )
46
85
131 $
1,563
—
37
835
162
48
(115 )
28
(53 )
64
—
(64 )
8
—
(137 )
(86 )
139
(65 )
126
42
(165 )
31
(22 )
23
(54 )
69
2,713
4,528
—
(1,759 )
(1,605 )
—
(604 )
(47 )
513
(3,312 )
(233 )
394
2,133
(2,236 )
35
(153 )
13
(3,359 )
(133 )
218
85 $
1,028 $
37 $
931 $
(103 ) $
$
$
$
392
2,022
795
90
(256 )
243
48
(76 )
20
(168 )
(3 )
—
(56 )
132
(187 )
(136 )
(17 )
(114 )
96
(126 )
(25 )
85
(10 )
19
(62 )
(36 )
(8 )
2,662
3,745
1,435
(3,600 )
—
(110 )
(920 )
(73 )
477
(2,638 )
(250 )
4
2,047
(2,096 )
(23 )
(146 )
9
(3,093 )
46
172
218
969
36
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
66
67
FIRSTENERGY CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Note
Number
Page
Number
of Terms.
1
2
3
4
5
6
7
8
9
Organization and Basis of Presentation ...........................................................................................
Accumulated Other Comprehensive Income ....................................................................................
Pension and Other Postemployment Benefits ..................................................................................
Stock-Based Compensation Plans ...................................................................................................
Taxes ................................................................................................................................................
Leases ..............................................................................................................................................
Intangible Assets ..............................................................................................................................
Variable Interest Entities ...................................................................................................................
Fair Value Measurements .................................................................................................................
69
76
79
86
89
95
96
96
99
10
Derivative Instruments ......................................................................................................................
104
11
Capitalization ....................................................................................................................................
109
12
Short-Term Borrowings and Bank Lines of Credit ............................................................................
114
13
Asset Retirement Obligations ...........................................................................................................
115
14
Regulatory Matters ...........................................................................................................................
116
15
Commitments, Guarantees and Contingencies ................................................................................
124
16
Transactions with Affiliated Companies ............................................................................................
130
liabilities based on federal and state jurisdictions.
17
Supplemental Guarantor Information ...............................................................................................
132
18
Segment Information ........................................................................................................................
141
19
Discontinued Operations ..................................................................................................................
143
20
Summary of Quarterly Financial Data (Unaudited) ..........................................................................
144
68
69
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary
FirstEnergy Corp. 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 common stock 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 common stock of other direct subsidiaries including:
FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and AE Ventures, Inc.
FirstEnergy and its subsidiaries are 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, serving six million customers in the
Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW 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.
FirstEnergy follows GAAP and complies 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, 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 8, Variable
Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with
respect to which they are not the primary beneficiary and do not exercise control, 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 share of
the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. 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.
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
FIRSTENERGY CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Note
Number
1
2
3
4
5
6
7
8
9
Organization and Basis of Presentation ...........................................................................................
Accumulated Other Comprehensive Income ....................................................................................
Pension and Other Postemployment Benefits ..................................................................................
Stock-Based Compensation Plans ...................................................................................................
Taxes ................................................................................................................................................
Leases ..............................................................................................................................................
Intangible Assets ..............................................................................................................................
Variable Interest Entities ...................................................................................................................
Fair Value Measurements .................................................................................................................
Page
Number
69
76
79
86
89
95
96
96
99
10
Derivative Instruments ......................................................................................................................
104
11
Capitalization ....................................................................................................................................
109
12
Short-Term Borrowings and Bank Lines of Credit ............................................................................
114
13
Asset Retirement Obligations ...........................................................................................................
115
14
Regulatory Matters ...........................................................................................................................
116
15
Commitments, Guarantees and Contingencies ................................................................................
124
16
Transactions with Affiliated Companies ............................................................................................
130
17
Supplemental Guarantor Information ...............................................................................................
132
18
Segment Information ........................................................................................................................
141
19
Discontinued Operations ..................................................................................................................
143
20
Summary of Quarterly Financial Data (Unaudited) ..........................................................................
144
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary
of Terms.
FirstEnergy Corp. 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 common stock 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 common stock of other direct subsidiaries including:
FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and AE Ventures, Inc.
FirstEnergy and its subsidiaries are 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, serving six million customers in the
Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW 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.
FirstEnergy follows GAAP and complies 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, 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 8, Variable
Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with
respect to which they are not the primary beneficiary and do not exercise control, 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 share of
the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. 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.
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.
68
69
The following table provides information about the composition of net regulatory assets as of December 31, 2015 and December 31,
2014, and the changes during the year ended December 31, 2015:
Regulatory Assets by Source
December 31,
2015
December 31,
2014
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
185 $
355
(272 )
(372 )
115
243
335
186
403
170
240 $
370
(305 )
(254 )
90
281
182
153
465
189
Net Regulatory Assets included on the Consolidated Balance Sheets
$
1,348
$
1,411
$
(55 )
(15 )
33
(118 )
25
(38 )
153
33
(62 )
(19 )
(63 )
Regulatory assets that do not earn a current return totaled approximately $148 million and $488 million as of December 31, 2015 and
2014, respectively, primarily related to storm damage costs. JCP&L's regulatory asset related to 2011 and 2012 storm damage costs
began earning a return on April 1, 2015. Effective with the approved settlement on April 9, 2015, associated with their general base
rate case, the Pennsylvania Companies transferred the net book value of legacy meters from plant-in-service to regulatory assets,
which is being recovered over five years.
As of December 31, 2015 and December 31, 2014, FirstEnergy had approximately $116 million and $243 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, 2015 and 2014 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer
receivables as of December 31, 2015 and 2014 are included below.
70
Regulatory Assets by Source
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
December 31,
December 31,
2015
2014
Increase
(Decrease)
$
185 $
240 $
(In millions)
355
(272 )
(372 )
115
243
335
186
403
170
370
(305 )
(254 )
90
281
182
153
465
189
(55 )
(15 )
33
(118 )
25
(38 )
153
33
(62 )
(19 )
(63 )
Net Regulatory Assets included on the Consolidated Balance Sheets
$
1,348
$
1,411
$
Regulatory assets that do not earn a current return totaled approximately $148 million and $488 million as of December 31, 2015 and
2014, respectively, primarily related to storm damage costs. JCP&L's regulatory asset related to 2011 and 2012 storm damage costs
began earning a return on April 1, 2015. Effective with the approved settlement on April 9, 2015, associated with their general base
rate case, the Pennsylvania Companies transferred the net book value of legacy meters from plant-in-service to regulatory assets,
which is being recovered over five years.
As of December 31, 2015 and December 31, 2014, FirstEnergy had approximately $116 million and $243 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, 2015 and 2014 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer
receivables as of December 31, 2015 and 2014 are included below.
The following table provides information about the composition of net regulatory assets as of December 31, 2015 and December 31,
2014, and the changes during the year ended December 31, 2015:
Customer Receivables
Customer Receivables
FirstEnergy
FirstEnergy
FES
FES
December 31, 2015
December 31, 2015
Billed
Billed
Unbilled
Unbilled
Total
Total
December 31, 2014
December 31, 2014
Billed
Billed
Unbilled
Unbilled
Total
Total
(In millions)
(In millions)
836 $
836 $
579
579
1,415 $
1,415 $
914 $
914 $
640
640
1,554 $
1,554 $
165
165
110
110
275
275
239
239
176
176
415
415
$
$
$
$
$
$
$
$
EARNINGS PER SHARE OF COMMON STOCK
EARNINGS PER SHARE OF COMMON STOCK
Basic earnings 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 per share of common
stock:
Basic earnings 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 per share of common
stock:
Reconciliation of Basic and Diluted Earnings per Share of Common Stock
Reconciliation of Basic and Diluted Earnings per Share of Common Stock
Income from continuing operations available to common shareholders
Income from continuing operations available to common shareholders
Discontinued operations (Note 19)
Discontinued operations (Note 19)
Net income
Net income
2013
2013
2015
2015
2014
2014
(In millions, except per share amounts)
(In millions, except per share amounts)
375
375
17
17
392
392
578 $
578 $
—
—
578 $
578 $
213 $
213 $
86
86
299 $
299 $
$
$
$
$
Weighted average number of basic shares outstanding
Weighted average number of basic shares outstanding
Assumed exercise of dilutive stock options and awards(1)
Assumed exercise of dilutive stock options and awards(1)
Weighted average number of diluted shares outstanding
Weighted average number of diluted shares outstanding
422
422
2
2
424
424
420
420
1
1
421
421
Earnings per share:
Earnings per share:
Basic earnings per share:
Basic earnings per share:
Continuing operations
Continuing operations
Discontinued operations (Note 19)
Discontinued operations (Note 19)
Earnings per basic share
Earnings per basic share
Diluted earnings per share:
Diluted earnings per share:
Continuing operations
Continuing operations
Discontinued operations (Note 19)
Discontinued operations (Note 19)
Earnings per diluted share
Earnings per diluted share
$
$
$
$
$
$
$
$
1.37 $
1.37 $
—
—
1.37 $
1.37 $
0.51 $
0.51 $
0.20
0.20
0.71 $
0.71 $
1.37 $
1.37 $
—
—
1.37 $
1.37 $
0.51 $
0.51 $
0.20
0.20
0.71 $
0.71 $
418
418
1
1
419
419
0.90
0.90
0.04
0.04
0.94
0.94
0.90
0.90
0.04
0.04
0.94
0.94
(1)
(1)
For the years ended December 31, 2015, 2014 and 2013, approximately one million, two million, and two million shares were excluded from the
calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive.
For the years ended December 31, 2015, 2014 and 2013, approximately one million, two 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
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. The cost of nuclear fuel included in CES' net plant as
of December 31, 2015 was $418 million. Net plant in service balances by segment as of December 31, 2015 and 2014 were as
follows:
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. The cost of nuclear fuel included in CES' net plant as
of December 31, 2015 was $418 million. Net plant in service balances by segment as of December 31, 2015 and 2014 were as
follows:
70
71
71
Property, Plant and Equipment
December 31, 2015
In Service(2) Accum. Depr. Net Plant
December 31, 2014
In Service(2) Accum. Depr. Net Plant
Regulated Distribution
Regulated Transmission
Competitive Energy Services(1)
Corporate/Other
Total
$
$
24,553 $
7,703
17,214
482
49,952 $
(In millions)
(7,058 ) $
(1,647 )
(6,213 )
(242 )
(15,160 ) $
17,495 $
6,056
11,001
240
34,792 $
23,973 $
6,634
16,442
435
47,484 $
(6,759 ) $
(1,595 )
(5,598 )
(198 )
(14,150 ) $
17,214
5,039
10,844
237
33,334
(1) Primarily consists of generating assets and nuclear fuel as discussed above.
(2)Includes capital leases of $253 million and $281 million at December 31, 2015 and 2014, respectively.
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 $2.0 billion of regulated generation net plant in service.
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 2015, 2014 and 2013 are shown in the
following table:
Annual Composite Depreciation Rate
2015
2014
2013
FirstEnergy
FES
2.5 %
3.2 %
2.5 %
3.1 %
2.6 %
3.1 %
For the years ended December 31, 2015, 2014 and 2013, capitalized financing costs on FirstEnergy's Consolidated Statements of
Income include $49 million, $49 million and $28 million, respectively, of allowance for equity funds used during construction and $68
million, $69 million and $75 million, respectively, of capitalized interest.
million).
Goodwill
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 $666 million representing AGC's share in this facility as of December 31, 2015 of which $484 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.
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, 2015, are described further in Note 13, Asset Retirement Obligations.
ASSET IMPAIRMENTS
Long-lived Assets
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of
such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum
of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater
than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to
estimate fair value.
On October 9, 2013, MP sold its approximate 8% share of Pleasants at its fair market value of $73 million to AE Supply, and AE
Supply sold its approximate 80% share of Harrison to MP at its book value of $1.2 billion. The transaction resulted in AE Supply
receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. In connection with the
transaction, MP recorded a pre-tax impairment charge of approximately $322 million to reduce the net book value of the Harrison
Power Station to the amount that was permitted to be included in jurisdictional rate base. Additionally, MP recognized a regulatory
liability of approximately $23 million in 2013 representing refunds to customers associated with the excess purchase price received by
MP above the net book value of MP's minority interest in the Pleasants Power Station. The impairment charge recognized in 2013 is
included within the results of the Regulated Distribution segment.
On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the Hatfield's Ferry, generating Units 1-3, and
Mitchell, generating units 2-3. As a result of this decision FirstEnergy recorded a pre-tax impairment of approximately $473 million to
continuing operations, which also includes pre-tax impairments of $13 million related to excessive inventory at these facilities. The
impairment charge recognized in 2013 is included within the results of the CES segment. On October 9, 2013, Hatfield's Ferry Units
1-3 and Mitchell Units 2-3 were deactivated.
During 2015, FirstEnergy recognized impairments totaling $42 million associated with certain non-core assets, including equipment
and facilities. The impairment charges are included within the Regulated Distribution segment ($8 million) and the CES segment ($34
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.
FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated
Transmission, and CES. The following table presents goodwill by reporting unit:
Goodwill
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Consolidated
Balance as of December 31, 2015
526 $
800 $
6,418
(In millions)
$
5,092 $
There were no changes in goodwill for any reporting unit during 2015. As of December 31, 2015 and 2014, total goodwill recognized
by FES was $23 million. Neither FirstEnergy nor FES has accumulated impairment charges as of December 31, 2015.
Annual impairment testing is conducted as of July 31 of each year and for 2015, 2014 and 2013, the analysis indicated no impairment
of goodwill. For 2015, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission
reporting units, assessing economic, industry and market considerations in addition to the reporting unit's 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 for 2015.
FirstEnergy performed a quantitative assessment of the CES reporting unit as of July 31, 2015. Key assumptions incorporated into
the CES discounted cash flow analysis requiring significant management judgment included the following:
• Future Energy and Capacity Prices: FirstEnergy used observable market information for near term forward power prices,
PJM auction results for near term capacity pricing, and a longer-term 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: FirstEnergy used CES' current retail targeted portfolio to estimate future retail sales volume as
well as historical financial results to estimate retail margins.
72
73
Property, Plant and Equipment
In Service(2) Accum. Depr. Net Plant
In Service(2) Accum. Depr. Net Plant
December 31, 2015
December 31, 2014
Regulated Distribution
$
24,553 $
(7,058 ) $
17,495 $
23,973 $
(6,759 ) $
Regulated Transmission
Competitive Energy Services(1)
Corporate/Other
Total
7,703
17,214
482
(1,647 )
(6,213 )
(242 )
6,056
11,001
240
6,634
16,442
435
(1,595 )
(5,598 )
(198 )
$
49,952 $
(15,160 ) $
34,792 $
47,484 $
(14,150 ) $
17,214
5,039
10,844
237
33,334
(In millions)
(1) Primarily consists of generating assets and nuclear fuel as discussed above.
(2)Includes capital leases of $253 million and $281 million at December 31, 2015 and 2014, respectively.
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 $2.0 billion of regulated generation net plant in service.
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 2015, 2014 and 2013 are shown in the
following table:
Annual Composite Depreciation Rate
2015
2014
2013
FirstEnergy
FES
2.5 %
3.2 %
2.5 %
3.1 %
2.6 %
3.1 %
For the years ended December 31, 2015, 2014 and 2013, capitalized financing costs on FirstEnergy's Consolidated Statements of
Income include $49 million, $49 million and $28 million, respectively, of allowance for equity funds used during construction and $68
million, $69 million and $75 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 $666 million representing AGC's share in this facility as of December 31, 2015 of which $484 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.
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.
liability recognition.
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
AROs as of December 31, 2015, are described further in Note 13, Asset Retirement Obligations.
ASSET IMPAIRMENTS
Long-lived Assets
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of
such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum
of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater
than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to
estimate fair value.
On October 9, 2013, MP sold its approximate 8% share of Pleasants at its fair market value of $73 million to AE Supply, and AE
Supply sold its approximate 80% share of Harrison to MP at its book value of $1.2 billion. The transaction resulted in AE Supply
receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. In connection with the
transaction, MP recorded a pre-tax impairment charge of approximately $322 million to reduce the net book value of the Harrison
Power Station to the amount that was permitted to be included in jurisdictional rate base. Additionally, MP recognized a regulatory
liability of approximately $23 million in 2013 representing refunds to customers associated with the excess purchase price received by
MP above the net book value of MP's minority interest in the Pleasants Power Station. The impairment charge recognized in 2013 is
included within the results of the Regulated Distribution segment.
On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the Hatfield's Ferry, generating Units 1-3, and
Mitchell, generating units 2-3. As a result of this decision FirstEnergy recorded a pre-tax impairment of approximately $473 million to
continuing operations, which also includes pre-tax impairments of $13 million related to excessive inventory at these facilities. The
impairment charge recognized in 2013 is included within the results of the CES segment. On October 9, 2013, Hatfield's Ferry Units
1-3 and Mitchell Units 2-3 were deactivated.
During 2015, FirstEnergy recognized impairments totaling $42 million associated with certain non-core assets, including equipment
and facilities. The impairment charges are included within the Regulated Distribution segment ($8 million) and the CES segment ($34
million).
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.
FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated
Transmission, and CES. The following table presents goodwill by reporting unit:
Goodwill
Balance as of December 31, 2015
Regulated
Distribution
(In millions)
5,092 $
$
Regulated
Transmission
Competitive
Energy
Services
Consolidated
526 $
800 $
6,418
There were no changes in goodwill for any reporting unit during 2015. As of December 31, 2015 and 2014, total goodwill recognized
by FES was $23 million. Neither FirstEnergy nor FES has accumulated impairment charges as of December 31, 2015.
Annual impairment testing is conducted as of July 31 of each year and for 2015, 2014 and 2013, the analysis indicated no impairment
of goodwill. For 2015, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission
reporting units, assessing economic, industry and market considerations in addition to the reporting unit's 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 for 2015.
FirstEnergy performed a quantitative assessment of the CES reporting unit as of July 31, 2015. Key assumptions incorporated into
the CES discounted cash flow analysis requiring significant management judgment included the following:
• Future Energy and Capacity Prices: FirstEnergy used observable market information for near term forward power prices,
PJM auction results for near term capacity pricing, and a longer-term 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: FirstEnergy used CES' current retail targeted portfolio to estimate future retail sales volume as
well as historical financial results to estimate retail margins.
72
73
In April 2015, the FASB issued, 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 guidance is effective for financial statements issued for fiscal years beginning after
December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not
financial statements. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of
Debt Issuance Costs Associated with Line-of-Credit Arrangements", which states given the absence of authoritative guidance within
ASU 2015-03 for debt issuance costs related to the line-of-credit arrangements, the SEC staff would not object to presenting those
deferred debt issuance costs as an asset and subsequently amortizing the costs ratably over the term of the arrangement, regardless
of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy will adopt ASU 2015-15 and ASU 2015-03
beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES debt issuance costs included in Deferred Charges and
Other Assets were $93 million and $17 million, respectively. FirstEnergy will elect to continue presenting debt issuance costs relating
to its revolving credit facilities as an asset.
In August 2015, the FASB issued ASU 2015 -13, "Application of the NPNS Scope Exception to Certain Electricity Contracts within
Nodal Energy Markets", which confirmed that forward physical contracts for the sale or purchase of electricity meet the physical
delivery criterion within the NPNS scope exception when the electricity is transmitted through a grid managed by an ISO. As a result,
an entity can elect the NPNS exception within the derivative accounting guidance for such contracts, provided that the other NPNS
criteria are also met. The ASU was effective on issuance and requires prospective application. There was no material effect on
FirstEnergy's financial statements resulting from the issuance of ASU 2015-13.
In November 2015, the FASB issued ASU 2015 - 17, "Balance Sheet Classification of Deferred Taxes", which requires all deferred tax
assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance
will be effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is
permitted for all entities as of the beginning of an interim or annual reporting period. The guidance may be applied either
prospectively, for all deferred tax assets and liabilities, or retrospectively. FirstEnergy early adopted ASU 2015-17 as of December
2015, and applied the new guidance retrospectively to all prior periods presented in the financial statements. There was no impact
from the early adoption of ASU 2015-17 on the Consolidated Statements of Income. On the Consolidated Balance Sheet as of
December 31, 2014, FirstEnergy and FES reclassified $518 million and $27 million of Accumulated Deferred Income Taxes from
Current Assets to Noncurrent Liabilities.
In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial
Assets and Financial Liabilities". Changes to the current GAAP model primarily affect 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 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.
• Operating and Capital Costs: FirstEnergy used 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 8.25%, based on a capital structure, return on debt and return on equity of selected
comparable companies.
• Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on
been previously issued. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the
consideration of peer group data and analyst consensus expectations.
Based on the results of the quantitative analysis, the fair value of the CES reporting unit exceeded its carrying value by approximately
10%. Continued weak economic conditions, lower than expected power and capacity prices, a higher cost of capital and revised
environmental requirements could have a negative impact on future goodwill assessments.
Investments
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 first 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 in net regulatory assets. In 2015, 2014 and 2013, FirstEnergy recognized $102 million, $37 million and $90 million,
respectively, of OTTI. During the same periods, FES recognized OTTI of $90 million, $33 million and $79 million, respectively. The fair
values of FirstEnergy’s investments are disclosed in Note 9, Fair Value Measurements.
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 current 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 an a pre-tax impairment charge of $362 million. 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. See Note 8, 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.
NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by
applying a five-step model in accordance with the core principle 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. In
addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue
recognition are expanded. In August 2015, the FASB issued a final Accounting Standards Update deferring the effective date until
fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after
December 15, 2016, (the original effective date). The standard shall be applied retrospectively to each period presented or as a
cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of
adopting this standard.
In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends
current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate
whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15,
2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by
recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments
retrospectively. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
74
75
In April 2015, the FASB issued, 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 guidance is effective for financial statements issued for fiscal years beginning after
December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not
been previously issued. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the
financial statements. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of
Debt Issuance Costs Associated with Line-of-Credit Arrangements", which states given the absence of authoritative guidance within
ASU 2015-03 for debt issuance costs related to the line-of-credit arrangements, the SEC staff would not object to presenting those
deferred debt issuance costs as an asset and subsequently amortizing the costs ratably over the term of the arrangement, regardless
of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy will adopt ASU 2015-15 and ASU 2015-03
beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES debt issuance costs included in Deferred Charges and
Other Assets were $93 million and $17 million, respectively. FirstEnergy will elect to continue presenting debt issuance costs relating
to its revolving credit facilities as an asset.
In August 2015, the FASB issued ASU 2015 -13, "Application of the NPNS Scope Exception to Certain Electricity Contracts within
Nodal Energy Markets", which confirmed that forward physical contracts for the sale or purchase of electricity meet the physical
delivery criterion within the NPNS scope exception when the electricity is transmitted through a grid managed by an ISO. As a result,
an entity can elect the NPNS exception within the derivative accounting guidance for such contracts, provided that the other NPNS
criteria are also met. The ASU was effective on issuance and requires prospective application. There was no material effect on
FirstEnergy's financial statements resulting from the issuance of ASU 2015-13.
In November 2015, the FASB issued ASU 2015 - 17, "Balance Sheet Classification of Deferred Taxes", which requires all deferred tax
assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance
will be effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is
permitted for all entities as of the beginning of an interim or annual reporting period. The guidance may be applied either
prospectively, for all deferred tax assets and liabilities, or retrospectively. FirstEnergy early adopted ASU 2015-17 as of December
2015, and applied the new guidance retrospectively to all prior periods presented in the financial statements. There was no impact
from the early adoption of ASU 2015-17 on the Consolidated Statements of Income. On the Consolidated Balance Sheet as of
December 31, 2014, FirstEnergy and FES reclassified $518 million and $27 million of Accumulated Deferred Income Taxes from
Current Assets to Noncurrent Liabilities.
In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial
Assets and Financial Liabilities". Changes to the current GAAP model primarily affect 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 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.
• Operating and Capital Costs: FirstEnergy used 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
• Discount Rate: A discount rate of 8.25%, based on a capital structure, return on debt and return on equity of selected
performance reforms in the PJM market.
comparable companies.
• 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 results of the quantitative analysis, the fair value of the CES reporting unit exceeded its carrying value by approximately
10%. Continued weak economic conditions, lower than expected power and capacity prices, a higher cost of capital and revised
environmental requirements could have a negative impact on future goodwill assessments.
Investments
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 first 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 in net regulatory assets. In 2015, 2014 and 2013, FirstEnergy recognized $102 million, $37 million and $90 million,
respectively, of OTTI. During the same periods, FES recognized OTTI of $90 million, $33 million and $79 million, respectively. The fair
values of FirstEnergy’s investments are disclosed in Note 9, Fair Value Measurements.
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 current 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 an a pre-tax impairment charge of $362 million. 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. See Note 8, 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.
NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by
applying a five-step model in accordance with the core principle 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. In
addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue
recognition are expanded. In August 2015, the FASB issued a final Accounting Standards Update deferring the effective date until
fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after
December 15, 2016, (the original effective date). The standard shall be applied retrospectively to each period presented or as a
cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of
adopting this standard.
In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends
current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate
whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15,
2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by
recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments
retrospectively. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
74
75
2. ACCUMULATED OTHER COMPREHENSIVE INCOME
The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2015, 2014 and 2013:
The changes in AOCI for the years ended December 31, 2015, 2014 and 2013 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, 2013
$
(38 ) $
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
—
3
3
1
2
(In millions)
15 $
46
(56 )
(10 )
(4 )
(6 )
408 $
35
(195 )
(160 )
(63 )
(97 )
AOCI Balance, December 31, 2013
$
(36 ) $
9 $
311 $
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 )
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 $
385
81
(248 )
(167 )
(66 )
(101 )
284
181
(233 )
(52 )
(14 )
(38 )
246
24
(146 )
(122 )
(47 )
(75 )
171
FirstEnergy
Reclassifications from AOCI (2)
2015
2014
2013
Statements of Income
Year Ended December 31,
Affected Line Item in Consolidated
Gains & losses on cash flow hedges
Commodity contracts
Long-term debt
(In millions)
$
(3 ) $
(10 ) $
(8 ) Other operating expenses
8
5
(1 )
8
(2 )
1
11 Interest expense
3 Total before taxes
(1 ) Income taxes (benefits)
$
4 $
(1 ) $
2 Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities
$
(25 ) $
(63 ) $
(56 ) Investment income (loss)
9
24
21 Income taxes (benefits)
$
(16 ) $
(39 ) $
(35 ) Net of tax
Defined benefit pension and OPEB plans
Prior-service costs
$
(126 ) $
(168 ) $
(195 ) (1)
49
65
75 Income taxes (benefits)
$
(77 ) $
(103 ) $
(120 ) Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other
Postemployment Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
76
77
The changes in AOCI for the years ended December 31, 2015, 2014 and 2013 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, 2013
$
(38 ) $
(In millions)
15 $
AOCI Balance, December 31, 2013
$
(36 ) $
9 $
311 $
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
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
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
—
3
3
1
2
—
(2 )
(2 )
(1 )
(1 )
—
5
5
1
4
46
(56 )
(10 )
(4 )
(6 )
89
(63 )
26
10
16
14
(25 )
(11 )
(4 )
(7 )
AOCI Balance, December 31, 2015
$
(33 ) $
18 $
186 $
408 $
35
(195 )
(160 )
(63 )
(97 )
92
(168 )
(76 )
(23 )
(53 )
10
(126 )
(116 )
(44 )
(72 )
385
81
(248 )
(167 )
(66 )
(101 )
284
181
(233 )
(52 )
(14 )
(38 )
246
24
(146 )
(122 )
(47 )
(75 )
171
2. ACCUMULATED OTHER COMPREHENSIVE INCOME
The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2015, 2014 and 2013:
FirstEnergy
Reclassifications from AOCI (2)
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
Year Ended December 31,
2013
2014
2015
Affected Line Item in Consolidated
Statements of Income
(In millions)
(3 ) $
8
5
(1 )
4 $
(10 ) $
8
(2 )
1
(1 ) $
(8 ) Other operating expenses
11 Interest expense
3 Total before taxes
(1 ) Income taxes (benefits)
2 Net of tax
(25 ) $
9
(16 ) $
(63 ) $
24
(39 ) $
(56 ) Investment income (loss)
21 Income taxes (benefits)
(35 ) Net of tax
(126 ) $
49
(77 ) $
(168 ) $
65
(103 ) $
(195 ) (1)
75 Income taxes (benefits)
(120 ) Net of tax
$
$
$
$
$
$
AOCI Balance, December 31, 2014
$
(37 ) $
25 $
258 $
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other
Postemployment Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
76
77
The changes in AOCI for the years ended December 31, 2015, 2014 and 2013 for FES are shown in the following table:
The following amounts were reclassified from AOCI for FES in the years ended December 31, 2015, 2014 and 2013:
FES
Gains &
Losses on
Cash Flow
Hedges
Unrealized
Gains on
AFS
Securities
Defined
Benefit
Pension &
OPEB Plans
Total
(In millions)
AOCI Balance, January 1, 2013
$
3 $
13 $
56 $
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
—
(6 )
(6 )
(2 )
(4 )
41
(49 )
(8 )
(3 )
(5 )
5
(20 )
(15 )
(6 )
(9 )
AOCI Balance, December 31, 2013
$
(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 $
72
46
(75 )
(29 )
(11 )
(18 )
54
93
(88 )
5
2
3
57
25
(43 )
(18 )
(7 )
(11 )
46
FES
Reclassifications from AOCI (2)
2015
2014
2013
Statements of Income
Year Ended December 31,
Affected Line Item in Consolidated
Gains & losses on cash flow hedges
Commodity contracts
Long-term debt
(In millions)
$
(3 ) $
(10 ) $
(8 ) Other operating expenses
—
(3 )
1
—
(10 )
4
2 Interest expense - other
(6 ) Total before taxes
2 Income taxes (benefits)
$
(2 ) $
(6 ) $
(4 ) Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities
$
(24 ) $
(59 ) $
(49 ) Investment income (loss)
9
22
18 Income taxes (benefits)
$
(15 ) $
(37 ) $
(31 ) Net of tax
Defined benefit pension and OPEB plans
Prior-service costs
$
(16 ) $
(19 ) $
(20 ) (1)
6
7
8 Income taxes (benefits)
$
(10 ) $
(12 ) $
(12 ) Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment
Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
3. 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 2015 and 2014, certain unions ratified their
labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately
$10 million and $97 million, respectively.
FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment 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, 2015, 2014, and 2013 were $369 million ($242 million net of amounts capitalized), $1,243 million ($835
million net of amounts capitalized), and $(396) million ($(256) million net of amounts capitalized), respectively. In 2015, the pension
and OPEB mark-to-market adjustment primarily reflects lower than expected asset returns as well as the impact of other demographic
assumptions, including revisions to mortality assumptions, partially offset by a 25 basis point increase in the discount rate.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the
year ended December 31, 2015, FirstEnergy made contributions of $143 million to its qualified pension plan. In 2016, FirstEnergy has
minimum required funding obligations of $381 million to its qualified pension plan, of which $160 million has been contributed to date.
FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof,
depending on, among other things, market conditions.
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
78
79
The changes in AOCI for the years ended December 31, 2015, 2014 and 2013 for FES are shown in the following table:
The following amounts were reclassified from AOCI for FES in the years ended December 31, 2015, 2014 and 2013:
FES
Gains &
Losses on
Cash Flow
Hedges
Unrealized
Gains on
AFS
Securities
Defined
Benefit
Pension &
OPEB Plans
Total
(In millions)
AOCI Balance, January 1, 2013
$
3 $
13 $
56 $
AOCI Balance, December 31, 2013
$
(1 ) $
8 $
47 $
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
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
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
—
(6 )
(6 )
(2 )
(4 )
—
(10 )
(10 )
(4 )
(6 )
—
(3 )
(3 )
(1 )
(2 )
41
(49 )
(8 )
(3 )
(5 )
80
(59 )
21
8
13
15
(24 )
(9 )
(4 )
(5 )
5
(20 )
(15 )
(6 )
(9 )
13
(19 )
(6 )
(2 )
(4 )
10
(16 )
(6 )
(2 )
(4 )
AOCI Balance, December 31, 2014
$
(7 ) $
21 $
43 $
AOCI Balance, December 31, 2015
$
(9 ) $
16 $
39 $
72
46
(75 )
(29 )
(11 )
(18 )
54
93
(88 )
5
2
3
57
25
(43 )
(18 )
(7 )
(11 )
46
FES
Reclassifications from AOCI (2)
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
Year Ended December 31,
2013
2015
2014
(In millions)
Affected Line Item in Consolidated
Statements of Income
$
$
$
$
$
$
(3 ) $
—
(3 )
1
(2 ) $
(10 ) $
—
(10 )
4
(6 ) $
(8 ) Other operating expenses
2 Interest expense - other
(6 ) Total before taxes
2 Income taxes (benefits)
(4 ) Net of tax
(24 ) $
9
(15 ) $
(59 ) $
22
(37 ) $
(49 ) Investment income (loss)
18 Income taxes (benefits)
(31 ) Net of tax
(16 ) $
6
(10 ) $
(19 ) $
7
(12 ) $
(20 ) (1)
8 Income taxes (benefits)
(12 ) Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment
Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
3. 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 2015 and 2014, certain unions ratified their
labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately
$10 million and $97 million, respectively.
FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment 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, 2015, 2014, and 2013 were $369 million ($242 million net of amounts capitalized), $1,243 million ($835
million net of amounts capitalized), and $(396) million ($(256) million net of amounts capitalized), respectively. In 2015, the pension
and OPEB mark-to-market adjustment primarily reflects lower than expected asset returns as well as the impact of other demographic
assumptions, including revisions to mortality assumptions, partially offset by a 25 basis point increase in the discount rate.
FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the
year ended December 31, 2015, FirstEnergy made contributions of $143 million to its qualified pension plan. In 2016, FirstEnergy has
minimum required funding obligations of $381 million to its qualified pension plan, of which $160 million has been contributed to date.
FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof,
depending on, among other things, market conditions.
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
78
79
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 2015, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of
$(172) million, or (2.7)% compared to earnings of $387 million, or 6.2% in 2014 and losses of $(22) million, or (0.3)% in 2013, and
assumed a 7.75% rate of return for each year on plan assets which generated $476 million, $496 million and $535 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 2014, the Society of Actuaries published new mortality tables and improvement scales reflecting improved life expectancies
and an expectation that the trend will continue. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of
the RP2014 mortality table with blue collar adjustment for females and projection scale SS2014INT was most appropriate as of
December 31, 2015. As such, the RP2014 mortality table with projection scale SS2014INT was utilized to determine the 2015 benefit
cost and obligation as of December 31, 2015 for the FirstEnergy pension and OPEB plans. The impact of using the RP2014 mortality
table and projection scale SS2014INT resulted in an increase in the projected benefit obligation of $49 million and $1 million for the
pension and OPEB plans, respectively, and was included in the 2015 pension and OPEB mark-to-market adjustment.
80
Obligations and Funded Status
2015
2014
2015
2014
Pension
OPEB
(In millions)
$
9,249
$
8,263
$
757
$
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:
Current liabilities
Noncurrent liabilities
Net liability as of December 31
Amounts Recognized in AOCI:
Prior service cost (credit)
(as of December 31)
Discount rate
Rate of compensation increase
Assumptions Used to Determine Benefit Obligations
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
Derivatives
Total
Cash and short-term securities
$
$
$
$
$
$
$
$
$
81
193
383
—
—
—
(277 )
(469 )
9,079
$
5,824
$
(178 )
161
—
(469 )
5,338
$
167
402
—
5
—
1,123
(711 )
9,249
$
6,171
349
$
15
—
(711 )
5,824
$
(3,366 ) $
(375 )
(3,741 ) $
(3,064 )
(361 )
(3,425 ) $
8,579
$
8,744
$
(18 ) $
(3,723 )
(3,741 ) $
(17 ) $
(3,408 )
(3,425 ) $
5
29
6
(10 )
1
(2 )
(62 )
724
$
464
$
6
17
6
(62 )
431
$
(293 ) $
—
$
—
$
(293 )
(293 ) $
879
9
39
16
(97 )
—
13
(102 )
757
495
38
17
16
(102 )
464
(293 )
—
—
(293 )
(293 )
37
$
45
$
(355 ) $
(479 )
4.50 %
4.20 %
4.25 %
4.20 %
4.25 %
N/A
4.00 %
N/A
N/A
N/A
N/A
40 %
34 %
7 %
11 %
— %
8 %
100 %
N/A
N/A
N/A
36 %
33 %
14 %
7 %
1 %
9 %
100 %
6.0-5.5%
7.5-7.0%
4.5 %
2026
51 %
43 %
— %
— %
— %
6 %
100 %
4.5 %
2026
49 %
40 %
1 %
1 %
— %
9 %
100 %
The estimated 2016 amortization of pension and OPEB prior service costs (credits) from AOCI into net periodic pension and
OPEB costs (credits) is approximately $8 million and $(80) million, respectively.
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 2015, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of
$(172) million, or (2.7)% compared to earnings of $387 million, or 6.2% in 2014 and losses of $(22) million, or (0.3)% in 2013, and
assumed a 7.75% rate of return for each year on plan assets which generated $476 million, $496 million and $535 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 2014, the Society of Actuaries published new mortality tables and improvement scales reflecting improved life expectancies
and an expectation that the trend will continue. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of
the RP2014 mortality table with blue collar adjustment for females and projection scale SS2014INT was most appropriate as of
December 31, 2015. As such, the RP2014 mortality table with projection scale SS2014INT was utilized to determine the 2015 benefit
cost and obligation as of December 31, 2015 for the FirstEnergy pension and OPEB plans. The impact of using the RP2014 mortality
table and projection scale SS2014INT resulted in an increase in the projected benefit obligation of $49 million and $1 million for the
pension and OPEB plans, respectively, and was included in the 2015 pension and OPEB mark-to-market adjustment.
Obligations and Funded Status
2015
2014
2015
2014
Pension
OPEB
(In millions)
$
9,249
$
8,263
$
757
$
$
$
$
$
$
$
$
$
$
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:
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
Derivatives
Cash and short-term securities
Total
193
383
—
—
—
167
402
—
5
—
(277 )
(469 )
9,079
$
1,123
(711 )
9,249
$
5
29
6
(10 )
1
(2 )
(62 )
724
$
$
5,824
(178 )
161
—
(469 )
5,338
$
$
6,171
349
15
—
(711 )
5,824
$
$
464
6
17
6
(62 )
431
$
(3,366 ) $
(375 )
(3,741 ) $
(3,064 )
(361 )
(3,425 ) $
8,579
$
8,744
$
(18 ) $
(3,723 )
(3,741 ) $
(17 ) $
(3,408 )
(3,425 ) $
(293 ) $
—
$
$
—
(293 )
(293 ) $
879
9
39
16
(97 )
—
13
(102 )
757
495
38
17
16
(102 )
464
(293 )
—
—
(293 )
(293 )
37
$
45
$
(355 ) $
(479 )
4.50 %
4.20 %
4.25 %
4.20 %
4.25 %
N/A
4.00 %
N/A
N/A
N/A
N/A
40 %
34 %
7 %
11 %
— %
8 %
100 %
N/A
N/A
N/A
36 %
33 %
14 %
7 %
1 %
9 %
100 %
6.0-5.5%
7.5-7.0%
4.5 %
2026
51 %
43 %
— %
— %
— %
6 %
100 %
4.5 %
2026
49 %
40 %
1 %
1 %
— %
9 %
100 %
80
81
The estimated 2016 amortization of pension and OPEB prior service costs (credits) from AOCI into net periodic pension and
OPEB costs (credits) is approximately $8 million and $(80) million, respectively.
Components of Net Periodic Benefit Costs
2015
2014
2013
2015
Pension
OPEB
2014
2013
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost (credit)
Pension & OPEB mark-to-market adjustment
Net periodic cost (credit)
$
$
193 $
383
(443 )
8
344
485 $
167 $
402
(462 )
8
1,235
1,350 $
(In millions)
197 $
372
(501 )
12
(267 )
(187 ) $
5 $
29
(33 )
(134 )
25
(108 ) $
9 $
39
(34 )
(176 )
8
(154 ) $
13
37
(34 )
(207 )
(129 )
(320 )
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
2015
2014
2013
2015
2014
2013
4.25 %
7.75 %
4.20 %
5.00 %
7.75 %
4.20 %
4.25 %
7.75 %
4.70 %
4.00 %
7.75 %
N/A
4.75 %
7.75 %
N/A
4.00 %
7.75 %
N/A
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. In 2016, FirstEnergy decreased
the expected long-term return on plan assets to 7.50%.
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See
Note 9, Fair Value Measurements, for a description of each level of the fair value hierarchy. There were no significant transfers
between levels during 2015 and 2014.
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.
December 31, 2014
Level 1
Level 2
Level 3
Total
$
— $
— $
517
(In millions)
517 $
Asset
Allocation
1,266
355
—
—
—
—
—
—
—
—
8
414
159
1,386
300
37
809
35
—
—
$
1,621 $
3,665 $
—
—
—
—
—
—
—
—
25
421
446 $
1,274
769
159
1,386
300
37
809
35
25
421
5,732
9 %
22 %
14 %
3 %
24 %
5 %
1 %
14 %
1 %
— %
7 %
100 %
Cash and short-term securities
Equity investments
Domestic
International
Fixed income
Government bonds
Corporate bonds
High yield debt
government)
Alternatives
Derivatives
Private equity funds
Real estate funds
Total (1)
Mortgage-backed securities (non-
Hedge funds (Absolute return)
reflected within the fair value table.
hierarchy during 2015 and 2014:
(1) Excludes $92 million as of December 31, 2014 of receivables, payables, taxes and accrued income associated with financial instruments
The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value
Balance as of January 1, 2014
Actual return on plan assets:
Unrealized gains (losses)
Realized gains
Transfers in (out)
Balance as of December 31, 2014
Actual return on plan assets:
Unrealized gains
Realized gains (losses)
Transfers in
Balance as of December 31, 2015
$
$
$
Private Equity
Real Estate
Funds
Funds
(In millions)
27 $
385
17
14
5
421
42
16
108
587
(2 )
1
(1 )
25 $
—
(1 )
—
24 $
82
83
Components of Net Periodic Benefit Costs
2015
2014
2013
2015
2013
Pension
OPEB
2014
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost (credit)
Pension & OPEB mark-to-market adjustment
Net periodic cost (credit)
$
193 $
167 $
197 $
5 $
9 $
(In millions)
383
(443 )
8
344
402
(462 )
8
1,235
372
(501 )
12
(267 )
29
(33 )
(134 )
25
39
(34 )
(176 )
8
$
485 $
1,350 $
(187 ) $
(108 ) $
(154 ) $
13
37
(34 )
(207 )
(129 )
(320 )
Assumptions Used to Determine Net Periodic
Pension
OPEB
Benefit Cost
for Years Ended December 31
Weighted-average discount rate
Expected long-term return on plan assets
Rate of compensation increase
2015
2014
2013
2015
2014
2013
4.25 %
7.75 %
4.20 %
5.00 %
7.75 %
4.20 %
4.25 %
7.75 %
4.70 %
4.00 %
7.75 %
N/A
4.75 %
7.75 %
N/A
4.00 %
7.75 %
N/A
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. In 2016, FirstEnergy decreased
the expected long-term return on plan assets to 7.50%.
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See
Note 9, Fair Value Measurements, for a description of each level of the fair value hierarchy. There were no significant transfers
between levels during 2015 and 2014.
December 31, 2015
Level 1
Level 2
Level 3
Total
$
— $
— $
427
(In millions)
427 $
Asset
Allocation
Cash and short-term securities
Equity investments
Domestic
International
Fixed income
Government bonds
Corporate bonds
High yield debt
government)
Alternatives
Derivatives
Private equity funds
Real estate funds
Total (1)
Mortgage-backed securities (non-
Hedge funds (Absolute return)
75
794
232
1,115
438
31
343
15
—
—
—
—
—
—
—
—
—
—
24
587
611 $
944
1,189
232
1,115
438
31
343
15
24
587
5,345
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.
$
1,264 $
3,470 $
869
395
—
—
—
—
—
—
—
—
82
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, 2014
Level 1
Level 2
Level 3
Total
$
— $
(In millions)
517 $
— $
517
1,266
355
—
—
—
—
—
—
—
—
1,621 $
8
414
159
1,386
300
37
809
35
—
—
3,665 $
—
—
—
—
—
—
—
—
25
421
446 $
1,274
769
159
1,386
300
37
809
35
25
421
5,732
$
Asset
Allocation
9 %
22 %
14 %
3 %
24 %
5 %
1 %
14 %
1 %
— %
7 %
100 %
(1) Excludes $92 million as of December 31, 2014 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 2015 and 2014:
Private Equity
Funds
Real Estate
Funds
Balance as of January 1, 2014
Actual return on plan assets:
Unrealized gains (losses)
Realized gains
Transfers in (out)
Balance as of December 31, 2014
Actual return on plan assets:
Unrealized gains
Realized gains (losses)
Transfers in
Balance as of December 31, 2015
$
$
$
(In millions)
27 $
(2 )
1
(1 )
25 $
—
(1 )
—
24 $
385
17
14
5
421
42
16
108
587
83
As of December 31, 2015 and 2014, the OPEB trust investments measured at fair value were as follows:
The following table provides a reconciliation of changes in the fair value of OPEB trust investments classified as Level 3 in the fair
December 31, 2015
Level 1
Level 2
Level 3
Total
Asset
Allocation
value hierarchy during 2015 and 2014:
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.
Target Asset Allocations
2015
2014
December 31, 2014
Level 1
Level 2
Level 3
Total
Asset
Allocation
Cash and short-term securities
$
— $
(In millions)
41 $
— $
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)
230
3
—
—
—
—
—
—
3
41
110
32
2
3
—
—
233 $
5
—
237 $
$
—
—
—
—
—
—
—
—
3
3 $
41
230
6
41
110
32
2
3
5
3
473
9 %
48 %
1 %
9 %
23 %
7 %
— %
1 %
1 %
1 %
100 %
(1) Excludes $(9) million as of December 31, 2014, of receivables, payables, taxes and accrued income associated with financial instruments
reflected within the fair value table.
84
Real Estate
Funds
Balance as of January 1, 2014
Balance as of December 31, 2014
Transfers out
Transfers out
Balance as of December 31, 2015
$
$
$
5
(2 )
3
(1 )
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 2015 and 2014 are shown in the following table:
Equities
Fixed income
Absolute return strategies
Real estate
Alternative investments
Cash
38 %
30 %
8 %
10 %
8 %
6 %
42 %
32 %
14 %
5 %
1 %
6 %
100 %
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 $
26 $
(1 )
(23 )
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)
$
484 $
54 $
54
54
54
54
259
(3 )
(3 )
(3 )
(3 )
(3 )
(9 )
2016
2017
2018
2019
2020
Years 2021-2025
505
522
533
551
2,946
85
As of December 31, 2015 and 2014, the OPEB trust investments measured at fair value were as follows:
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 2015 and 2014:
Real Estate
Funds
Balance as of January 1, 2014
Transfers out
Balance as of December 31, 2014
Transfers out
Balance as of December 31, 2015
$
$
$
5
(2 )
3
(1 )
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.
(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.
Target Asset Allocations
2015
2014
$
220 $
216 $
2 $
438
FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2015 and 2014 are shown in the following table:
Equities
Fixed income
Absolute return strategies
Real estate
Alternative investments
Cash
38 %
30 %
8 %
10 %
8 %
6 %
100 %
42 %
32 %
14 %
5 %
1 %
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 $
26 $
(1 )
(23 )
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
484 $
505
522
533
551
2,946
85
54 $
54
54
54
54
259
(3 )
(3 )
(3 )
(3 )
(3 )
(9 )
Cash and short-term securities
$
— $
(In millions)
25 $
— $
December 31, 2015
Level 1
Level 2
Level 3
Total
Asset
Allocation
Cash and short-term securities
$
— $
(In millions)
41 $
— $
December 31, 2014
Level 1
Level 2
Level 3
Total
Asset
Allocation
Equity investment
Domestic
International
Fixed income
U.S. treasuries
Government bonds
Corporate bonds
High yield debt
government)
Alternatives
Hedge funds
Real estate funds
Total (1)
Mortgage-backed securities (non-
Equity investment
Domestic
International
Fixed income
U.S. treasuries
Government bonds
Corporate bonds
High yield debt
government)
Alternatives
Hedge funds
Real estate funds
Total (1)
Mortgage-backed securities (non-
25
219
4
42
114
27
1
3
1
2
41
230
6
41
110
32
2
3
5
3
6 %
50 %
1 %
10 %
26 %
6 %
— %
1 %
— %
— %
100 %
9 %
48 %
1 %
9 %
23 %
7 %
— %
1 %
1 %
1 %
—
—
—
—
—
—
—
—
2
—
—
—
—
—
—
—
—
3
—
3
42
114
27
1
3
1
—
—
3
41
110
32
2
3
5
—
219
1
—
—
—
—
—
—
—
230
3
—
—
—
—
—
—
—
84
(1) Excludes $(9) million as of December 31, 2014, of receivables, payables, taxes and accrued income associated with financial instruments
reflected within the fair value table.
$
233 $
237 $
3 $
473
100 %
FES’ share of the pension and OPEB net (liability) asset as of December 31, 2015 and 2014, was as follows:
Pension
OPEB
2015
2014
2015
2014
Net (Liability) Asset
$
(303 ) $
(In millions)
(295 ) $
25 $
10
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, 2015 was as follows:
Stock-based compensation costs capitalized
Pension
2015
2014
2013
2015
(In millions)
OPEB
2014
2013
Stock option expense was not material for FirstEnergy or FES for the years December 31, 2015, 2014 or 2013. Income tax benefits
associated with stock based compensation plan expense were $12 million, $14 million and $23 million (FES - $2 million, $2 million
and $1 million) for the years ended 2015, 2014 and 2013, respectively.
Net Periodic Cost (Credit)
$
10 $
150 $
(30 ) $
(22 ) $
(24 ) $
(40 )
Restricted Stock Units
4. 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, 2015, approximately 9.9 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. 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. 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. Realized tax benefits during the years ended December 31, 2015, 2014 and 2013
were $10 million, $13 million and $13 million, respectively. 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.
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,
2015
2014
2013
FES
Stock-based Compensation Plan
Restricted Stock Units
Performance Shares
401(k) Savings Plan
Total
Years ended December 31,
2015
2014
2013
(In millions)
$
$
$
6 $
—
5
11 $
1 $
4 $
1
4
9 $
1 $
(1 )
6
4
9
1
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. Compensation expense is recognized for the grant date
fair value of awards that are expected to vest. 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, 2015 was $3 million. No cash was paid to settle the restricted stock unit obligations in 2015.
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.
Restricted stock unit activity for the year ended December 31, 2015, was as follows:
Restricted Stock Unit Activity
Shares
Nonvested as of January 1, 2015
Granted in 2015
Forfeited in 2015
Vested in 2015(1)
Nonvested as of December 31, 2015
Weighted-
Average Grant
Date Fair Value
2,069,518
$
1,157,755
(231,271 )
(559,114 )
2,436,888 $
37.65
35.27
34.19
44.58
35.26
(1) Excludes dividend equivalents of 89,681 earned during vesting period
The weighted average fair value of awards granted in 2015, 2014 and 2013 were $35.27, $32.17 and $39.90 respectively. For the
years ended December 31, 2015, 2014, and 2013, the fair value of restricted stock units vested was $22 million, $28 million, and $37
million, respectively. As of December 31, 2015, there was $32 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 Stock Units
Restricted Stock
Performance Shares
401(k) Savings Plan
EDCP & DCPD
Total
Stock-based compensation costs capitalized
$
$
$
26 $
5
5
25
8
69 $
23 $
46 $
2
—
38
3
89 $
32 $
36
6
(10 )
25
3
60
20
(In millions)
86
87
FES
Stock-based Compensation Plan
Years ended December 31,
2015
2014
2013
(In millions)
6
(1 )
4
9
1
4 $
1
4
9 $
1 $
6 $
—
5
11 $
1 $
FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years
Stock-based compensation costs capitalized
ended December 31, 2015 was as follows:
Restricted Stock Units
Performance Shares
401(k) Savings Plan
Total
$
$
$
FES’ share of the pension and OPEB net (liability) asset as of December 31, 2015 and 2014, was as follows:
Pension
OPEB
2015
2014
2015
2014
(In millions)
Net (Liability) Asset
$
(303 ) $
(295 ) $
25 $
10
4. 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, 2015, approximately 9.9 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. 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. 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. Realized tax benefits during the years ended December 31, 2015, 2014 and 2013
were $10 million, $13 million and $13 million, respectively. 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.
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
Restricted Stock Units
Restricted Stock
Performance Shares
401(k) Savings Plan
EDCP & DCPD
Total
Years ended December 31,
2015
2014
2013
(In millions)
$
$
$
46 $
2
—
38
3
89 $
32 $
26 $
5
5
25
8
69 $
23 $
(10 )
36
6
25
3
60
20
2015
2014
2013
2015
2013
Pension
OPEB
2014
(In millions)
Stock option expense was not material for FirstEnergy or FES for the years December 31, 2015, 2014 or 2013. Income tax benefits
associated with stock based compensation plan expense were $12 million, $14 million and $23 million (FES - $2 million, $2 million
and $1 million) for the years ended 2015, 2014 and 2013, respectively.
Net Periodic Cost (Credit)
$
10 $
150 $
(30 ) $
(22 ) $
(24 ) $
(40 )
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. Compensation expense is recognized for the grant date
fair value of awards that are expected to vest. 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, 2015 was $3 million. No cash was paid to settle the restricted stock unit obligations in 2015.
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.
Restricted stock unit activity for the year ended December 31, 2015, was as follows:
Restricted Stock Unit Activity
Shares
Weighted-
Average Grant
Date Fair Value
Nonvested as of January 1, 2015
Granted in 2015
Forfeited in 2015
Vested in 2015(1)
Nonvested as of December 31, 2015
$
2,069,518
1,157,755
(231,271 )
(559,114 )
2,436,888 $
37.65
35.27
34.19
44.58
35.26
(1) Excludes dividend equivalents of 89,681 earned during vesting period
The weighted average fair value of awards granted in 2015, 2014 and 2013 were $35.27, $32.17 and $39.90 respectively. For the
years ended December 31, 2015, 2014, and 2013, the fair value of restricted stock units vested was $22 million, $28 million, and $37
million, respectively. As of December 31, 2015, there was $32 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.
Stock-based compensation costs capitalized
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.
86
87
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 $9 million and $8 million as of December 31, 2015 and December 31, 2014, respectively, is included in the
caption “Retirement benefits” on the Consolidated Balance Sheets.
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.
FES and the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries 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.
On December 18, 2015, the President signed into law the Protecting Americans from Tax Hikes Act of 2015 (the Act). The Act, among
other things, made permanent the R&D tax credit, and also extended accelerated depreciation of qualified capital investments placed
into service. This bonus depreciation provision is 50% for qualifying assets placed into service from 2015 through 2017, 40% for
qualifying assets placed into service in 2018 and 30% for qualifying assets placed into service in 2019. FirstEnergy and FES recorded
the effects of the Act that apply to 2015 in the fourth quarter of 2015. The extension of the tax benefits did not have a significant
impact to the effective tax rate.
Restricted common stock (restricted stock) activity for the year ended December 31, 2015, was as follows:
EDCP
Restricted Stock
Nonvested as of January 1, 2015
Granted in 2015
Forfeited in 2015
Vested in 2015(1)
Nonvested as of December 31, 2015
Number of
Shares
342,286 $
65,434
(26,079 )
(190,985 )
190,656 $
Weighted
Average
Grant-Date
Fair Value
45.29
32.98
57.58
43.17
40.65
(1) Excludes 52,872 shares for dividends earned during vesting period
The weighted average vesting period for restricted stock granted in 2015 was 5.59 years. The weighted average fair value of awards
granted in 2015, 2014, and 2013 were $32.98, $32.71 and $42.53 respectively. For the years ended December 31, 2015, 2014, and
2013, the fair value of restricted stock vested was $8 million, $4 million, and $7 million, respectively. As of December 31, 2015, there
was $3 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.
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 2015. Stock option activity during 2015 was as follows:
5. TAXES
Stock Option Activity
Balance, January 1, 2015 (1,077,988 options exercisable)
Options exercised
Options forfeited
Balance, December 31, 2015 (1,211,358 options exercisable)
Number of
Shares
1,439,145 $
(18,551 )
(8,623 )
1,411,971 $
Weighted
Average
Exercise
Price
44.83
29.53
68.02
44.89
Cash received from the exercise of stock options in 2015, 2014 and 2013 was $1 million, $1 million and $19 million, respectively. The
total intrinsic value of options exercised during 2015 was not material. The weighted-average remaining contractual term of options
outstanding as of December 31, 2015 was 3.58 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. No performance shares were granted in 2015. In 2014, $3 million cash
was paid to settle performance share obligations. During 2015 and 2013, no cash was paid to settle performance shares due to the
performance criteria not being met for the previous three-year vesting period.
401(k) Savings Plan
In 2015 and 2014, 1,072,494 and 756,412 shares of FE common stock, respectively, were issued and contributed to participants'
accounts. In 2013, approximately 708,000 shares of FE common stock were purchased on the market and contributed to participants’
accounts.
88
89
Restricted common stock (restricted stock) activity for the year ended December 31, 2015, was as follows:
EDCP
Restricted Stock
Nonvested as of January 1, 2015
Granted in 2015
Forfeited in 2015
Vested in 2015(1)
Nonvested as of December 31, 2015
Number of
Shares
342,286 $
65,434
(26,079 )
(190,985 )
190,656 $
Weighted
Average
Grant-Date
Fair Value
45.29
32.98
57.58
43.17
40.65
(1) Excludes 52,872 shares for dividends earned during vesting period
The weighted average vesting period for restricted stock granted in 2015 was 5.59 years. The weighted average fair value of awards
granted in 2015, 2014, and 2013 were $32.98, $32.71 and $42.53 respectively. For the years ended December 31, 2015, 2014, and
2013, the fair value of restricted stock vested was $8 million, $4 million, and $7 million, respectively. As of December 31, 2015, there
was $3 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.
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 2015. Stock option activity during 2015 was as follows:
Balance, January 1, 2015 (1,077,988 options exercisable)
Stock Option Activity
Options exercised
Options forfeited
Balance, December 31, 2015 (1,211,358 options exercisable)
Number of
Shares
1,439,145 $
(18,551 )
(8,623 )
1,411,971 $
Weighted
Average
Exercise
Price
44.83
29.53
68.02
44.89
Cash received from the exercise of stock options in 2015, 2014 and 2013 was $1 million, $1 million and $19 million, respectively. The
total intrinsic value of options exercised during 2015 was not material. The weighted-average remaining contractual term of options
outstanding as of December 31, 2015 was 3.58 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. No performance shares were granted in 2015. In 2014, $3 million cash
was paid to settle performance share obligations. During 2015 and 2013, no cash was paid to settle performance shares due to the
performance criteria not being met for the previous three-year vesting period.
401(k) Savings Plan
accounts.
In 2015 and 2014, 1,072,494 and 756,412 shares of FE common stock, respectively, were issued and contributed to participants'
accounts. In 2013, approximately 708,000 shares of FE common stock were purchased on the market and contributed to participants’
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 $9 million and $8 million as of December 31, 2015 and December 31, 2014, respectively, is included in the
caption “Retirement benefits” on the Consolidated Balance Sheets.
5. 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.
FES and the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries 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.
On December 18, 2015, the President signed into law the Protecting Americans from Tax Hikes Act of 2015 (the Act). The Act, among
other things, made permanent the R&D tax credit, and also extended accelerated depreciation of qualified capital investments placed
into service. This bonus depreciation provision is 50% for qualifying assets placed into service from 2015 through 2017, 40% for
qualifying assets placed into service in 2018 and 30% for qualifying assets placed into service in 2019. FirstEnergy and FES recorded
the effects of the Act that apply to 2015 in the fourth quarter of 2015. The extension of the tax benefits did not have a significant
impact to the effective tax rate.
88
89
INCOME TAXES (BENEFITS)(1)
FirstEnergy
Currently payable (receivable)-
Federal
State
Deferred, net-
Federal
State
Investment tax credit amortization
Total provision for income taxes (benefits)
FES
Currently payable (receivable)-
Federal
State
Deferred, net-
Federal
State
$
$
$
Investment tax credit amortization
Total provision for income taxes (benefits)
$
2015
2014
2013
(In millions)
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:
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 ) $
(118 )
70
(48 )
305
(54 )
251
(8 )
195
(300 )
(3 )
(303 )
317
(4 )
313
(4 )
6
(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.
FirstEnergy
Income from Continuing Operations before income taxes
Federal income tax expense 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
Tax basis balance sheet adjustments
Uncertain tax positions
Other, net
Total income taxes (benefits)
Effective income tax rate
FES
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit
Amortization of investment tax credits
ESOP dividend
Uncertain tax positions
Other, net
Total income taxes (benefits)
Effective income tax rate
2015
2014
2013
(In millions)
$
$
893
313
$
$
171
60
$
$
570
199
315
$
35.3 %
(42 )
$
(24.6 )%
195
34.2 %
34
(16 )
(8 )
(8 )
(6 )
—
1
5
16
(2 )
(1 )
5
(4 )
$
$
$
12
(13 )
(10 )
(27 )
(6 )
(25 )
(35 )
2
(14 )
(4 )
(1 )
—
(3 )
10
(7 )
(8 )
—
(9 )
—
(2 )
12
52
18
(5 )
(4 )
(2 )
—
(1 )
6
65
$
44.2 %
(228 )
$
38.8 %
11.5 %
Income (loss) from Continuing Operations before income taxes (benefits) $
Federal income tax expense (benefit) at statutory rate (35%)
147
51
$
$
(588 )
(206 )
$
$
In 2015, FirstEnergy’s effective tax rate was 35.3% compared to (24.6)% in 2014. The increase in the effective tax rate year-over-year
resulted from lower tax benefits in 2015 as compared to 2014, primarily related to IRS approved changes in accounting methods,
reduced tax benefits on uncertain tax positions, partially offset by lower valuation allowances required on state and municipal net
operating loss carryforwards that FirstEnergy believes are no longer realizable. Additionally, during 2014, income tax benefits of $25
million were recorded that related to prior periods. The out-of-period adjustment primarily related to the correction of amounts
included in the FirstEnergy’s tax basis balance sheet. Management determined that this adjustment was not material to 2014 or any
prior period. The increase in the effective rate was also impacted by higher income from continuing operations.
In 2015, FES’ effective tax rate on income from continuing operations was 44.2% compared to 38.8% on a loss from continuing
operations in 2014. The increase in the effective tax rate is primarily due to an increase in reserves associated with uncertain tax
positions in 2015 and the absence of tax benefits recognized in 2014 associated with changes in state apportionment factors, partially
offset by lower valuation allowances recorded on state and municipal NOL carryforwards that FirstEnergy believes are no longer
realizable.
90
91
INCOME TAXES (BENEFITS)(1)
FirstEnergy
Currently payable (receivable)-
Federal
State
Deferred, net-
Federal
State
FES
Federal
State
Deferred, net-
Federal
State
Investment tax credit amortization
Total provision for income taxes (benefits)
315 $
(42 ) $
Currently payable (receivable)-
$
$
$
1 $
30
31
277
15
292
(8 )
(56 ) $
2
(54 )
103
18
121
(2 )
(132 ) $
(72 )
(204 )
214
(42 )
172
(10 )
(222 ) $
(13 )
(235 )
25
(14 )
11
(4 )
(118 )
70
(48 )
305
(54 )
251
(8 )
195
(300 )
(3 )
(303 )
317
(4 )
313
(4 )
6
Investment tax credit amortization
Total provision for income taxes (benefits)
$
65 $
(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.
2015
2014
2013
(In millions)
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:
FirstEnergy
Income from Continuing Operations before income taxes
Federal income tax expense 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
Tax basis balance sheet adjustments
Uncertain tax positions
Other, net
Total income taxes (benefits)
Effective income tax rate
FES
Income (loss) from Continuing Operations before income taxes (benefits) $
Federal income tax expense (benefit) at statutory rate (35%)
$
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit
Amortization of investment tax credits
ESOP dividend
Uncertain tax positions
Other, net
Total income taxes (benefits)
Effective income tax rate
$
2015
2014
2013
(In millions)
$
$
893
313
$
$
171
60
$
$
34
(16 )
(8 )
(8 )
(6 )
—
1
5
315
$
12
(13 )
(10 )
(27 )
(6 )
(25 )
(35 )
2
(42 )
$
$
570
199
10
(7 )
(8 )
—
(9 )
—
(2 )
12
195
35.3 %
(24.6 )%
34.2 %
147
51
$
$
16
(2 )
(1 )
5
(4 )
65
44.2 %
$
(588 )
(206 )
$
$
(14 )
(4 )
(1 )
—
(3 )
(228 )
$
38.8 %
52
18
(5 )
(4 )
(2 )
—
(1 )
6
11.5 %
In 2015, FirstEnergy’s effective tax rate was 35.3% compared to (24.6)% in 2014. The increase in the effective tax rate year-over-year
resulted from lower tax benefits in 2015 as compared to 2014, primarily related to IRS approved changes in accounting methods,
reduced tax benefits on uncertain tax positions, partially offset by lower valuation allowances required on state and municipal net
operating loss carryforwards that FirstEnergy believes are no longer realizable. Additionally, during 2014, income tax benefits of $25
million were recorded that related to prior periods. The out-of-period adjustment primarily related to the correction of amounts
included in the FirstEnergy’s tax basis balance sheet. Management determined that this adjustment was not material to 2014 or any
prior period. The increase in the effective rate was also impacted by higher income from continuing operations.
In 2015, FES’ effective tax rate on income from continuing operations was 44.2% compared to 38.8% on a loss from continuing
operations in 2014. The increase in the effective tax rate is primarily due to an increase in reserves associated with uncertain tax
positions in 2015 and the absence of tax benefits recognized in 2014 associated with changes in state apportionment factors, partially
offset by lower valuation allowances recorded on state and municipal NOL carryforwards that FirstEnergy believes are no longer
realizable.
90
91
company's tax return. As of December 31, 2015 and 2014, FirstEnergy's total unrecognized income tax benefits were approximately
$34 million. If ultimately recognized in future years, approximately $29 million of unrecognized income tax benefits as of
December 31, 2015, would impact the effective tax rate. As of December 31, 2015, it is reasonably possible that approximately $9
million of unrecognized tax benefits may be resolved during 2016 as a result of the statute of limitations expiring, of which
approximately $7 million would affect FirstEnergy's effective tax rate.
The following table summarizes the changes in unrecognized tax positions for the years ended 2015, 2014 and 2013:
Balance, January 1, 2013
Prior years increases
Prior years decreases
Balance, December 31, 2013
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
FirstEnergy
FES
(In millions)
$
$
$
$
43 $
10
(5 )
48 $
4
5
3
7
(23 )
34 $
(10 )
34 $
3
—
—
3
—
—
—
3
—
5
—
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 reversal of accrued interest associated with
unrecognized tax benefits reduced FirstEnergy's effective tax rate in 2015 and 2014 by approximately $1 million and $6 million,
respectively. There was an increase of $1 million of accrued interest for the year ended December 31, 2013.
The following table summarizes the net interest expense (income) for the three years ended December 31, 2015 and the cumulative
net interest payable as of December 31, 2015 and 2014 (FES did not have net interest expense (income) or a net interest payable for
the periods presented):
Net Interest Expense (Income)
For the Years Ended December 31,
Net Interest Payable
As of December 31,
2015
2014
2013
2015
2014
FirstEnergy
$
(1 ) $
(6 ) $
(In millions)
1 $
(In millions)
1 $
2
Accumulated deferred income taxes as of December 31, 2015 and 2014 are as follows:
FirstEnergy
Property basis differences
Deferred sale and leaseback gain
Pension and OPEB
Nuclear decommissioning activities
Asset retirement obligations
Regulatory asset/liability
Loss carryforwards and AMT credits
Loss carryforward 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
Loss carryforward valuation reserve
All other
Net deferred income tax liability
2015
2014
(In millions)
$
$
$
$
9,920 $
(360 )
(1,541 )
480
(731 )
763
(1,965 )
192
15
6,773 $
1,901 $
(342 )
(393 )
95
483
(509 )
(687 )
46
6
600 $
9,354
(381 )
(1,433 )
458
(641 )
768
(1,932 )
174
172
6,539
1,749
(356 )
(373 )
75
489
(486 )
(631 )
32
(15 )
484
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 2011-2014. In January 2015, the IRS completed its examination of the 2013 federal
income tax return and issued a Revenue Agent Report and there were no material impacts to FirstEnergy's effective tax rate
associated with this examination. Tax year 2014 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, 2015, the deferred income
tax assets, before any valuation allowances, for loss carryforwards and AMT credits consisted of $1.5 billion of Federal NOL
carryforwards, net of tax, that will begin to expire in 2030, Federal AMT credits of $26 million, net of tax, that have an indefinite
carryforward period, and $398 million, net of tax, of state and local NOL carryforwards that will begin to expire in 2016.
The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10 billion for
FirstEnergy, of which approximately $6 billion 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.
Expiration Period
FirstEnergy
FES
2016-2020
2021-2025
2026-2030
2031-2035
(In millions)
State
Local
State
Local
$
$
403 $
1,323
2,205
3,245
7,176 $
2,983 $
—
—
—
2,983 $
95 $
68
259
1,128
1,550 $
1,820
—
—
—
1,820
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
92
93
company's tax return. As of December 31, 2015 and 2014, FirstEnergy's total unrecognized income tax benefits were approximately
$34 million. If ultimately recognized in future years, approximately $29 million of unrecognized income tax benefits as of
December 31, 2015, would impact the effective tax rate. As of December 31, 2015, it is reasonably possible that approximately $9
million of unrecognized tax benefits may be resolved during 2016 as a result of the statute of limitations expiring, of which
approximately $7 million would affect FirstEnergy's effective tax rate.
The following table summarizes the changes in unrecognized tax positions for the years ended 2015, 2014 and 2013:
Balance, January 1, 2013
Prior years increases
Prior years decreases
Balance, December 31, 2013
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
FirstEnergy
FES
$
$
$
$
(In millions)
43 $
10
(5 )
48 $
4
5
(23 )
34 $
3
7
(10 )
34 $
3
—
—
3
—
—
—
3
—
5
—
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 reversal of accrued interest associated with
unrecognized tax benefits reduced FirstEnergy's effective tax rate in 2015 and 2014 by approximately $1 million and $6 million,
respectively. There was an increase of $1 million of accrued interest for the year ended December 31, 2013.
The following table summarizes the net interest expense (income) for the three years ended December 31, 2015 and the cumulative
net interest payable as of December 31, 2015 and 2014 (FES did not have net interest expense (income) or a net interest payable for
the periods presented):
Net Interest Expense (Income)
For the Years Ended December 31,
Net Interest Payable
As of December 31,
2015
2014
2013
2015
2014
FirstEnergy
$
(1 ) $
(6 ) $
(In millions)
1 $
(In millions)
1 $
2
Accumulated deferred income taxes as of December 31, 2015 and 2014 are as follows:
FirstEnergy
Property basis differences
Deferred sale and leaseback gain
Pension and OPEB
Nuclear decommissioning activities
Asset retirement obligations
Regulatory asset/liability
Loss carryforwards and AMT credits
Loss carryforward valuation reserve
Net deferred income tax liability
All other
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
Loss carryforward valuation reserve
All other
Net deferred income tax liability
2015
2014
(In millions)
$
9,920 $
$
$
1,901 $
1,749
(360 )
(1,541 )
480
(731 )
763
(1,965 )
192
15
6,773 $
(342 )
(393 )
95
483
(509 )
(687 )
46
6
9,354
(381 )
(1,433 )
458
(641 )
768
(1,932 )
174
172
6,539
(356 )
(373 )
75
489
(486 )
(631 )
32
(15 )
484
$
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 2011-2014. In January 2015, the IRS completed its examination of the 2013 federal
income tax return and issued a Revenue Agent Report and there were no material impacts to FirstEnergy's effective tax rate
associated with this examination. Tax year 2014 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, 2015, the deferred income
tax assets, before any valuation allowances, for loss carryforwards and AMT credits consisted of $1.5 billion of Federal NOL
carryforwards, net of tax, that will begin to expire in 2030, Federal AMT credits of $26 million, net of tax, that have an indefinite
carryforward period, and $398 million, net of tax, of state and local NOL carryforwards that will begin to expire in 2016.
The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10 billion for
FirstEnergy, of which approximately $6 billion 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.
Expiration Period
FirstEnergy
FES
2016-2020
2021-2025
2026-2030
2031-2035
(In millions)
State
Local
State
Local
403 $
2,983 $
1,323
2,205
3,245
—
—
—
7,176 $
2,983 $
95 $
68
259
1,128
1,550 $
1,820
—
—
—
1,820
$
$
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
92
93
General Taxes
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
2015
2014
2013
(In millions)
$
$
$
$
193 $
224
410
119
32
978 $
44 $
36
16
2
98 $
194 $
226
393
112
37
962 $
69 $
39
17
3
128 $
219
240
368
110
41
978
77
40
19
2
138
6. LEASES
leases.
FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable
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, expiring in 2016. In that same year, CEI and TE also sold portions of
their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for
lease terms of approximately 30 years expiring in 2017. OE, CEI and TE have 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. In 2013, FG acquired the remaining lessor interests in Bruce Mansfield
Units 1, 2 and 3, which were part of the leases entered into by CEI and TE in 1987.
In February 2014, NG purchased 47.7 MW of lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for
approximately $94 million. 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. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity
interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease
term. In November 2014, NG repurchased 55.3 MW of lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for
approximately $87 million. OE and TE continue to lease these MW under their respective sale and leaseback arrangements and the
related lease debt remains outstanding.
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. Similarly, CEI and TE established Shippingport in 1997 to purchase the
lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. During
2013, the investments held at Shippingport were liquidated. The PNBV arrangements effectively reduce lease costs related to those
transactions (see Note 8, Variable Interest Entities).
As of December 31, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60%
of Beaver Valley Unit 2.
Operating lease expense for 2015, 2014 and 2013, is summarized as follows:
2015
2014
2013
$
$
174 $
94 $
199 $
95 $
224
97
The future minimum capital lease payments as of December 31, 2015 are as follows:
(In millions)
FirstEnergy
FES
Capital leases
2016
2017
2018
2019
2020
Years thereafter
Interest portion
Total minimum lease payments
Present value of net minimum lease payments
Less current portion
Noncurrent portion
FirstEnergy
FES
$
(In millions)
36 $
31
24
18
14
27
150
(18 )
132
32
$
100 $
6
6
2
—
—
—
14
(1 )
13
5
8
94
95
General Taxes
6. LEASES
FirstEnergy
KWH excise
State gross receipts
Real and personal property
Social security and unemployment
Total general taxes
Other
FES
State gross receipts
Real and personal property
Social security and unemployment
Other
Total general taxes
2015
2014
2013
(In millions)
$
193 $
194 $
978 $
962 $
224
410
119
32
44 $
36
16
2
98 $
226
393
112
37
69 $
39
17
3
128 $
$
$
$
219
240
368
110
41
978
77
40
19
2
138
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, expiring in 2016. In that same year, CEI and TE also sold portions of
their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for
lease terms of approximately 30 years expiring in 2017. OE, CEI and TE have 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. In 2013, FG acquired the remaining lessor interests in Bruce Mansfield
Units 1, 2 and 3, which were part of the leases entered into by CEI and TE in 1987.
In February 2014, NG purchased 47.7 MW of lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for
approximately $94 million. 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. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity
interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease
term. In November 2014, NG repurchased 55.3 MW of lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for
approximately $87 million. OE and TE continue to lease these MW under their respective sale and leaseback arrangements and the
related lease debt remains outstanding.
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. Similarly, CEI and TE established Shippingport in 1997 to purchase the
lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. During
2013, the investments held at Shippingport were liquidated. The PNBV arrangements effectively reduce lease costs related to those
transactions (see Note 8, Variable Interest Entities).
As of December 31, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60%
of Beaver Valley Unit 2.
Operating lease expense for 2015, 2014 and 2013, is summarized as follows:
(In millions)
FirstEnergy
FES
2015
2014
2013
$
$
174 $
94 $
199 $
95 $
224
97
The future minimum capital lease payments as of December 31, 2015 are as follows:
Capital leases
FirstEnergy
FES
2016
2017
2018
2019
2020
Years thereafter
Total minimum lease payments
Interest portion
Present value of net minimum lease payments
Less current portion
Noncurrent portion
$
$
(In millions)
36 $
31
24
18
14
27
150
(18 )
132
32
100 $
6
6
2
—
—
—
14
(1 )
13
5
8
94
95
FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2015, are as follows:
the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE
FirstEnergy
when it is determined that it is the primary beneficiary.
Operating Leases
Lease Payments
PNBV
Net
The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that
(In millions)
FirstEnergy consolidates, but does not own.
2016
2017
2018
2019
2020
$
Years thereafter
Total minimum lease payments
$
197 $
122
135
116
91
1,438
2,099 $
13 $
3
—
—
—
—
16 $
184
119
135
116
91
1,438
2,083
FES' future minimum operating lease payments as of December 31, 2015, are as follows:
Operating Leases
Lease Payments
(In millions)
2016
2017
2018
2019
2020
Years thereafter
Total minimum lease payments
$
$
131
82
101
97
68
1,315
1,794
7. INTANGIBLE ASSETS
As of December 31, 2015, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet,
include the following:
Intangible Assets
Actual
Accumulated
Amortization Net
2015
Amortization Expense
Estimated
(In millions)
NUG contracts(1)
OVEC
Coal contracts(2)(3)(4)
FES customer contracts
Gross
$
124 $
54
556
148
882 $
$
99 $
45
126
61
25 $
9
430
87
551 $ 331 $
2016 2017 2018 2019 2020 Thereafter
74
35
—
—
109
5 $
5 $
2
2
32
38
17
16
62 $ 55 $ 38 $
5 $
2
17
13
37 $
5 $
2
6
1
14 $
5 $
2
17
14
5 $
2
116
17
140 $
(1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
(2) A gross amount of $40 million ($23 million, net) of the coal contracts is related to FES. The 2015 and estimated 2016 to 2019 amortization
expense for FES is $5.7 million annually.
(3) A gross amount of $102 million ($16 million, net) of the coal contracts was 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) Amortization expense in 2015, includes a $67 million impairment of a coal contract intangible asset associated with the termination of a coal
supply contract, which impacted earnings.
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.
8. 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
96
97
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
statements):
VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial
• PNBV - 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 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. As of December 31, 2015 and December 31, 2014, $362 million and $386
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, 2015 and December 31, 2014, $128 million and $168
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, 2015 and December 31, 2014, $429 million and $450 million of the environmental control bonds were
outstanding, respectively.
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 15, 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 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.
FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2015, are as follows:
Operating Leases
Lease Payments
PNBV
Net
FirstEnergy
(In millions)
2016
2017
2018
2019
2020
$
197 $
122
135
116
91
1,438
2,099 $
184
119
135
116
91
1,438
2,083
Years thereafter
Total minimum lease payments
$
FES' future minimum operating lease payments as of December 31, 2015, are as follows:
Operating Leases
Lease Payments
(In millions)
2016
2017
2018
2019
2020
Years thereafter
Total minimum lease payments
$
$
13 $
3
—
—
—
—
16 $
131
82
101
97
68
1,315
1,794
7. INTANGIBLE ASSETS
include the following:
As of December 31, 2015, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet,
Intangible Assets
Actual
Amortization Expense
Estimated
(In millions)
NUG contracts(1)
OVEC
Coal contracts(2)(3)(4)
FES customer contracts
Accumulated
Amortization Net
Gross
$
124 $
2015
2016 2017 2018 2019 2020 Thereafter
54
556
148
25 $
99 $
5 $
5 $
5 $
5 $
5 $
5 $
9
430
87
45
126
61
2
116
17
2
38
17
2
32
16
2
17
14
2
17
13
2
6
1
$
882 $
551 $ 331 $
140 $
62 $ 55 $ 38 $
37 $
14 $
74
35
—
—
109
(1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
(2) A gross amount of $40 million ($23 million, net) of the coal contracts is related to FES. The 2015 and estimated 2016 to 2019 amortization
expense for FES is $5.7 million annually.
(3) A gross amount of $102 million ($16 million, net) of the coal contracts was 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) Amortization expense in 2015, includes a $67 million impairment of a coal contract intangible asset associated with the termination of a coal
supply contract, which impacted earnings.
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.
8. 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 - 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 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. As of December 31, 2015 and December 31, 2014, $362 million and $386
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, 2015 and December 31, 2014, $128 million and $168
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, 2015 and December 31, 2014, $429 million and $450 million of the environmental control bonds were
outstanding, respectively.
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 15, 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 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.
96
97
• Power Purchase 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.
9. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASUREMENTS
FirstEnergy maintains 15 long-term power purchase agreements 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 in the entities 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
Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a
variable interest were $116 million and $185 million, respectively, during the years ended December 31, 2015 and 2014.
• Sale and Leaseback Transactions - 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. 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, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce
Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.
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.
Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor
equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the
end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at
Perry Unit 1 and Beaver Valley Unit 2.
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, 2015:
Maximum
Exposure
Discounted Lease
Payments, net
Net
Exposure
(In millions)
FirstEnergy
FES
$
$
1,225 $
1,155 $
950 $
933 $
275
222
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 processes for FTRs and NUGs are as 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 RTO 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 RTO 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 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.
NUG contracts represent purchase power agreements 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 MWHs. Pricing for the NUG contracts is a combination of market
prices for the current year and next three 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 MWHs reflects data provided by contractual arrangements and historical
trends. The model calculates the fair value by multiplying the prices by the generation MWHs. 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, 2015, from those used as of December 31, 2014. 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.
98
99
• Power Purchase Agreements - FirstEnergy evaluated its power purchase agreements and determined that certain NUG
9. FAIR VALUE MEASUREMENTS
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 15 long-term power purchase agreements 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 in the entities 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
Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a
variable interest were $116 million and $185 million, respectively, during the years ended December 31, 2015 and 2014.
• Sale and Leaseback Transactions - 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. 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, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce
Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.
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.
Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor
equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the
end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at
Perry Unit 1 and Beaver Valley Unit 2.
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, 2015:
Maximum
Exposure
Discounted Lease
Payments, net
Net
Exposure
(In millions)
FirstEnergy
FES
$
$
1,225 $
1,155 $
950 $
933 $
275
222
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 processes for FTRs and NUGs are as 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 RTO 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 RTO 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 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.
NUG contracts represent purchase power agreements 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 MWHs. Pricing for the NUG contracts is a combination of market
prices for the current year and next three 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 MWHs reflects data provided by contractual arrangements and historical
trends. The model calculates the fair value by multiplying the prices by the generation MWHs. 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, 2015, from those used as of December 31, 2014. 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.
98
99
Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the years
ended December 31, 2015 and 2014. The following tables set forth the recurring assets and liabilities that are accounted for at fair
value by level within the fair value hierarchy:
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, 2015 and December 31, 2014:
FirstEnergy
Recurring Fair Value Measurements
Level 1
December 31, 2015
Level 3
Level 2
Total
Level 1
(In millions)
December 31, 2014
Level 3
Level 2
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
Derivative liabilities - commodity contracts
Derivative liabilities - FTRs
Derivative liabilities - NUG contracts(1)
Total liabilities
Net assets (liabilities)(4)
$
$
$
$
— $ 1,245 $
4
—
—
576
—
—
—
105
685 $ 2,182 $
224
—
—
—
75
180
246
212
— $ 1,245 $
228
—
8
8
1
1
576
—
75
—
180
—
246
—
—
317
9 $ 2,876 $
— $ 1,221 $
171
1
—
—
—
—
—
592
76
—
182
—
237
—
256
55
648 $ 2,143 $
— $ 1,221
172
—
39
39
2
2
592
—
76
—
182
—
237
—
—
311
41 $ 2,832
(9 ) $
—
—
(9 ) $
(122 ) $
—
—
(122 ) $
— $
(13 )
(137 )
(150 ) $
(131 ) $
(13 )
(137 )
(281 ) $
(26 ) $
—
—
(26 ) $
(141 ) $
—
—
(141 ) $
— $
(14 )
(153 )
(167 ) $
(167 )
(14 )
(153 )
(334 )
676 $ 2,060 $
(141 ) $ 2,595 $
622 $ 2,002 $
(126 ) $ 2,498
hierarchy for the period ended December 31, 2015:
The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value
(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 $7 million and $40 million as of December 31, 2015 and December 31, 2014, respectively, of receivables, payables, taxes and accrued
income associated with financial instruments reflected within the fair value table.
100
101
NUG Contracts(1)
FTRs
Derivative
Assets
Derivative
Liabilities
Net
Derivative
Assets
Derivative
Liabilities
Net
(In millions)
January 1, 2014
Balance
Unrealized gain (loss)
Purchases
Settlements
December 31, 2014
Balance
$
Unrealized gain (loss)
Purchases
Settlements
December 31, 2015
Balance
$
20
$
(222 ) $
(202 ) $
4
$
(12 ) $
2
—
(20 )
2
2
—
(3 )
(2 )
—
71
(49 )
—
65
—
—
51
(47 )
—
62
47
26
(38 )
(5 )
22
(48 )
$
(153 ) $
(151 ) $
39
$
(14 ) $
(8 )
46
10
(23 )
25
(12 )
11
(29 )
(1 )
(16 )
15
(7 )
(11 )
19
$
1
$
(137 ) $
(136 ) $
8
$
(13 ) $
(5 )
(1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Level 3 Quantitative Information
Fair Value, Net
(In millions)
Valuation
Technique
Significant Input
Range
FTRs
NUG Contracts
$
$
(5 ) Model
RTO auction clearing prices
($3.90) to $6.90
(136 ) Model
Generation
Regional electricity prices
400 to 3,871,000
$38.10 to $45.60
Weighted
Average
Units
$1.00
839,000
$40.20
Dollars/MWH
MWH
Dollars/MWH
FES
Recurring Fair Value Measurements
December 31, 2015
December 31, 2014
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
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
678 $
224
—
—
59
23
4
184
(In millions)
— $
—
5
—
—
—
—
—
678 $
228
5
378
59
23
4
184
— $
1
—
360
—
—
—
—
655 $
171
—
—
57
46
4
199
— $
—
27
—
—
—
—
—
655
172
27
360
57
46
4
199
4
—
378
—
—
—
—
$
382 $ 1,172 $
5 $ 1,559 $
361 $ 1,132 $
27 $ 1,520
Derivative liabilities - commodity contracts
$
Derivative liabilities - FTRs
Total liabilities
(9 ) $
(122 ) $
—
—
— $
(11 )
(131 ) $
(26 ) $
(141 ) $
(11 )
—
—
— $
(13 )
(167 )
(13 )
(9 ) $
(122 ) $
(11 ) $
(142 ) $
(26 ) $
(141 ) $
(13 ) $
(180 )
Net assets (liabilities)(3)
373 $ 1,050 $
(6 ) $ 1,417 $
335 $
991 $
14 $ 1,340
$
$
Recurring Fair Value Measurements
December 31, 2015
December 31, 2014
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
— $ 1,245 $
— $ 1,245 $
— $ 1,221 $
— $ 1,221
576
4
—
—
—
—
—
105
224
—
—
—
75
180
246
212
(In millions)
228
8
1
576
75
180
246
317
1
—
—
592
—
—
—
55
—
8
1
—
—
—
—
—
171
—
—
—
76
182
237
256
—
39
2
—
—
—
—
—
172
39
2
592
76
182
237
311
$
685 $ 2,182 $
9 $ 2,876 $
648 $ 2,143 $
41 $ 2,832
value by level within the fair value hierarchy:
FirstEnergy
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
Derivative liabilities - FTRs
Derivative liabilities - NUG contracts(1)
Derivative liabilities - commodity contracts
$
(9 ) $
(122 ) $
(131 ) $
(26 ) $
(141 ) $
—
—
—
—
— $
(13 )
(137 )
(13 )
(137 )
—
—
—
—
— $
(14 )
(153 )
(167 )
(14 )
(153 )
(334 )
Total liabilities
(9 ) $
(122 ) $
(150 ) $
(281 ) $
(26 ) $
(141 ) $
(167 ) $
Net assets (liabilities)(4)
676 $ 2,060 $
(141 ) $ 2,595 $
622 $ 2,002 $
(126 ) $ 2,498
$
$
(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 $7 million and $40 million as of December 31, 2015 and December 31, 2014, respectively, of receivables, payables, taxes and accrued
income associated with financial instruments reflected within the fair value table.
Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the years
Rollforward of Level 3 Measurements
ended December 31, 2015 and 2014. The following tables set forth the recurring assets and liabilities that are accounted for at fair
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, 2015 and December 31, 2014:
NUG Contracts(1)
FTRs
Derivative
Assets
Derivative
Liabilities
Net
Derivative
Assets
Derivative
Liabilities
Net
(In millions)
January 1, 2014
Balance
$
Unrealized gain (loss)
Purchases
Settlements
December 31, 2014
Balance
$
Unrealized gain (loss)
Purchases
Settlements
December 31, 2015
Balance
$
20
2
—
(20 )
$
2
2
—
(3 )
(222 ) $
(2 )
—
71
(153 ) $
(49 )
—
65
(202 ) $
—
—
51
(151 ) $
(47 )
—
62
$
$
4
47
26
(38 )
39
(5 )
22
(48 )
(12 ) $
(1 )
(16 )
15
(14 ) $
(7 )
(11 )
19
(8 )
46
10
(23 )
25
(12 )
11
(29 )
$
1
$
(137 ) $
(136 ) $
8
$
(13 ) $
(5 )
(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, 2015:
Fair Value, Net
(In millions)
Valuation
Technique
Significant Input
Range
Weighted
Average
FTRs
NUG Contracts
$
$
(5 ) Model
(136 ) Model
RTO auction clearing prices
Generation
Regional electricity prices
($3.90) to $6.90
400 to 3,871,000
$38.10 to $45.60
$1.00
839,000
$40.20
Units
Dollars/MWH
MWH
Dollars/MWH
FES
Recurring Fair Value Measurements
Level 1
December 31, 2015
Level 3
Level 2
Total
Level 1
December 31, 2014
Level 3
Level 2
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
$
678 $
224
—
—
59
23
4
184
— $
4
—
378
—
—
—
—
382 $ 1,172 $
(In millions)
— $
678 $
—
228
5
5
—
378
—
59
—
23
—
4
184
—
5 $ 1,559 $
— $
655 $
1
171
—
—
360
—
—
57
—
46
—
4
199
—
361 $ 1,132 $
— $
655
—
172
27
27
—
360
—
57
—
46
—
4
199
—
27 $ 1,520
Derivative liabilities - commodity contracts
$
Derivative liabilities - FTRs
Total liabilities
Net assets (liabilities)(3)
$
$
(9 ) $
—
(9 ) $
(122 ) $
—
(122 ) $
— $
(11 )
(11 ) $
(131 ) $
(11 )
(142 ) $
(26 ) $
—
(26 ) $
(141 ) $
—
(141 ) $
— $
(13 )
(13 ) $
(167 )
(13 )
(180 )
373 $ 1,050 $
(6 ) $ 1,417 $
335 $
991 $
14 $ 1,340
100
101
Securities REIT index.
income associated with financial instruments reflected within the fair value table.
(1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred
(2) Primarily consists of short-term cash investments.
(3) Excludes $1 million and $44 million as of December 31, 2015 and December 31, 2014, respectively, of receivables, payables, taxes and accrued
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, 2015 and December 31, 2014:
Derivative Asset Derivative Liability
Net Asset/(Liability)
(In millions)
January 1, 2014 Balance
Unrealized gain (loss)
Purchases
Settlements
$
December 31, 2014 Balance
$
Unrealized gain (loss)
Purchases
Settlements
December 31, 2015 Balance
$
3 $
34
15
(25 )
27 $
2
9
(33 )
5 $
(11 ) $
(1 )
(16 )
15
(13 ) $
(5 )
(10 )
17
(11 ) $
(8 )
33
(1 )
(10 )
14
(3 )
(1 )
(16 )
(6 )
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, 2015:
December 31, 2015
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
Fair Value, Net
(In millions)
Valuation
Technique
Significant Input
Range
Weighted
Average
Units
FTRs
$
(6 )
Model
RTO auction clearing prices
($3.90) to $5.70
$0.70 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 first 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 in net 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.
102
103
AFS Securities
FirstEnergy holds debt and equity securities within its NDT, nuclear fuel disposal and NUG 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, nuclear fuel disposal and NUG trusts as of December 31, 2015 and December 31, 2014:
December 31, 2015(1)
December 31, 2014(2)
Cost
Basis
Unrealized
Gains
Fair Value
Cost
Basis
Unrealized
Gains
Fair Value
(In millions)
1,778 $
801
16 $
9
1,794 $
810
1,724 $
788
27 $
13
1,751
801
Debt securities
FirstEnergy
FES
Equity securities
FirstEnergy
FES
$
$
$
$
$
542 $
354
34 $
24
576 $
378
533 $
329
58 $
31
591
360
(1) Excludes short-term cash investments: FE Consolidated - $157 million;; FES - $139 million.
(2) Excludes short-term cash investments: FE Consolidated - $241 million;; FES - $204 million.
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, 2015, 2014 and 2013 were as follows:
December 31, 2014
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
(In millions)
1,534 $
733
209 $
158
(191 ) $
(134 )
(102 ) $
(90 )
(In millions)
2,133 $
1,163
146 $
113
(75 ) $
(54 )
(37 ) $
(33 )
(In millions)
2,047 $
940
92 $
70
(46 ) $
(21 )
(90 ) $
(79 )
101
57
96
56
101
60
December 31, 2013
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
FirstEnergy
FES
FirstEnergy
FES
FirstEnergy
FES
Held-To-Maturity Securities
The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values
of investments in held-to-maturity securities as of December 31, 2015 and December 31, 2014:
December 31, 2015
December 31, 2014
Cost
Basis
Unrealized
Gains
Fair Value
Cost
Basis
Unrealized
Gains
Fair Value
(In millions)
Debt Securities
FirstEnergy
$
6 $
2 $
8 $
13 $
4 $
17
(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 $1 million and $44 million as of December 31, 2015 and December 31, 2014, 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, 2015 and December 31, 2014:
January 1, 2014 Balance
$
Unrealized gain (loss)
December 31, 2014 Balance
$
Unrealized gain (loss)
Purchases
Settlements
Purchases
Settlements
December 31, 2015 Balance
$
Level 3 Quantitative Information
Derivative Asset Derivative Liability
Net Asset/(Liability)
(In millions)
3 $
34
15
(25 )
27 $
2
9
(33 )
5 $
(11 ) $
(1 )
(16 )
15
(13 ) $
(5 )
(10 )
17
(11 ) $
(8 )
33
(1 )
(10 )
14
(3 )
(1 )
(16 )
(6 )
AFS Securities
FirstEnergy holds debt and equity securities within its NDT, nuclear fuel disposal and NUG 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, nuclear fuel disposal and NUG trusts as of December 31, 2015 and December 31, 2014:
December 31, 2015(1)
December 31, 2014(2)
Cost
Basis
Unrealized
Gains
Fair Value
Cost
Basis
Unrealized
Gains
Fair Value
(In millions)
1,778 $
801
16 $
9
1,794 $
810
1,724 $
788
27 $
13
1,751
801
542 $
354
34 $
24
576 $
378
533 $
329
58 $
31
591
360
Debt securities
FirstEnergy
$
FES
Equity securities
$
FirstEnergy
FES
(1) Excludes short-term cash investments: FE Consolidated - $157 million;; FES - $139 million.
(2) Excludes short-term cash investments: FE Consolidated - $241 million;; FES - $204 million.
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, 2015, 2014 and 2013 were as follows:
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, 2015:
December 31, 2015
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
FirstEnergy
FES
December 31, 2014
FirstEnergy
FES
December 31, 2013
FirstEnergy
FES
$
$
$
(In millions)
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
Sale
Proceeds
Realized
Gains
Realized
Losses
OTTI
Interest and
Dividend Income
(In millions)
2,047 $
940
92 $
70
(46 ) $
(21 )
(90 ) $
(79 )
101
60
required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost
Held-To-Maturity Securities
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.
The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values
of investments in held-to-maturity securities as of December 31, 2015 and December 31, 2014:
December 31, 2015
December 31, 2014
Cost
Basis
Unrealized
Gains
Fair Value
Cost
Basis
Unrealized
Gains
Fair Value
(In millions)
Debt Securities
FirstEnergy
$
6 $
2 $
8 $
13 $
4 $
17
102
103
Fair Value, Net
(In millions)
Valuation
Technique
Significant Input
Range
Weighted
Average
Units
FTRs
$
(6 )
Model
RTO auction clearing prices
($3.90) to $5.70
$0.70 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 first 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
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 in net 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.
The held-to-maturity debt securities contractually mature by June 30, 2017. Investments in employee benefit trusts and equity method
investments totaling $255 million as of December 31, 2015 and $626 million as of December 31, 2014, 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 and other long-term obligations, excluding capital lease obligations and net unamortized
premiums and discounts:
December 31, 2015
December 31, 2014
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
(In millions)
FirstEnergy
FES
$
20,244 $
3,027
21,519 $
3,121
19,828 $
3,097
21,733
3,241
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 and its subsidiaries. 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, 2015 and December 31, 2014.
10. 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
As of December 31, 2015 and 2014, no interest rate swaps were outstanding.
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
$11 million and $8 million as of December 31, 2015 and December 31, 2014, respectively. Since the forecasted transactions remain
probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $1 million
of net unamortized losses is expected to be amortized to income during the next twelve months.
104
105
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 $42 million and $50 million as of December 31, 2015 and
December 31, 2014, respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to
be amortized to interest expense during the next twelve months.
Refer to Note 2, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the years ended December 31,
As of December 31, 2015 and December 31, 2014, no commodity or interest rate derivatives were designated as cash flow hedges.
2015 and 2014.
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, 2015 and December 31, 2014, no fixed-for-floating interest
rate swap agreements were outstanding.
Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $20 million
and $32 million as of December 31, 2015 and December 31, 2014, respectively. During the next twelve months, approximately $10
million of unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term
debt totaled approximately $12 million during the years ended December 31, 2015 and 2014.
As of December 31, 2015 and December 31, 2014, 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, 2015, FirstEnergy's net asset position under commodity derivative contracts was $97 million, which related to
FES positions. Under these commodity derivative contracts, FES posted $26 million of collateral. Certain commodity derivative
contracts include credit risk related contingent features that would require FES to post $3 million of additional collateral if the credit
rating for its debt were to fall below investment grade.
Based on derivative contracts held as of December 31, 2015, an increase in commodity prices of 10% would decrease net income by
approximately $30 million during the next twelve months.
Interest Rate Swaps
NUGs
FTRs
As of December 31, 2015, FirstEnergy's net liability position under NUG contracts was $136 million representing contracts held at
JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted
to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment
and do not impact earnings.
As of December 31, 2015, FirstEnergy's and FES' net liability position under FTRs was $5 million and $6 million, respectively and
FES posted $6 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 an RTO that have load serving
obligations and through the direct allocation of FTRs from PJM. PJM has a rule that allows directly allocated FTRs to be granted to
LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of
FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the
ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.
The held-to-maturity debt securities contractually mature by June 30, 2017. Investments in employee benefit trusts and equity method
investments totaling $255 million as of December 31, 2015 and $626 million as of December 31, 2014, 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 and other long-term obligations, excluding capital lease obligations and net unamortized
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 $42 million and $50 million as of December 31, 2015 and
December 31, 2014, respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to
be amortized to interest expense during the next twelve months.
Refer to Note 2, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the years ended December 31,
2015 and 2014.
premiums and discounts:
As of December 31, 2015 and December 31, 2014, no commodity or interest rate derivatives were designated as cash flow hedges.
December 31, 2015
December 31, 2014
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
(In millions)
FirstEnergy
FES
$
20,244 $
3,027
21,519 $
3,121
19,828 $
3,097
21,733
3,241
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 and its subsidiaries. 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, 2015 and December 31, 2014.
10. 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.
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, 2015 and December 31, 2014, no fixed-for-floating interest
rate swap agreements were outstanding.
Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $20 million
and $32 million as of December 31, 2015 and December 31, 2014, respectively. During the next twelve months, approximately $10
million of unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term
debt totaled approximately $12 million during the years ended December 31, 2015 and 2014.
As of December 31, 2015 and December 31, 2014, 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, 2015, FirstEnergy's net asset position under commodity derivative contracts was $97 million, which related to
FES positions. Under these commodity derivative contracts, FES posted $26 million of collateral. Certain commodity derivative
contracts include credit risk related contingent features that would require FES to post $3 million of additional collateral if the credit
rating for its debt were to fall below investment grade.
Based on derivative contracts held as of December 31, 2015, an increase in commodity prices of 10% would decrease net income by
approximately $30 million during the next twelve months.
• 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
Interest Rate Swaps
• Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in
As of December 31, 2015 and 2014, no interest rate swaps were outstanding.
hedged is amortized into earnings.
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
$11 million and $8 million as of December 31, 2015 and December 31, 2014, respectively. Since the forecasted transactions remain
probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $1 million
of net unamortized losses is expected to be amortized to income during the next twelve months.
NUGs
As of December 31, 2015, FirstEnergy's net liability position under NUG contracts was $136 million representing contracts held at
JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted
to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment
and do not impact earnings.
FTRs
As of December 31, 2015, FirstEnergy's and FES' net liability position under FTRs was $5 million and $6 million, respectively and
FES posted $6 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 an RTO that have load serving
obligations and through the direct allocation of FTRs from PJM. PJM has a rule that allows directly allocated FTRs to be granted to
LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of
FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the
ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.
104
105
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.
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,
2015
December 31,
2014
(In millions)
Fair Value
December 31,
2015
December 31,
2014
(In millions)
Current Assets -
Derivatives
Commodity Contracts $
FTRs
Deferred Charges and
Other Assets - Other
Commodity Contracts
FTRs
NUGs(1)
Derivative Assets
$
150 $
7
157
78
1
1
80
237 $
Current Liabilities -
Derivatives
121 Commodity Contracts
38
159
FTRs
$
Noncurrent Liabilities -
Adverse Power Contract
Liability
(94 ) $
(12 )
(106 )
(154 )
(13 )
(167 )
NUGs(1)
Noncurrent Liabilities -
Other
51
1 Commodity Contracts
2
54
213 Derivative Liabilities
FTRs
(137 )
(153 )
(37 )
(1 )
(175 )
(281 ) $
(13 )
(1 )
(167 )
(334 )
$
(1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
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:
106
107
December 31, 2015
Fair Value
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
(In millions)
Amounts Not Offset in Consolidated
Balance Sheet
Derivative Assets
Commodity contracts
FTRs
NUG contracts
Derivative Liabilities
Commodity contracts
FTRs
NUG contracts
Derivative Assets
Commodity contracts
FTRs
NUG contracts
Derivative Liabilities
Commodity contracts
FTRs
NUG contracts
$
$
$
$
$
$
$
$
228 $
8
1
237 $
(131 ) $
(13 )
(137 )
(281 ) $
172 $
39
2
213 $
(167 ) $
(14 )
(153 )
(334 ) $
(125 ) $
(8 )
—
(133 ) $
125 $
8
—
133 $
(126 ) $
(14 )
—
(140 ) $
126 $
14
—
140 $
— $
—
—
— $
3 $
5
—
8 $
103
—
1
104
(3 )
—
(137 )
(140 )
— $
—
—
— $
35 $
—
—
35 $
46
25
2
73
(6 )
—
(153 )
(159 )
December 31, 2014
Fair Value
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
(In millions)
Amounts Not Offset in Consolidated
Balance Sheet
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of
December 31, 2015:
Power Contracts
FTRs
NUGs
Natural Gas
Purchases
Sales
Net
(In millions)
16
29
4
83
49
—
—
—
Units
MWH
MWH
MWH
mmBTU
(33 )
29
4
83
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.
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,
December 31,
2015
2014
(In millions)
Fair Value
December 31,
December 31,
2015
2014
(In millions)
Current Assets -
Derivatives
Commodity Contracts $
FTRs
Current Liabilities -
Derivatives
121 Commodity Contracts
$
150 $
7
157
38
159
FTRs
(94 ) $
(12 )
(106 )
(154 )
(13 )
(167 )
Deferred Charges and
Other Assets - Other
Commodity Contracts
FTRs
NUGs(1)
Noncurrent Liabilities -
Adverse Power Contract
Liability
NUGs(1)
Noncurrent Liabilities -
51
Other
1 Commodity Contracts
2
54
FTRs
78
1
1
80
(137 )
(153 )
(37 )
(1 )
(175 )
(281 ) $
(13 )
(1 )
(167 )
(334 )
Derivative Assets
$
237 $
213 Derivative Liabilities
$
(1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
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, 2015
Fair Value
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
Amounts Not Offset in Consolidated
Balance Sheet
Derivative Assets
Commodity contracts
FTRs
NUG contracts
Derivative Liabilities
Commodity contracts
FTRs
NUG contracts
$
$
$
$
228 $
8
1
237 $
(131 ) $
(13 )
(137 )
(281 ) $
(In millions)
(125 ) $
(8 )
—
(133 ) $
125 $
8
—
133 $
— $
—
—
— $
3 $
5
—
8 $
103
—
1
104
(3 )
—
(137 )
(140 )
December 31, 2014
Fair Value
Derivative
Instruments
Cash Collateral
(Received)/Pledged
Net Fair
Value
Amounts Not Offset in Consolidated
Balance Sheet
Derivative Assets
Commodity contracts
FTRs
NUG contracts
Derivative Liabilities
Commodity contracts
FTRs
NUG contracts
$
$
$
$
172 $
39
2
213 $
(167 ) $
(14 )
(153 )
(334 ) $
(In millions)
(126 ) $
(14 )
—
(140 ) $
126 $
14
—
140 $
— $
—
—
— $
35 $
—
—
35 $
46
25
2
73
(6 )
—
(153 )
(159 )
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of
December 31, 2015:
Power Contracts
FTRs
NUGs
Natural Gas
Purchases
Sales
Net
(In millions)
16
29
4
83
49
—
—
—
Units
MWH
MWH
MWH
mmBTU
(33 )
29
4
83
106
107
The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during 2015
and 2014 are summarized in the following tables:
The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory
accounting during 2015 and 2014. Changes in the value of these contracts are deferred for future recovery from (or credit to)
customers:
Year Ended December 31,
Commodity
Contracts
FTRs
Total
(In millions)
Unrealized Gain (Loss) Recognized in:
Other Operating Expense(1)
Realized Gain (Loss) Reclassified to:
Revenues(2)
Purchased Power Expense(3)
Other Operating Expense(4)
Fuel Expense
2015
$
$
93 $
(20 ) $
73
111 $
(130 )
—
(34 )
50 $
—
(49 )
—
161
(130 )
(49 )
(34 )
(1) Includes $93 million for commodity contracts and ($19) million for FTRs associated with FES.
(2) Includes $111 million for commodity contracts and $49 million for FTRs associated with FES.
(3) Includes ($130) million for commodity contracts associated with FES.
(4) Includes ($49) million for FTRs associated with FES.
2014
Unrealized Gain (Loss) Recognized in:
Other Operating Expense(5)
Realized Gain (Loss) Reclassified to:
Revenues(6)
Purchased Power Expense(7)
Other Operating Expense(8)
Fuel Expense
Interest Expense
Year Ended December 31,
Commodity
Contracts
FTRs
Interest
Rate Swaps
Total
(In millions)
$
$
(86 ) $
22 $
— $
(64 )
(6 ) $
365
—
(6 )
—
68 $
—
(44 )
—
—
— $
—
—
—
14
62
365
(44 )
(6 )
14
Derivatives Not in a Hedging Relationship with
Regulatory Offset
Outstanding net asset (liability) as of January 1, 2015
$
(151 ) $
Unrealized loss
Purchases
Settlements
Unrealized gain (loss)
Purchases
Settlements
Outstanding net asset (liability) as of December 31, 2015
Outstanding net liability as of January 1, 2014
Year Ended December 31,
NUGs
Total
Regulated
FTRs
(In millions)
$
$
(47 )
—
62
(136 ) $
(202 ) $
(1 )
—
52
11 $
(9 )
12
(13 )
1 $
— $
13
11
(13 )
(140 )
(56 )
12
49
(135 )
(202 )
12
11
39
Outstanding net asset (liability) as of December 31, 2014
$
(151 ) $
11 $
(140 )
11. CAPITALIZATION
COMMON STOCK
Retained Earnings and Dividends
As of December 31, 2015, FirstEnergy’s unrestricted retained earnings were $2.3 billion. Dividends declared in 2015 and 2014 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, 2016 the Board of Directors declared a quarterly dividend
of $0.36 per share to be paid in the first quarter of 2016.
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, 2015.
(5) Includes ($86) million for commodity contracts and $21 million for FTRs associated with FES.
(6) Includes ($6) million for commodity contracts and $67 million for FTRs associated with FES.
(7) Realized losses on financially settled wholesale sales contracts of $252 million resulting from higher market prices were netted in purchased
power. Includes $365 million for commodity contracts associated with FES.
(8) Includes ($43) million for FTRs associated with FES.
Stock Issuance
In each of 2015 and 2014, FE issued approximately 2.5 million shares of common stock to registered shareholders and its employees
and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans.
108
109
The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during 2015
and 2014 are summarized in the following tables:
The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory
accounting during 2015 and 2014. Changes in the value of these contracts are deferred for future recovery from (or credit to)
customers:
Year Ended December 31,
Commodity
Contracts
FTRs
Total
(In millions)
Unrealized Gain (Loss) Recognized in:
Other Operating Expense(1)
Realized Gain (Loss) Reclassified to:
Revenues(2)
Purchased Power Expense(3)
Other Operating Expense(4)
Fuel Expense
2015
$
$
93 $
(20 ) $
73
111 $
50 $
(130 )
—
(34 )
—
(49 )
—
161
(130 )
(49 )
(34 )
(1) Includes $93 million for commodity contracts and ($19) million for FTRs associated with FES.
(2) Includes $111 million for commodity contracts and $49 million for FTRs associated with FES.
(3) Includes ($130) million for commodity contracts associated with FES.
(4) Includes ($49) million for FTRs associated with FES.
2014
Unrealized Gain (Loss) Recognized in:
Other Operating Expense(5)
Realized Gain (Loss) Reclassified to:
Revenues(6)
Purchased Power Expense(7)
Other Operating Expense(8)
Fuel Expense
Interest Expense
Year Ended December 31,
Commodity
Contracts
FTRs
Interest
Rate Swaps
Total
(In millions)
$
$
(86 ) $
22 $
— $
(64 )
(6 ) $
365
—
(6 )
—
—
(44 )
—
—
68 $
— $
—
—
—
14
62
365
(44 )
(6 )
14
(5) Includes ($86) million for commodity contracts and $21 million for FTRs associated with FES.
(6) Includes ($6) million for commodity contracts and $67 million for FTRs associated with FES.
(7) Realized losses on financially settled wholesale sales contracts of $252 million resulting from higher market prices were netted in purchased
power. Includes $365 million for commodity contracts associated with FES.
(8) Includes ($43) million for FTRs associated with FES.
Derivatives Not in a Hedging Relationship with
Regulatory Offset
NUGs
Year Ended December 31,
Regulated
FTRs
(In millions)
Total
Outstanding net asset (liability) as of January 1, 2015
Unrealized loss
Purchases
Settlements
Outstanding net asset (liability) as of December 31, 2015
Outstanding net liability as of January 1, 2014
Unrealized gain (loss)
Purchases
Settlements
Outstanding net asset (liability) as of December 31, 2014
$
$
$
$
(151 ) $
(47 )
—
62
(136 ) $
(202 ) $
(1 )
—
52
(151 ) $
11 $
(9 )
12
(13 )
1 $
— $
13
11
(13 )
11 $
(140 )
(56 )
12
49
(135 )
(202 )
12
11
39
(140 )
11. CAPITALIZATION
COMMON STOCK
Retained Earnings and Dividends
As of December 31, 2015, FirstEnergy’s unrestricted retained earnings were $2.3 billion. Dividends declared in 2015 and 2014 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, 2016 the Board of Directors declared a quarterly dividend
of $0.36 per share to be paid in the first quarter of 2016.
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, 2015.
Stock Issuance
In each of 2015 and 2014, FE issued approximately 2.5 million shares of common stock to registered shareholders and its employees
and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans.
108
109
PREFERRED AND PREFERENCE STOCK
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2015, as follows:
The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31,
Preferred Stock
Preference Stock
Shares
Authorized
Par Value
Shares
Authorized
Par Value
2015 and 2014:
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, 2015, and 2014, there were no preferred or preference shares outstanding.
Total long-term debt and other long-term obligations
$
19,192 $
19,176
(Dollar amounts in millions)
Maturity Date
Interest Rate
2015
2014
As of December 31, 2015
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 fair value adjustments
Currently payable long-term debt
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
Currently payable long-term debt
2016 - 2045
3.340% - 9.740%
$
2016 - 2037
0.679% - 12.000%
2017 - 2017
3.500% - 3.500%
2016 - 2045
2.150% - 7.700%
2017 - 2020
0.010% - 2.180%
2016 - 2018
5.625% - 12.000% $
2017 - 2017
3.500% - 3.500%
340 $
2
2016 - 2039
2.150% - 6.800%
2017 - 2017
0.010% - 0.010%
3,269 $
2,096
2
2,098
13,580
1,292
14,872
132
(18 )
5
(1,166 )
3,190
2,247
—
2,247
13,078
1,292
14,370
160
(8 )
21
(804 )
342
2,593
92
2,685
13
(1 )
(512 )
437
—
437
2,568
92
2,660
18
(1 )
(506 )
2,608
Total long-term debt and other long-term obligations
$
2,527 $
During the second quarter of 2015, FE refinanced a $200 million variable interest term loan, maturing on December 31, 2016 with a
new $200 million variable interest term loan maturing on May 29, 2020.
On July 1, 2015, FG and NG remarketed approximately $43 million and $296 million, respectively, of PCRBs. The PCRBs were
remarketed with fixed interest rates ranging from 3.125% to 4.00% and mandatory put dates ranging from July 2, 2018 to July 1,
2021.
In August 2015, JCP&L issued $250 million of 4.30% senior notes due January 2026. The proceeds received from the issuance of the
senior notes were used to repay a portion of JCP&L’s short-term borrowings under the FirstEnergy regulated companies' money pool
and an external revolving credit facility.
Also, in the second quarter of 2015, WP agreed to sell $150 million of new 4.45% FMBs due September 2045 and PE agreed to sell
$145 million of new 4.47% FMBs due August 2045. The transactions closed on September 17, 2015 and August 17, 2015,
respectively. The proceeds resulting from the issuance of the WP FMBs were used to repay WP’s borrowings under the FirstEnergy
regulated companies' money pool and for other general corporate purposes. The proceeds resulting from the issuance of the PE
FMBs were used to repay PE’s $145 million 5.125% FMBs that matured on August 15, 2015.
In October 2015, TrAIL issued $75 million of 3.76% senior notes due May 2025. The proceeds resulting from the issuance of the
senior notes were used: (i) to fund capital expenditures, including with respect to TrAIL's transmission expansion plans;; and (ii) for
working capital needs and other general business purposes.
Additionally, in October 2015, ATSI issued in total $150 million of senior notes: $75 million of 4.00% senior notes due April 2026 and
$75 million of 5.23% senior notes due October 2045. The proceeds resulting from the issuance of the senior notes were used: (i) to
110
111
PREFERRED AND PREFERENCE STOCK
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2015, as follows:
The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31,
2015 and 2014:
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, 2015
Maturity Date
Interest Rate
As of December 31
2014
2015
2016 - 2045
2016 - 2037
2017 - 2017
3.340% - 9.740%
0.679% - 12.000%
3.500% - 3.500%
$
2016 - 2045
2017 - 2020
2.150% - 7.700%
0.010% - 2.180%
(Dollar amounts in millions)
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 fair value adjustments
Currently payable long-term debt
As of December 31, 2015, and 2014, there were no preferred or preference shares outstanding.
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
Currently payable long-term debt
2016 - 2018
2017 - 2017
5.625% - 12.000% $
3.500% - 3.500%
2016 - 2039
2017 - 2017
2.150% - 6.800%
0.010% - 0.010%
Total long-term debt and other long-term obligations
$
3,269 $
2,096
2
2,098
13,580
1,292
14,872
132
(18 )
5
(1,166 )
19,192 $
340 $
2
342
2,593
92
2,685
13
(1 )
(512 )
2,527 $
3,190
2,247
—
2,247
13,078
1,292
14,370
160
(8 )
21
(804 )
19,176
437
—
437
2,568
92
2,660
18
(1 )
(506 )
2,608
During the second quarter of 2015, FE refinanced a $200 million variable interest term loan, maturing on December 31, 2016 with a
new $200 million variable interest term loan maturing on May 29, 2020.
On July 1, 2015, FG and NG remarketed approximately $43 million and $296 million, respectively, of PCRBs. The PCRBs were
remarketed with fixed interest rates ranging from 3.125% to 4.00% and mandatory put dates ranging from July 2, 2018 to July 1,
2021.
In August 2015, JCP&L issued $250 million of 4.30% senior notes due January 2026. The proceeds received from the issuance of the
senior notes were used to repay a portion of JCP&L’s short-term borrowings under the FirstEnergy regulated companies' money pool
and an external revolving credit facility.
Also, in the second quarter of 2015, WP agreed to sell $150 million of new 4.45% FMBs due September 2045 and PE agreed to sell
$145 million of new 4.47% FMBs due August 2045. The transactions closed on September 17, 2015 and August 17, 2015,
respectively. The proceeds resulting from the issuance of the WP FMBs were used to repay WP’s borrowings under the FirstEnergy
regulated companies' money pool and for other general corporate purposes. The proceeds resulting from the issuance of the PE
FMBs were used to repay PE’s $145 million 5.125% FMBs that matured on August 15, 2015.
In October 2015, TrAIL issued $75 million of 3.76% senior notes due May 2025. The proceeds resulting from the issuance of the
senior notes were used: (i) to fund capital expenditures, including with respect to TrAIL's transmission expansion plans;; and (ii) for
working capital needs and other general business purposes.
Additionally, in October 2015, ATSI issued in total $150 million of senior notes: $75 million of 4.00% senior notes due April 2026 and
$75 million of 5.23% senior notes due October 2045. The proceeds resulting from the issuance of the senior notes were used: (i) to
110
111
fund capital expenditures, including with respect to ATSI's transmission expansion plans;; (ii) for working capital needs and other
general business purposes;; and (iii) to repay borrowings under the FirstEnergy regulated companies' money pool.
The following table classifies the outstanding fixed rate PCRBs and variable rate 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.
See Note 6, 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, 2015 and 2014, $429 million and $450 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, 2015 and 2014, $128 million and $168
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, 2015 and 2014, $362 million and $386 million of the phase-in recovery bonds were
outstanding, respectively.
See Note 8, 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, 2015, the sinking fund
requirement for all FMBs issued under the various mortgage indentures amounted to payments of $3 million in 2015, all of which
relate to Penn. Penn expects to meet its 2016 annual sinking fund requirement with a replacement credit under its mortgage
indenture.
As of December 31, 2015, FirstEnergy’s currently payable long-term debt included approximately $92 million of FES variable interest
rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the
PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase
price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay
LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to
honor its LOC for any reason, must itself pay the purchase price.
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, 2015. 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
2016
2017
2018
2019
2020
FirstEnergy
FES
$
(In millions)
1,039 $
1,733
1,702
2,268
1,231
414
257
516
322
667
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.
The amounts and annual fees for PCRB-related LOCs for FirstEnergy and FES as of December 31, 2015, are as follows:
Year
FirstEnergy
FES
$
(In millions)
391 $
222
375
232
490
391
222
375
232
490
2016
2017
2018
2019
2020
Aggregate LOC
Amount (1)
(In millions)
Annual Fees
FirstEnergy
$
FES
93
93
1.25%
1.25%
(1)
Includes approximately $1 million of applicable interest
coverage.
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, 2015, 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 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.
112
113
fund capital expenditures, including with respect to ATSI's transmission expansion plans;; (ii) for working capital needs and other
general business purposes;; and (iii) to repay borrowings under the FirstEnergy regulated companies' money pool.
The following table classifies the outstanding fixed rate PCRBs and variable rate 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.
See Note 6, 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, 2015 and 2014, $429 million and $450 million of
environmental control bonds were outstanding, respectively.
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, 2015 and 2014, $128 million and $168
million of the transition bonds were outstanding, respectively.
Transition Bonds
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, 2015 and 2014, $362 million and $386 million of the phase-in recovery bonds were
outstanding, respectively.
See Note 8, 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, 2015, the sinking fund
requirement for all FMBs issued under the various mortgage indentures amounted to payments of $3 million in 2015, all of which
relate to Penn. Penn expects to meet its 2016 annual sinking fund requirement with a replacement credit under its mortgage
indenture.
As of December 31, 2015, FirstEnergy’s currently payable long-term debt included approximately $92 million of FES variable interest
rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the
PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase
price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay
LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to
honor its LOC for any reason, must itself pay the purchase price.
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, 2015. 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
2016
2017
2018
2019
2020
FirstEnergy
FES
(In millions)
1,039 $
$
1,733
1,702
2,268
1,231
414
257
516
322
667
Year
FirstEnergy
FES
$
2016
2017
2018
2019
2020
(In millions)
391 $
222
375
232
490
391
222
375
232
490
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.
The amounts and annual fees for PCRB-related LOCs for FirstEnergy and FES as of December 31, 2015, are as follows:
Aggregate LOC
Amount (1)
(In millions)
Annual Fees
FirstEnergy
$
FES
93
93
1.25%
1.25%
(1)
Includes approximately $1 million of applicable interest
coverage.
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, 2015, 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 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.
112
113
12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of
$6.0 billion (Facilities), which are available until March 31, 2019. FirstEnergy had $1,708 million and $1,799 million of short-term
borrowings as of December 31, 2015 and 2014, respectively. FirstEnergy’s available liquidity under the Facilities as of January 31,
2016 was as follows:
Borrower(s)
Type
Maturity
Commitment
Available
Liquidity
FirstEnergy(1)
FES / AE Supply
FET(2)
Revolving
Revolving
Revolving
March 2019 $
March 2019
March 2019
Subtotal $
Cash
Total $
(In millions)
3,500 $
1,500
1,000
6,000 $
—
6,000 $
1,595
1,442
1,000
4,037
63
4,100
(1)
(2)
FE and the Utilities
Includes FET, ATSI and TrAIL as subsidiary borrowers
Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days
from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains
financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio (as defined under each of the
Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
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, 2015:
Borrower
FE
FES
AE Supply
FET
OE
CEI
TE
JCP&L
ME
PN
WP
MP
PE
ATSI
Penn
TrAIL
Revolving
Credit Facility
Sub-Limits
Regulatory and
Other Short-Term
Debt Limitations
(In millions)
$
3,500
1,500
1,000
1,000
500
500
500
600
300
300
200
500
150
500
50
400
$
— (1)
— (2)
— (2)
— (1)
500 (3)
500 (3)
500 (3)
500 (3)
500 (3)
300 (3)
200 (3)
500 (3)
150 (3)
500 (3)
100 (3)
400 (3)
(1)
(2)
(3)
No limitations.
No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.
Excluding amounts which may be borrowed under the regulated companies' money pool.
The entire amount of the FES/AE Supply Facility, $600 million of the FE Facility and $225 million of the FET Facility, subject to each
borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year
114
115
from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the
Facilities and against the applicable borrower’s borrowing sub-limit.
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, 2015, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants under the
respective Facilities.
Term Loans
FE has a $1 billion variable rate term loan credit agreement with a maturity date of March 31, 2019. The initial borrowing under the
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. The proceeds from this term loan reduced borrowings under the FE Facility.
Additionally, FE has a $200 million variable rate term loan with a maturity date of May 29, 2020. Each of the term loans contains
covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same
consolidated debt to total capitalization ratio requirement.
As of December 31, 2015, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants under
each of these term loans.
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 2015 was 0.84% per annum for the regulated companies’ money pool
and 1.64% per annum for 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, 2015 and 2014, were as follows:
FirstEnergy
FES
2015
2014
2.16 %
— %
1.96 %
3.34 %
13. 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. 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, 2015 and 2014 were as follows:
FirstEnergy
FES
$
$
2015
2014
(In millions)
2,282 $
1,327 $
2,341
1,365
12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of
$6.0 billion (Facilities), which are available until March 31, 2019. FirstEnergy had $1,708 million and $1,799 million of short-term
borrowings as of December 31, 2015 and 2014, respectively. FirstEnergy’s available liquidity under the Facilities as of January 31,
2016 was as follows:
Borrower(s)
Type
Maturity
Commitment
FirstEnergy(1)
FES / AE Supply
FET(2)
Revolving
Revolving
Revolving
Available
Liquidity
(In millions)
3,500 $
1,500
1,000
6,000 $
—
6,000 $
1,595
1,442
1,000
4,037
63
4,100
March 2019 $
March 2019
March 2019
Subtotal $
Cash
Total $
FE and the Utilities
(1)
(2)
Includes FET, ATSI and TrAIL as subsidiary borrowers
Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days
from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains
financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio (as defined under each of the
Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
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, 2015:
Borrower
AE Supply
JCP&L
FE
FES
FET
OE
CEI
TE
ME
PN
WP
MP
PE
ATSI
Penn
TrAIL
Revolving
Credit Facility
Sub-Limits
Regulatory and
Other Short-Term
Debt Limitations
(In millions)
$
$
3,500
1,500
1,000
1,000
500
500
500
600
300
300
200
500
150
500
50
400
— (1)
— (2)
— (2)
— (1)
500 (3)
500 (3)
500 (3)
500 (3)
500 (3)
300 (3)
200 (3)
500 (3)
150 (3)
500 (3)
100 (3)
400 (3)
No limitations.
(1)
(2)
(3)
No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.
Excluding amounts which may be borrowed under the regulated companies' money pool.
The entire amount of the FES/AE Supply Facility, $600 million of the FE Facility and $225 million of the FET Facility, subject to each
borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year
from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the
Facilities and against the applicable borrower’s borrowing sub-limit.
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, 2015, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants under the
respective Facilities.
Term Loans
FE has a $1 billion variable rate term loan credit agreement with a maturity date of March 31, 2019. The initial borrowing under the
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. The proceeds from this term loan reduced borrowings under the FE Facility.
Additionally, FE has a $200 million variable rate term loan with a maturity date of May 29, 2020. Each of the term loans contains
covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same
consolidated debt to total capitalization ratio requirement.
As of December 31, 2015, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants under
each of these term loans.
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 2015 was 0.84% per annum for the regulated companies’ money pool
and 1.64% per annum for 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, 2015 and 2014, were as follows:
FirstEnergy
FES
2015
2014
2.16 %
— %
1.96 %
3.34 %
13. 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. 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, 2015 and 2014 were as follows:
FirstEnergy
FES
$
$
2015
2014
(In millions)
2,282 $
1,327 $
2,341
1,365
114
115
The following table summarizes the changes to the ARO balances during 2015 and 2014:
ARO Reconciliation
FirstEnergy
FES
Balance, January 1, 2014
Liabilities settled
Accretion
Revisions in estimated cash flows
Balance, December 31, 2014
Liabilities settled
Accretion
Revisions in estimated cash flows
Balance, December 31, 2015
$
$
$
(In millions)
1,678 $
(9 )
113
(395 )
1,387 $
(13 )
92
(56 )
1,410 $
1,015
(7 )
66
(233 )
841
(8 )
55
(57 )
831
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.
During 2014, based on studies by a third-party to reassess the estimated costs of decommissioning certain nuclear generating
facilities, FE decreased its ARO by $395 million ($233 million at FES) of which $133 million was credited against a regulatory asset
associated with nuclear decommissioning and spent fuel disposal costs for TMI-2. The decrease in the ARO primarily resulted from
an extension in the number of years in which decommissioning activities are estimated to occur at Davis-Besse, Perry, TMI-2 and
Beaver Valley Units 1 and 2.
14. 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 by 10%
and reduce electricity demand by 15%, in each case by 2015, 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. The costs of the 2015-
2017 plan are expected to be approximately $66 million for that three-year period, of which $19 million was incurred through
December 2015. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond,
beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%.
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 January 28, 2016, PE filed a request to increase plan spending by $2
million in order to reach the new goals for 2017 set in the July 16, 2015 order.
On February 27, 2013, the MDPSC issued an order (the February 27 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. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to
propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs
customer information. 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 27 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 27 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. The Staff of the MDPSC also recommended 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 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 March 3, 2014, pursuant to the MDPSC's regulations, PE filed its recommendations for SAIDI and SAIFI standards to apply during
the period 2016-2019. The MDPSC directed the Staff of the MDPSC to file an analysis and recommendations with respect to the
proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which the Staff of the MDPSC recommended. The
Staff of the MDPSC made its filing on July 10, 2015, and recommended that PE be required to improve its SAIDI results by
approximately 20% by 2019. The MDPSC held a hearing on the Staff's analysis and recommendations on September 1-2, 2015, and
approved PE's revised proposal for an improvement of 8.6% in its SAIDI standard by 2019 and maintained its SAIFI standard at 2015
levels. The proposed regulations incorporating the new SAIDI and SAIFI standards were approved as final in December 2015.
On April 1, 2015, PE filed its annual report on its performance relative to various service reliability standards set forth in the MDPSC’s
regulations. The MDPSC conducted hearings on the reports filed by PE and the other electric utilities in Maryland on August 24, 2015
and subsequently closed its 2014 service reliability review.
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.
On March 26, 2015, the NJBPU entered final orders which together provided an overall reduction in JCP&L's annual revenues of
approximately $34 million, effective April 1, 2015. The final order in JCP&L's base rate case proceeding directed an annual base rate
revenue reduction of approximately $115 million, including recovery of 2011 storm costs and the application of the NJBPU's modified
CTA policy approved in the generic CTA proceeding referred to below. Additionally, the final order in the generic proceeding
established to review JCP&L's major storm events of 2011 and 2012 approved the recovery of 2012 storm costs of $580 million
resulting in an increase in annual revenues of approximately $81 million. JCP&L is required to file another base rate case no later
than April 1, 2017. The NJBPU also directed that certain studies be completed. On July 22, 2015, the NJBPU approved the NJBPU
staff's recommendation to implement such studies, which will include operational and financial components and is expected to take
approximately one year to complete.
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 has filed to participate as a respondent in
that proceeding. Briefing has been completed, and oral argument has not yet been scheduled.
On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On
January 8, 2016, the NJBPU President issued an Order granting Rate Counsel’s Motion on the legal issue of whether MAIT can be
designated as a public utility. The procedural schedule has been suspended until a decision is made on this issue. See Transfer of
Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
OHIO
prior ESP;;
The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include:
• A base distribution rate freeze through May 31, 2016;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• Economic development and assistance to low-income customers for the two-year plan period at levels established in the
• A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral
wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);;
• A requirement to provide power to non-shopping customers at a market-based price set through an auction process;;
116
117
The following table summarizes the changes to the ARO balances during 2015 and 2014:
ARO Reconciliation
FirstEnergy
FES
Balance, January 1, 2014
Liabilities settled
Accretion
Revisions in estimated cash flows
Balance, December 31, 2014
Liabilities settled
Accretion
Revisions in estimated cash flows
Balance, December 31, 2015
$
$
$
(In millions)
1,678 $
(9 )
113
(395 )
1,387 $
(13 )
92
(56 )
1,410 $
1,015
(7 )
66
(233 )
841
(8 )
55
(57 )
831
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.
During 2014, based on studies by a third-party to reassess the estimated costs of decommissioning certain nuclear generating
facilities, FE decreased its ARO by $395 million ($233 million at FES) of which $133 million was credited against a regulatory asset
associated with nuclear decommissioning and spent fuel disposal costs for TMI-2. The decrease in the ARO primarily resulted from
an extension in the number of years in which decommissioning activities are estimated to occur at Davis-Besse, Perry, TMI-2 and
Beaver Valley Units 1 and 2.
14. 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 by 10%
and reduce electricity demand by 15%, in each case by 2015, 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. The costs of the 2015-
2017 plan are expected to be approximately $66 million for that three-year period, of which $19 million was incurred through
December 2015. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond,
beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%.
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 January 28, 2016, PE filed a request to increase plan spending by $2
million in order to reach the new goals for 2017 set in the July 16, 2015 order.
On February 27, 2013, the MDPSC issued an order (the February 27 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. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to
propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs
customer information. 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 27 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 27 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. The Staff of the MDPSC also recommended 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 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 March 3, 2014, pursuant to the MDPSC's regulations, PE filed its recommendations for SAIDI and SAIFI standards to apply during
the period 2016-2019. The MDPSC directed the Staff of the MDPSC to file an analysis and recommendations with respect to the
proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which the Staff of the MDPSC recommended. The
Staff of the MDPSC made its filing on July 10, 2015, and recommended that PE be required to improve its SAIDI results by
approximately 20% by 2019. The MDPSC held a hearing on the Staff's analysis and recommendations on September 1-2, 2015, and
approved PE's revised proposal for an improvement of 8.6% in its SAIDI standard by 2019 and maintained its SAIFI standard at 2015
levels. The proposed regulations incorporating the new SAIDI and SAIFI standards were approved as final in December 2015.
On April 1, 2015, PE filed its annual report on its performance relative to various service reliability standards set forth in the MDPSC’s
regulations. The MDPSC conducted hearings on the reports filed by PE and the other electric utilities in Maryland on August 24, 2015
and subsequently closed its 2014 service reliability review.
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.
On March 26, 2015, the NJBPU entered final orders which together provided an overall reduction in JCP&L's annual revenues of
approximately $34 million, effective April 1, 2015. The final order in JCP&L's base rate case proceeding directed an annual base rate
revenue reduction of approximately $115 million, including recovery of 2011 storm costs and the application of the NJBPU's modified
CTA policy approved in the generic CTA proceeding referred to below. Additionally, the final order in the generic proceeding
established to review JCP&L's major storm events of 2011 and 2012 approved the recovery of 2012 storm costs of $580 million
resulting in an increase in annual revenues of approximately $81 million. JCP&L is required to file another base rate case no later
than April 1, 2017. The NJBPU also directed that certain studies be completed. On July 22, 2015, the NJBPU approved the NJBPU
staff's recommendation to implement such studies, which will include operational and financial components and is expected to take
approximately one year to complete.
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 has filed to participate as a respondent in
that proceeding. Briefing has been completed, and oral argument has not yet been scheduled.
On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On
January 8, 2016, the NJBPU President issued an Order granting Rate Counsel’s Motion on the legal issue of whether MAIT can be
designated as a public utility. The procedural schedule has been suspended until a decision is made on this issue. See Transfer of
Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
OHIO
The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include:
• A base distribution rate freeze through May 31, 2016;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• Economic development and assistance to low-income customers for the two-year plan period at levels established in the
prior ESP;;
• A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral
wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);;
• A requirement to provide power to non-shopping customers at a market-based price set through an auction process;;
116
117
• Rider DCR that allows continued investment in the distribution system for the benefit of customers;;
• A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the
five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain
types of products totals $360 million, subject to the outcome of certain FERC proceedings;;
• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-
year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility
customers who do not switch to a competitive generation supplier;; and
• Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy
and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly
renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the
entire ESP period.
Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy
Council and the ELPC. The oral argument in this matter occurred on January 6, 2016.
The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's
Progress. The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and
recommendations on May 28, 2015, and June 4, 2015. The evidentiary hearing on the ESP IV commenced on August 31, 2015 and
concluded on October 29, 2015. On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and
Recommendation, which included PUCO Staff as a signatory party in addition to other signatories. The PUCO completed a hearing
on the Third Supplemental Stipulation and Recommendation in January 2016. Initial briefs are due on February 16, 2016 and reply
briefs are due on February 26, 2016. A final PUCO decision is expected in March 2016.
The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to
deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving
electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:
• An eight-year term (June 1, 2016 - May 31, 2024);;
• Contemplates continuing a base distribution rate freeze through May 31, 2024;;
• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the
price paid to FES through a proposed eight-year FERC-jurisdictional PPA for the output of the Sammis and Davis-Besse
plants and FES’ share of OVEC against the revenues received from selling such output into the PJM markets over the same
period, subject to the PUCO’s termination of Rider RRS charges/credits associated with any plants or units that may be sold
or transferred;;
• Continuing to provide power to non-shopping customers at a market-based price set through an auction process;;
• Continuing Rider DCR 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 that supports continued investment related to the distribution system for the benefit of customers;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers
as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;;
• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the
longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by
customers for certain types of products totals $360 million, including such costs from MISO along with such costs from PJM,
subject to the outcome of certain FERC proceedings;;
• Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new
renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;;
• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential
PENNSYLVANIA
customers;;
• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval;;
• A contribution of $3 million per year ($24 million over the eight year term) to fund energy conservation programs,
economic development and job retention in the Ohio Companies service territory;;
• Contributions of $2.4 million per year ($19 million over the eight year term) to fund a fuel-fund in each of the Ohio
Companies service territories to assist low-income customers;; and
• A contribution of $1 million per year ($8 million over the eight year term) to establish a Customary Advisory Council to
ensure preservation and growth of the competitive market in Ohio.
On January 27, 2016, certain parties filed a complaint at FERC against FES, OE, CEI, and TE that requests FERC review of the ESP
IV PPA under Section 205 of the FPA. In addition to such proceeding, parties have expressed an intention to challenge in the courts
and/or before FERC, the PPA or PUCO approval of the ESP IV, if approved. Management intends to vigorously defend against such
challenges.
Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans,
the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of
2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative
amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak
118
119
demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject
to legislative amendments to the peak demand reduction standards discussed below.
On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy
mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an
expedited process for review of utility proposed energy efficiency plans;; (ii) ensuring maximum credit for all of Ohio's Energy
Initiatives;; (iii) a switch from energy mandates to energy incentives;; and (iv) a declaration be made that the General Assembly may
determine energy policy of the state. No legislation has yet been introduced to change the standards described above.
On March 20, 2013, the PUCO approved the three-year energy efficiency portfolio plans for 2013-2015, originally estimated to cost
the Ohio Companies approximately $250 million over the three-year period, which is expected to be recovered in rates. Actual costs
may be lower for a number of reasons including the approval of the amended portfolio plan under SB310. On July 17, 2013, the
PUCO modified the plan to authorize the Ohio Companies to receive 20% of any revenues obtained from offering energy efficiency
and DR reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable
penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to
the extent that such costs or penalties are prudently incurred. ELPC and OCC filed applications for rehearing, which were granted for
the sole purpose of further consideration of the issue. On September 24, 2014, the Ohio Companies filed an amendment to their
portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the
plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio
plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters
specified in those applications.
On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013
Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the
PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss
the appeal, which is still pending. The matter has not been scheduled for oral argument.
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, subject to legislative amendments discussed above, 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.
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.
On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery
period, which would 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 proposed programs, the supply would
be provided by wholesale suppliers though 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 proposal includes modifications to the Pennsylvania Companies’ existing POR
programs in order to reduce the level of uncollectibles 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 are effective through May 31, 2016. Total
costs of these plans are expected to be approximately $234 million and recoverable through the Pennsylvania Companies'
• Rider DCR that allows continued investment in the distribution system for the benefit of customers;;
• A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the
five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain
types of products totals $360 million, subject to the outcome of certain FERC proceedings;;
• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-
year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility
customers who do not switch to a competitive generation supplier;; and
• Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy
and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly
renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the
entire ESP period.
Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy
Council and the ELPC. The oral argument in this matter occurred on January 6, 2016.
The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's
Progress. The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and
recommendations on May 28, 2015, and June 4, 2015. The evidentiary hearing on the ESP IV commenced on August 31, 2015 and
concluded on October 29, 2015. On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and
Recommendation, which included PUCO Staff as a signatory party in addition to other signatories. The PUCO completed a hearing
on the Third Supplemental Stipulation and Recommendation in January 2016. Initial briefs are due on February 16, 2016 and reply
briefs are due on February 26, 2016. A final PUCO decision is expected in March 2016.
The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to
deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving
electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:
• An eight-year term (June 1, 2016 - May 31, 2024);;
• Contemplates continuing a base distribution rate freeze through May 31, 2024;;
• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the
price paid to FES through a proposed eight-year FERC-jurisdictional PPA for the output of the Sammis and Davis-Besse
plants and FES’ share of OVEC against the revenues received from selling such output into the PJM markets over the same
period, subject to the PUCO’s termination of Rider RRS charges/credits associated with any plants or units that may be sold
or transferred;;
• Continuing to provide power to non-shopping customers at a market-based price set through an auction process;;
• Continuing Rider DCR 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 that supports continued investment related to the distribution system for the benefit of customers;;
• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;;
• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers
as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight;;
• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the
longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by
customers for certain types of products totals $360 million, including such costs from MISO along with such costs from PJM,
subject to the outcome of certain FERC proceedings;;
• Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new
renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;;
customers;;
• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval;;
• A contribution of $3 million per year ($24 million over the eight year term) to fund energy conservation programs,
economic development and job retention in the Ohio Companies service territory;;
• Contributions of $2.4 million per year ($19 million over the eight year term) to fund a fuel-fund in each of the Ohio
Companies service territories to assist low-income customers;; and
• A contribution of $1 million per year ($8 million over the eight year term) to establish a Customary Advisory Council to
ensure preservation and growth of the competitive market in Ohio.
On January 27, 2016, certain parties filed a complaint at FERC against FES, OE, CEI, and TE that requests FERC review of the ESP
IV PPA under Section 205 of the FPA. In addition to such proceeding, parties have expressed an intention to challenge in the courts
and/or before FERC, the PPA or PUCO approval of the ESP IV, if approved. Management intends to vigorously defend against such
challenges.
Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans,
the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of
2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative
amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak
demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject
to legislative amendments to the peak demand reduction standards discussed below.
On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy
mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an
expedited process for review of utility proposed energy efficiency plans;; (ii) ensuring maximum credit for all of Ohio's Energy
Initiatives;; (iii) a switch from energy mandates to energy incentives;; and (iv) a declaration be made that the General Assembly may
determine energy policy of the state. No legislation has yet been introduced to change the standards described above.
On March 20, 2013, the PUCO approved the three-year energy efficiency portfolio plans for 2013-2015, originally estimated to cost
the Ohio Companies approximately $250 million over the three-year period, which is expected to be recovered in rates. Actual costs
may be lower for a number of reasons including the approval of the amended portfolio plan under SB310. On July 17, 2013, the
PUCO modified the plan to authorize the Ohio Companies to receive 20% of any revenues obtained from offering energy efficiency
and DR reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable
penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to
the extent that such costs or penalties are prudently incurred. ELPC and OCC filed applications for rehearing, which were granted for
the sole purpose of further consideration of the issue. On September 24, 2014, the Ohio Companies filed an amendment to their
portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the
plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio
plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters
specified in those applications.
On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013
Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the
PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss
the appeal, which is still pending. The matter has not been scheduled for oral argument.
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, subject to legislative amendments discussed above, 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.
• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential
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.
On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery
period, which would 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 proposed programs, the supply would
be provided by wholesale suppliers though 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 proposal includes modifications to the Pennsylvania Companies’ existing POR
programs in order to reduce the level of uncollectibles 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 are effective through May 31, 2016. Total
costs of these plans are expected to be approximately $234 million and recoverable through the Pennsylvania Companies'
118
119
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 filed their Phase III EE&C
plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in
the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On
February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint
settlement that resolves all issues in the proceeding and is subject to PPUC approval.
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. These amounts include all qualifying distribution capital
additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania
Companies as discussed below. 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. The DSIC riders are expected to be effective July 1, 2016.
Each of the Pennsylvania Companies currently offer distribution rates under their respective Joint Petitions for Settlement approved
on April 9, 2015 by the PPUC, which, among other things, provided for a total increase in annual revenues for all Pennsylvania
Companies of $292.8 million, ($89.3 million for ME, $90.8 million for PN, $15.9 million for Penn and $96.8 million for WP), including
the recovery of $87.7 million of additional annual operating expenses, including costs associated with service reliability
enhancements to the distribution system, amortization of deferred storm costs and the remaining net book value of legacy meters,
assistance for providing service to low-income customers, and the creation of a storm reserve for each utility. Additionally, the
approved settlements include commitments to meet certain wait times for call centers and service reliability standards. The new rates
were effective May 3, 2015.
On July 16, 2013, the PPUC's Bureau of Audits initiated a focused management and operations audit of the Pennsylvania Companies
as required every eight years by statute. The PPUC issued a report on its findings and recommendations on February 12, 2015, at
which time the Pennsylvania Companies' associated implementation plan was also made public. In an order issued on March 30,
2015, the Pennsylvania Companies were directed to develop and file by May 29, 2015 a revised implementation plan regarding
certain of the operational topics addressed in the report, including addressing certain reliability matters. The Pennsylvania Companies
filed their revised implementation plan in compliance with this order. A final order adopting the plan, as revised, was entered on
November 5, 2015. The cost of compliance for the Pennsylvania Companies is currently expected to range from approximately $200
million to $230 million.
On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.
Evidentiary hearings are scheduled to commence before the PPUC on February 29, 2016. A final decision from the PPUC is expected
by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
WEST VIRGINIA
MP and PE currently operate under a Joint Stipulation and Agreement of Settlement approved by the WVPSC on February 3, 2015,
that provided for: a $15 million increase in annual base rate revenues effective February 25, 2015;; the implementation of a Vegetation
Management Surcharge to recover all costs related to both new and existing vegetation maintenance programs;; authority to establish
a regulatory asset for MATS investments placed into service in 2016 and 2017;; authority to defer, amortize and recover over a five-
year period through base rates approximately $46 million of storm restoration costs;; and elimination of the TTS for costs associated
with MP's acquisition of the Harrison plant in October 2013 and movement of those costs into base rates.
On August 14, 2015, MP and PE filed their annual ENEC case with the WVPSC proposing an approximate $165.1 million annual
increase in rates effective January 1, 2016 or before, which would be a 12.5% overall increase over existing rates. The original
proposed increase was comprised of a $97 million under-recovered balance as of June 30, 2015, a projected $23.7 million under-
recovery for the 2016 calendar year, and an actual under-recovered balance from MP and PE's TTS for Harrison Power Station of
$44.4 million. On September 10, 2015, MP and PE filed an amendment addressing the results of the recent PJM Transitional
Auctions for Capacity Performance, which resulted in a net decrease of $20.6 million from the initial requested increase to $144.5
million. A settlement was reached among all the parties increasing revenues $96.9 million and deferring other costs for recovery into
2017. The settlement was presented to the WVPSC on November 19, 2015, and a final order approving the settlement without
changes was issued on December 22, 2015, with rates effective on January 1, 2016.
On August 31, 2015, MP and PE filed with the WVPSC their biennial petition for reconciliation of the Vegetation Management
Program Surcharge and regular review of the program proposing an approximate $37.7 million annual increase in rates over a two
year period, which is a 2.8% overall increase over existing rates. The proposed increase was comprised of a $2.1 million under-
recovered balance as of June 30, 2015, a projected $23.9 million in under-recovery for the 2016/2017 rate effective period, and
recovery of previously authorized deferred vegetation management costs from April 14, 2014 through February 24, 2015 in the
amount of $49.9 million. A settlement was reached among all the parties increasing revenues $36.7 million annually for the 2016-
2017 two year rate recovery period, and was presented to the WVPSC on November 19, 2015. A final order approving the settlement
without changes was issued on December 21, 2015, with rates effective on January 1, 2016.
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, AE Supply, FG, FENOC, NG, 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
FirstEnergy 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 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 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 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
RFC.
flows.
FERC MATTERS
PJM Transmission Rates
PJM and its stakeholders have been debating the proper method to allocate costs for new 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. Settlement discussions
under a FERC-appointed settlement judge are ongoing.
In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent
“right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of
PJM’s RTEP process. FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether
FirstEnergy and the PJM transmission owners have a "right of first refusal" is now pending before the U.S. Court of Appeals for the
D.C. Circuit in an appeal of FERC's order approving PJM's Order No. 1000 compliance filing.
The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.
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. FirstEnergy's request for rehearing of FERC's order rejecting the settlement agreement remains
pending.
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 is pending at FERC. In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek
120
121
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 filed their Phase III EE&C
plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in
the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On
February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint
settlement that resolves all issues in the proceeding and is subject to PPUC approval.
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. These amounts include all qualifying distribution capital
additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania
Companies as discussed below. 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. The DSIC riders are expected to be effective July 1, 2016.
Each of the Pennsylvania Companies currently offer distribution rates under their respective Joint Petitions for Settlement approved
on April 9, 2015 by the PPUC, which, among other things, provided for a total increase in annual revenues for all Pennsylvania
Companies of $292.8 million, ($89.3 million for ME, $90.8 million for PN, $15.9 million for Penn and $96.8 million for WP), including
the recovery of $87.7 million of additional annual operating expenses, including costs associated with service reliability
enhancements to the distribution system, amortization of deferred storm costs and the remaining net book value of legacy meters,
assistance for providing service to low-income customers, and the creation of a storm reserve for each utility. Additionally, the
approved settlements include commitments to meet certain wait times for call centers and service reliability standards. The new rates
were effective May 3, 2015.
On July 16, 2013, the PPUC's Bureau of Audits initiated a focused management and operations audit of the Pennsylvania Companies
as required every eight years by statute. The PPUC issued a report on its findings and recommendations on February 12, 2015, at
which time the Pennsylvania Companies' associated implementation plan was also made public. In an order issued on March 30,
2015, the Pennsylvania Companies were directed to develop and file by May 29, 2015 a revised implementation plan regarding
certain of the operational topics addressed in the report, including addressing certain reliability matters. The Pennsylvania Companies
filed their revised implementation plan in compliance with this order. A final order adopting the plan, as revised, was entered on
November 5, 2015. The cost of compliance for the Pennsylvania Companies is currently expected to range from approximately $200
million to $230 million.
On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting
authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.
Evidentiary hearings are scheduled to commence before the PPUC on February 29, 2016. A final decision from the PPUC is expected
by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.
WEST VIRGINIA
MP and PE currently operate under a Joint Stipulation and Agreement of Settlement approved by the WVPSC on February 3, 2015,
that provided for: a $15 million increase in annual base rate revenues effective February 25, 2015;; the implementation of a Vegetation
Management Surcharge to recover all costs related to both new and existing vegetation maintenance programs;; authority to establish
a regulatory asset for MATS investments placed into service in 2016 and 2017;; authority to defer, amortize and recover over a five-
year period through base rates approximately $46 million of storm restoration costs;; and elimination of the TTS for costs associated
with MP's acquisition of the Harrison plant in October 2013 and movement of those costs into base rates.
On August 14, 2015, MP and PE filed their annual ENEC case with the WVPSC proposing an approximate $165.1 million annual
increase in rates effective January 1, 2016 or before, which would be a 12.5% overall increase over existing rates. The original
proposed increase was comprised of a $97 million under-recovered balance as of June 30, 2015, a projected $23.7 million under-
recovery for the 2016 calendar year, and an actual under-recovered balance from MP and PE's TTS for Harrison Power Station of
$44.4 million. On September 10, 2015, MP and PE filed an amendment addressing the results of the recent PJM Transitional
Auctions for Capacity Performance, which resulted in a net decrease of $20.6 million from the initial requested increase to $144.5
million. A settlement was reached among all the parties increasing revenues $96.9 million and deferring other costs for recovery into
2017. The settlement was presented to the WVPSC on November 19, 2015, and a final order approving the settlement without
changes was issued on December 22, 2015, with rates effective on January 1, 2016.
On August 31, 2015, MP and PE filed with the WVPSC their biennial petition for reconciliation of the Vegetation Management
Program Surcharge and regular review of the program proposing an approximate $37.7 million annual increase in rates over a two
year period, which is a 2.8% overall increase over existing rates. The proposed increase was comprised of a $2.1 million under-
recovered balance as of June 30, 2015, a projected $23.9 million in under-recovery for the 2016/2017 rate effective period, and
recovery of previously authorized deferred vegetation management costs from April 14, 2014 through February 24, 2015 in the
amount of $49.9 million. A settlement was reached among all the parties increasing revenues $36.7 million annually for the 2016-
2017 two year rate recovery period, and was presented to the WVPSC on November 19, 2015. A final order approving the settlement
without changes was issued on December 21, 2015, with rates effective on January 1, 2016.
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, AE Supply, FG, FENOC, NG, 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 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 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 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 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
PJM Transmission Rates
PJM and its stakeholders have been debating the proper method to allocate costs for new 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. Settlement discussions
under a FERC-appointed settlement judge are ongoing.
In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent
“right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of
PJM’s RTEP process. FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether
FirstEnergy and the PJM transmission owners have a "right of first refusal" is now pending before the U.S. Court of Appeals for the
D.C. Circuit in an appeal of FERC's order approving PJM's Order No. 1000 compliance filing.
The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.
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. FirstEnergy's request for rehearing of FERC's order rejecting the settlement agreement remains
pending.
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 is pending at FERC. In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek
120
121
recovery of these charges through its formula rate. On a related issue, FirstEnergy joined certain other PJM transmission owners in a
protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On January
22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any
limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent. Certain PJM
transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP
export charge on transactions into PJM was correct and should be re-affirmed on remand. The briefs and replies thereto are now
before FERC for consideration.
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.
2014 ATSI Formula Rate Filing
On October 31, 2014, ATSI filed a proposal with FERC to change the structure of its formula rate from an “historical looking”
approach, where transmission rates reflect actual costs for the prior year, to a “forward looking” approach, where transmission rates
would be based on the estimated costs for the coming year, with an annual true up. On December 31, 2014, FERC issued an order
accepting ATSI's filing effective January 1, 2015, subject to refund and the outcome of hearing and settlement proceedings. FERC
subsequently issued an order on October 29, 2015, accepting a settlement agreement on the forward-looking formula rate, subject to
minor compliance requirements. The settlement agreement provides for certain changes to ATSI's formula rate template and
protocols, and also changes ATSI's ROE from 12.38% to the following values: (i) 12.38% from January 1, 2015 through June 30,
2015;; (ii) 11.06% from July 1, 2015 through December 31, 2015;; and (iii) 10.38% from January 1, 2016, unless changed pursuant to
section 205 or 206 of the FPA, provided the effective date for any change cannot be earlier than January 1, 2018.
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. On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the
NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. Additionally,
the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way
associated with the utilities' transmission assets;; (ii) a Mutual Assistance Agreement;; (iii) MAIT being deemed a public utility under
state law;; (iv) MAIT's participation in FE's regulated companies' money pool;; and (v) certain affiliated interest agreements. If
approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-
free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL. MAIT's
transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities
under the PJM Tariff. During the third quarter of 2015, FirstEnergy responded to FERC Staff's request for additional information
regarding the application. FERC approval is expected during the first quarter of 2016 with final decisions expected from the NJBPU
and PPUC by mid-2016. Following FERC approval of the transfer, MAIT expects to file a Section 204 application with FERC, and
other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their
respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application with FERC to establish its
transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve
alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001.
The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was
made in the context of mediation efforts by FERC and the Ninth Circuit in several pending proceedings to resolve all outstanding
refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The
Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California parties in May
2011. The California parties appealed FERC's decision back to the Ninth Circuit. AE Supply joined with other intervenors in the case
and filed a brief in support of FERC's dismissal of the case. On April 29, 2015, the Ninth Circuit remanded the case to FERC for
further proceedings. On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any
individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and
unreasonable rate for that particular seller in California during the 2000-2001 period. Settlement discussions under a FERC-appointed
settlement judge are ongoing. Requests for rehearing or clarification of FERC’s November 3, 2015 order by various parties, including
AE Supply, remain pending.
In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a complaint with
FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during
2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply and
other parties filed motions to dismiss, which FERC granted. The California Attorney General appealed FERC's dismissal of its
complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and
stayed the proceedings pending further order.
The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.
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 (an equity method
investment for FE), 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 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. The initial decision and exceptions thereto are now before FERC for review and a final order. FirstEnergy continues to
believe the costs are recoverable, subject to final ruling from FERC.
FERC Opinion No. 531
On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow
element of FERC’s ROE methodology, and announced the potential for a qualitative adjustment to the ROE methodology results.
Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth
variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight);; and (b) a long-term dividend growth forecast
based on a forecast for the U.S. economy (1/3 weight). Regarding the qualitative adjustment, for single-utility rate cases FERC
formerly pegged ROE at the median of the “zone of reasonableness” that came out of the ROE formula, whereas going forward,
FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level
sufficient to attract future investment. On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE
methodology to certain ISO New England transmission owners, and on March 3, 2015, FERC issued Opinion No. 531-B affirming its
prior rulings. Appeals of Opinion Nos. 531, 532-A and 531-B are pending before the U.S. Court of Appeals for the D.C. Circuit.
FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities
and the cost-of-service wholesale power generation transactions of MP.
MISO Capacity Portability
On June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regarding whether existing
rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FirstEnergy and other parties submitted
filings arguing that MISO's concerns largely are without foundation, FERC did not mandate a solution in response to MISO's
concerns. At FERC's direction, in May, 2015, PJM, MISO, and their respective independent market monitors provided additional
information on their various joint issues surrounding the PJM/MISO seam to assist FERC's understanding of the issues and what, if
any, additional steps FERC should take to improve the efficiency of operations at the PJM/MISO seam. Stakeholders, including FESC
on behalf of certain of its affiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions. The
various submissions and responses are now before FERC for consideration.
Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the
outcome of those auctions, including a negative impact on the prices at which those auctions would clear.
FTR Underfunding Complaint
In PJM, FTRs are a mechanism to hedge congestion and operate as a financial replacement for physical firm transmission service.
FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price
differences across a specific transmission path in the PJM Day-ahead Energy Market. Due to certain language in the PJM Tariff, the
funds that are set aside to pay FTRs can be diverted to other uses, which may result in “underfunding” of FTR payments. On
February 15, 2013, FES and AE Supply filed a renewed complaint with FERC for the purpose of changing the PJM Tariff to eliminate
FTR underfunding. On June 5, 2013, FERC issued an order denying the complaint, and on June 8, 2015, denied a request for
rehearing of the June 5, 2013 order.
122
123
recovery of these charges through its formula rate. On a related issue, FirstEnergy joined certain other PJM transmission owners in a
protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On January
22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any
limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent. Certain PJM
transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP
2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply and
other parties filed motions to dismiss, which FERC granted. The California Attorney General appealed FERC's dismissal of its
complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and
stayed the proceedings pending further order.
export charge on transactions into PJM was correct and should be re-affirmed on remand. The briefs and replies thereto are now
The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.
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 (an equity method
investment for FE), 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 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. The initial decision and exceptions thereto are now before FERC for review and a final order. FirstEnergy continues to
believe the costs are recoverable, subject to final ruling from FERC.
minor compliance requirements. The settlement agreement provides for certain changes to ATSI's formula rate template and
FERC Opinion No. 531
free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL. MAIT's
MISO Capacity Portability
On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow
element of FERC’s ROE methodology, and announced the potential for a qualitative adjustment to the ROE methodology results.
Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth
variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight);; and (b) a long-term dividend growth forecast
based on a forecast for the U.S. economy (1/3 weight). Regarding the qualitative adjustment, for single-utility rate cases FERC
formerly pegged ROE at the median of the “zone of reasonableness” that came out of the ROE formula, whereas going forward,
FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level
sufficient to attract future investment. On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE
methodology to certain ISO New England transmission owners, and on March 3, 2015, FERC issued Opinion No. 531-B affirming its
prior rulings. Appeals of Opinion Nos. 531, 532-A and 531-B are pending before the U.S. Court of Appeals for the D.C. Circuit.
FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities
and the cost-of-service wholesale power generation transactions of MP.
On June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regarding whether existing
rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FirstEnergy and other parties submitted
filings arguing that MISO's concerns largely are without foundation, FERC did not mandate a solution in response to MISO's
concerns. At FERC's direction, in May, 2015, PJM, MISO, and their respective independent market monitors provided additional
information on their various joint issues surrounding the PJM/MISO seam to assist FERC's understanding of the issues and what, if
any, additional steps FERC should take to improve the efficiency of operations at the PJM/MISO seam. Stakeholders, including FESC
on behalf of certain of its affiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions. The
various submissions and responses are now before FERC for consideration.
Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the
outcome of those auctions, including a negative impact on the prices at which those auctions would clear.
FTR Underfunding Complaint
In PJM, FTRs are a mechanism to hedge congestion and operate as a financial replacement for physical firm transmission service.
FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price
differences across a specific transmission path in the PJM Day-ahead Energy Market. Due to certain language in the PJM Tariff, the
funds that are set aside to pay FTRs can be diverted to other uses, which may result in “underfunding” of FTR payments. On
February 15, 2013, FES and AE Supply filed a renewed complaint with FERC for the purpose of changing the PJM Tariff to eliminate
FTR underfunding. On June 5, 2013, FERC issued an order denying the complaint, and on June 8, 2015, denied a request for
rehearing of the June 5, 2013 order.
122
123
before FERC for consideration.
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.
2014 ATSI Formula Rate Filing
On October 31, 2014, ATSI filed a proposal with FERC to change the structure of its formula rate from an “historical looking”
approach, where transmission rates reflect actual costs for the prior year, to a “forward looking” approach, where transmission rates
would be based on the estimated costs for the coming year, with an annual true up. On December 31, 2014, FERC issued an order
accepting ATSI's filing effective January 1, 2015, subject to refund and the outcome of hearing and settlement proceedings. FERC
subsequently issued an order on October 29, 2015, accepting a settlement agreement on the forward-looking formula rate, subject to
protocols, and also changes ATSI's ROE from 12.38% to the following values: (i) 12.38% from January 1, 2015 through June 30,
2015;; (ii) 11.06% from July 1, 2015 through December 31, 2015;; and (iii) 10.38% from January 1, 2016, unless changed pursuant to
section 205 or 206 of the FPA, provided the effective date for any change cannot be earlier than January 1, 2018.
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. On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the
NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. Additionally,
the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way
associated with the utilities' transmission assets;; (ii) a Mutual Assistance Agreement;; (iii) MAIT being deemed a public utility under
state law;; (iv) MAIT's participation in FE's regulated companies' money pool;; and (v) certain affiliated interest agreements. If
approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-
transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities
under the PJM Tariff. During the third quarter of 2015, FirstEnergy responded to FERC Staff's request for additional information
regarding the application. FERC approval is expected during the first quarter of 2016 with final decisions expected from the NJBPU
and PPUC by mid-2016. Following FERC approval of the transfer, MAIT expects to file a Section 204 application with FERC, and
other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their
respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application with FERC to establish its
transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve
alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001.
The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was
made in the context of mediation efforts by FERC and the Ninth Circuit in several pending proceedings to resolve all outstanding
refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The
Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California parties in May
2011. The California parties appealed FERC's decision back to the Ninth Circuit. AE Supply joined with other intervenors in the case
and filed a brief in support of FERC's dismissal of the case. On April 29, 2015, the Ninth Circuit remanded the case to FERC for
further proceedings. On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any
individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and
unreasonable rate for that particular seller in California during the 2000-2001 period. Settlement discussions under a FERC-appointed
settlement judge are ongoing. Requests for rehearing or clarification of FERC’s November 3, 2015 order by various parties, including
AE Supply, remain pending.
In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a complaint with
FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during
PJM Market Reform: PJM Capacity Performance Proposal
In December 2014, PJM submitted proposed “Capacity Performance” reforms of its RPM capacity and energy markets. On June 9,
2015, FERC issued an order conditionally approving the bulk of the proposed Capacity Performance reforms with an effective date of
April 1, 2015, and directed PJM to make a compliance filing reflecting the mandate of FERC’s order. On July 9, 2015, several parties,
including FESC on behalf of certain of its affiliates, submitted requests for rehearing for FERC's June 9, 2015 order, and PJM
submitted its compliance filing as directed by the order. The requests for rehearing and PJM's compliance filing are pending before
FERC.
In August and September 2015, PJM conducted RPM auctions pursuant to the new Capacity Performance rules. FirstEnergy’s net
competitive capacity position as a result of the BRA and Capacity Performance transition auctions is as follows:
2016 - 2017
2017 - 2018
2018 - 2019*
Legacy
Obligation
Capacity
Performance
Legacy
Obligation
Capacity
Performance
Base
Generation
Capacity
Performance
(MW)
($/MWD)
(MW)
2,765 $114.23 4,210
$59.37 3,675
875
$119.13 —
135
($/MWD)
$134.00
$134.00
$134.00
ATSI
RTO
All Other
Zones
($/MWD)
($/MWD)
(MW)
(MW)
(MW)
$149.98 6,245
375 $120.00 6,245 $151.50 —
985 $120.00 3,565 $151.50 240 $149.98 3,930
$151.50
150 $120.00 —
($/MWD)
20
35
**
(MW)
($/MWD)
$164.77
$164.77
**
3,775
7,885
1,510
9,810
275
10,195
*Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year.
**Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at
$215.00/MWD and 15 MWs cleared at $164.77/MWD.
PJM Market Reform: FERC Order No. 745 - DR
On May 23, 2014, a divided three-judge panel of the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating FERC
Order No. 745, which required that, under certain parameters, DR participating in organized wholesale energy markets be
compensated at LMP. The majority concluded that DR is a retail service, and therefore falls under state, and not federal, jurisdiction,
and that FERC, therefore, lacks jurisdiction to regulate DR. The majority also found that even if FERC had jurisdiction over DR, Order
No. 745 would be arbitrary and capricious because, under its requirements, DR was inappropriately receiving a double payment (LMP
plus the savings of foregone energy purchases). On January 25, 2016, the United States Supreme Court reversed the opinion of the
U.S. Court of Appeals for the D.C. Circuit and remanded for further action, finding FERC has statutory authority under the FPA to
regulate compensation of demand response resources in FERC-jurisdictional wholesale power markets. The United States Supreme
Court also reversed the holding that FERC's Order No. 745 was arbitrary and capricious, finding that the order included detailed
support of the chosen compensation method.
On May 23, 2014, as amended September 22, 2014, FESC, on behalf of its affiliates with market-based rate authorization, filed a
complaint asking FERC to issue an order requiring the removal of all portions of the PJM Tariff allowing or requiring DR to be included
in the PJM capacity market, with a refund effective date of May 23, 2014. FESC also requested that the results of the May 2014 PJM
BRA be considered void and legally invalid to the extent that DR cleared that auction because the participation of DR in that auction
was unlawful. However, in light of the United States Supreme Court's January 25, 2016 decision discussed above, on January 29,
2016, FESC withdrew the complaint.
15. 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 $13.5 billion
(assuming 103 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to
$375 million;; and (ii) $13.1 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-$501 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, FirstEnergy has also obtained insurance
coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of
NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of
nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable annually, corresponding to their respective nuclear
2015:
124
125
interests, which provide an aggregate indemnity of up to approximately $1.96 billion (NG-$1.93 billion) for replacement power costs
incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to
assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment
for incidents at any covered nuclear facility occurring during a policy year would be approximately $15 million (NG-$15 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating
company for each plant. 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. FirstEnergy pays annual premiums for this coverage and
is liable for retrospective assessments of up to approximately $83 million (NG-$81 million).
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 FirstEnergy’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, 2015, outstanding guarantees and other assurances aggregated approximately $3.7 billion, consisting of
parental guarantees ($583 million), subsidiaries' guarantees ($2,137 million), other guarantees ($300 million) and other assurances
($667 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, 2015, FES has posted collateral of $188 million and AE
Supply has posted no collateral. The Regulated Distribution segment has posted collateral of $1 million.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit
rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of
forward contracts and future price movements, higher amounts for margining could be required.
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material
adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following
table discloses the additional credit contingent contractual obligations that may be required under certain events as of December 31,
PJM Market Reform: PJM Capacity Performance Proposal
In December 2014, PJM submitted proposed “Capacity Performance” reforms of its RPM capacity and energy markets. On June 9,
2015, FERC issued an order conditionally approving the bulk of the proposed Capacity Performance reforms with an effective date of
April 1, 2015, and directed PJM to make a compliance filing reflecting the mandate of FERC’s order. On July 9, 2015, several parties,
including FESC on behalf of certain of its affiliates, submitted requests for rehearing for FERC's June 9, 2015 order, and PJM
submitted its compliance filing as directed by the order. The requests for rehearing and PJM's compliance filing are pending before
FERC.
In August and September 2015, PJM conducted RPM auctions pursuant to the new Capacity Performance rules. FirstEnergy’s net
competitive capacity position as a result of the BRA and Capacity Performance transition auctions is as follows:
2016 - 2017
2017 - 2018
2018 - 2019*
Legacy
Obligation
Capacity
Performance
Legacy
Obligation
Capacity
Performance
Base
Generation
Capacity
Performance
(MW)
($/MWD)
(MW)
($/MWD)
(MW)
(MW)
($/MWD)
($/MWD)
(MW)
($/MWD)
($/MWD)
(MW)
2,765 $114.23 4,210
$134.00
375 $120.00 6,245 $151.50 —
$149.98 6,245
$164.77
$59.37 3,675
$134.00
985 $120.00 3,565 $151.50 240 $149.98 3,930
$164.77
$119.13 —
$134.00
150 $120.00 —
$151.50
35
**
20
**
ATSI
RTO
All Other
Zones
875
135
3,775
7,885
1,510
9,810
275
10,195
*Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year.
**Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at
$215.00/MWD and 15 MWs cleared at $164.77/MWD.
PJM Market Reform: FERC Order No. 745 - DR
On May 23, 2014, a divided three-judge panel of the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating FERC
Order No. 745, which required that, under certain parameters, DR participating in organized wholesale energy markets be
compensated at LMP. The majority concluded that DR is a retail service, and therefore falls under state, and not federal, jurisdiction,
and that FERC, therefore, lacks jurisdiction to regulate DR. The majority also found that even if FERC had jurisdiction over DR, Order
No. 745 would be arbitrary and capricious because, under its requirements, DR was inappropriately receiving a double payment (LMP
plus the savings of foregone energy purchases). On January 25, 2016, the United States Supreme Court reversed the opinion of the
U.S. Court of Appeals for the D.C. Circuit and remanded for further action, finding FERC has statutory authority under the FPA to
regulate compensation of demand response resources in FERC-jurisdictional wholesale power markets. The United States Supreme
Court also reversed the holding that FERC's Order No. 745 was arbitrary and capricious, finding that the order included detailed
support of the chosen compensation method.
On May 23, 2014, as amended September 22, 2014, FESC, on behalf of its affiliates with market-based rate authorization, filed a
complaint asking FERC to issue an order requiring the removal of all portions of the PJM Tariff allowing or requiring DR to be included
in the PJM capacity market, with a refund effective date of May 23, 2014. FESC also requested that the results of the May 2014 PJM
BRA be considered void and legally invalid to the extent that DR cleared that auction because the participation of DR in that auction
was unlawful. However, in light of the United States Supreme Court's January 25, 2016 decision discussed above, on January 29,
2016, FESC withdrew the complaint.
15. 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 $13.5 billion
(assuming 103 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to
$375 million;; and (ii) $13.1 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-$501 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, FirstEnergy has also obtained insurance
coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of
NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of
nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable annually, corresponding to their respective nuclear
interests, which provide an aggregate indemnity of up to approximately $1.96 billion (NG-$1.93 billion) for replacement power costs
incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to
assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment
for incidents at any covered nuclear facility occurring during a policy year would be approximately $15 million (NG-$15 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating
company for each plant. 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. FirstEnergy pays annual premiums for this coverage and
is liable for retrospective assessments of up to approximately $83 million (NG-$81 million).
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 FirstEnergy’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, 2015, outstanding guarantees and other assurances aggregated approximately $3.7 billion, consisting of
parental guarantees ($583 million), subsidiaries' guarantees ($2,137 million), other guarantees ($300 million) and other assurances
($667 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, 2015, FES has posted collateral of $188 million and AE
Supply has posted no collateral. The Regulated Distribution segment has posted collateral of $1 million.
These credit-risk-related contingent features 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 could be required.
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material
adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following
table discloses the additional credit contingent contractual obligations that may be required under certain events as of December 31,
2015:
124
125
BB+/Ba1 Credit Ratings
Full impact of credit contingent contractual obligations
Collateral Provisions
FES
AE Supply
Utilities
Total
198 $
231 $
363 $
(In millions)
6 $
6 $
16 $
41 $
41 $
41 $
245
278
420
Split Rating (One rating agency's rating below investment grade) $
$
$
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, 2015, neither FES nor AE Supply had any collateral posted with their
affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to
post $8 million with affiliated parties.
OTHER COMMITMENTS AND CONTINGENCIES
FirstEnergy 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, have also provided their joint and several guaranties of the
obligations of Global Holding under the facility.
In connection with Global Holding's term loan facility, a portion of Global Holding's direct and indirect membership interests in Signal
Peak, Global Rail and their affiliates along with each of FEV's and WMB Marketing Ventures,LLC's 33-1/3% membership interests in
Global Holding, are pledged to the lenders under Global Holding's facility as collateral. Failure by Global Holding to meet the terms
and conditions under its term loan facility could require FirstEnergy to be obligated under the provisions of its guarantee, resulting in
consolidation of Global Holding by FE.
During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the
Signal Peak mine to FG in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term
loan facility through 2020, resulting in a pre-tax charge of $24 million. See Note 8, Variable Interest Entities, and Note 1, Organization,
Basis of Presentation and Significant Accounting Policies - Investments, for additional information regarding FEV's investment in
Global Holding.
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 proposed a CSAPR update rule on
November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including
Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future
cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.
EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015.
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 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 substantial and changes to FirstEnergy’s and
FES’ operations may result.
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. Under the CAA, state permitting authorities can
126
127
grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where
electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16,
2016 for MATS compliance at the Fort Martin, Harrison and Pleasants plants. On March 20, 2013, the PA DEP granted an extension
through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Bruce Mansfield plants. On February 5, 2015, the OEPA
granted an extension through April 16, 2016 for MATS compliance at the Bay Shore and Sammis plants. Nearly all spending for
MATS compliance at Bay Shore and Sammis has been completed through 2014. In addition, an EPA enforcement policy document
contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical
units. On June 29, 2015, the United States Supreme Court reversed a U.S. Court of Appeals for the D.C. Circuit decision that upheld
MATS, rejecting EPA’s regulatory approach that costs are not relevant to the decision of whether or not to regulate power plant
emissions under Section 112 of the Clean Air Act and remanded the case back to the U.S. Court of Appeals for the D.C. Circuit for
further proceedings. The U.S. Court of Appeals for the D.C. Circuit later remanded MATS back to EPA, who represented to such court
that the EPA is on track to issue a finalized MATS by April 15, 2016. Subject to the outcome of any further proceedings before the
U.S. Court of Appeals for the D.C. Circuit and how the MATS are ultimately implemented, 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 $202 million has been spent through December 31, 2015 ($80 million
at CES and $122 million at Regulated Distribution).
As a result of MATS, Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 were deactivated in April 2015, which completes
the deactivation of 5,429 MW of coal-fired plants since 2012.
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 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, those plants 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 including, but not limited to, lost profits under the contract through 2025. As part of its statement of claim, a right to
liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to
begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is
expected to be issued within sixty days from the end of the liability hearings. 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. FirstEnergy and FES intend to vigorously assert their 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. FirstEnergy and FES are unable to estimate the loss or range of loss.
FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of
which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a
defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FirstEnergy and FES fail to
reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s
and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results
of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are
unable to estimate the loss or range of loss.
As to both coal transportation agreements referenced above, FES paid in settlement approximately $70 million in liquidated damages
for delivery shortfalls in 2014 related to its deactivated plants.
As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to
notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient
justification to terminate the agreement. FirstEnergy and AE Supply have 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 6 million tons
remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going
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, and March 27, 2013,
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.
Collateral Provisions
Split Rating (One rating agency's rating below investment grade) $
BB+/Ba1 Credit Ratings
Full impact of credit contingent contractual obligations
FES
AE Supply
Utilities
Total
198 $
231 $
363 $
$
$
(In millions)
6 $
6 $
16 $
41 $
41 $
41 $
245
278
420
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, 2015, neither FES nor AE Supply had any collateral posted with their
affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to
post $8 million with affiliated parties.
OTHER COMMITMENTS AND CONTINGENCIES
FirstEnergy 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, have also provided their joint and several guaranties of the
obligations of Global Holding under the facility.
In connection with Global Holding's term loan facility, a portion of Global Holding's direct and indirect membership interests in Signal
Peak, Global Rail and their affiliates along with each of FEV's and WMB Marketing Ventures,LLC's 33-1/3% membership interests in
Global Holding, are pledged to the lenders under Global Holding's facility as collateral. Failure by Global Holding to meet the terms
and conditions under its term loan facility could require FirstEnergy to be obligated under the provisions of its guarantee, resulting in
consolidation of Global Holding by FE.
During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the
Signal Peak mine to FG in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term
loan facility through 2020, resulting in a pre-tax charge of $24 million. See Note 8, Variable Interest Entities, and Note 1, Organization,
Basis of Presentation and Significant Accounting Policies - Investments, for additional information regarding FEV's investment in
Global Holding.
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
emission allowances.
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
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 proposed a CSAPR update rule on
November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including
Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future
cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.
EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015.
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 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 substantial and changes to FirstEnergy’s and
FES’ operations may result.
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. Under the CAA, state permitting authorities can
grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where
electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16,
2016 for MATS compliance at the Fort Martin, Harrison and Pleasants plants. On March 20, 2013, the PA DEP granted an extension
through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Bruce Mansfield plants. On February 5, 2015, the OEPA
granted an extension through April 16, 2016 for MATS compliance at the Bay Shore and Sammis plants. Nearly all spending for
MATS compliance at Bay Shore and Sammis has been completed through 2014. In addition, an EPA enforcement policy document
contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical
units. On June 29, 2015, the United States Supreme Court reversed a U.S. Court of Appeals for the D.C. Circuit decision that upheld
MATS, rejecting EPA’s regulatory approach that costs are not relevant to the decision of whether or not to regulate power plant
emissions under Section 112 of the Clean Air Act and remanded the case back to the U.S. Court of Appeals for the D.C. Circuit for
further proceedings. The U.S. Court of Appeals for the D.C. Circuit later remanded MATS back to EPA, who represented to such court
that the EPA is on track to issue a finalized MATS by April 15, 2016. Subject to the outcome of any further proceedings before the
U.S. Court of Appeals for the D.C. Circuit and how the MATS are ultimately implemented, 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 $202 million has been spent through December 31, 2015 ($80 million
at CES and $122 million at Regulated Distribution).
As a result of MATS, Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 were deactivated in April 2015, which completes
the deactivation of 5,429 MW of coal-fired plants since 2012.
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 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, those plants 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 including, but not limited to, lost profits under the contract through 2025. As part of its statement of claim, a right to
liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to
begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is
expected to be issued within sixty days from the end of the liability hearings. 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. FirstEnergy and FES intend to vigorously assert their 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. FirstEnergy and FES are unable to estimate the loss or range of loss.
FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of
which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a
defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FirstEnergy and FES fail to
reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s
and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results
of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are
unable to estimate the loss or range of loss.
As to both coal transportation agreements referenced above, FES paid in settlement approximately $70 million in liquidated damages
for delivery shortfalls in 2014 related to its deactivated plants.
As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to
notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient
justification to terminate the agreement. FirstEnergy and AE Supply have 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 6 million tons
remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going
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, and March 27, 2013,
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.
126
127
Climate Change
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. A June 2013, Presidential Climate Action
Plan outlined goals to: (i) cut carbon pollution in America by 17% by 2020 (from 2005 levels);; (ii) prepare the United States for the
impacts of climate change;; and (iii) lead international efforts to combat global climate change and prepare for its impacts. GHG
emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant
deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2015,
exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.
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. The EPA released its final regulations in August 2015, 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. 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.
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, 2015, 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 substantial.
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 must be ratified by at least 55
countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below
two degrees Celsius become effective. 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 significant 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 substantial.
The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating
category (40 CFR Part 423) in April 2013. On September 30, 2015, the EPA finalized new, more stringent effluent limits for arsenic,
mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.
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 unexpected, changes in timing and closure plan
requirements in the future could impact our asset retirement obligations significantly.
Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-
closure activities and to complete closure within a 12-year period, but authorizing FE 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 Bruce Mansfield
plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal
options will be sufficient for the ongoing operation of the plant. 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 Notice of Appeals 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, 2015 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
$126 million have been accrued through December 31, 2015. Included in the total are accrued liabilities of approximately $87 million
for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered
by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional
amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
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, 2015, FirstEnergy had approximately $2.3 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 required by the NRC, FirstEnergy annually recalculates and adjusts the
amount of its parental guaranties, as appropriate.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional
twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue
operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record
and admit a contention on the NRC’s Continued Storage Rule. On August 6, 2015, this intervenor sought review of the NRC
Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC has moved to intervene in that proceeding.
128
129
Climate Change
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. A June 2013, Presidential Climate Action
Plan outlined goals to: (i) cut carbon pollution in America by 17% by 2020 (from 2005 levels);; (ii) prepare the United States for the
impacts of climate change;; and (iii) lead international efforts to combat global climate change and prepare for its impacts. GHG
emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant
deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2015,
exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.
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.
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
Regulation of Waste Disposal
pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric
generating plants. The EPA released its final regulations in August 2015, 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. 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.
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, 2015, 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 substantial.
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 must be ratified by at least 55
countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below
two degrees Celsius become effective. 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 significant 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.
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 unexpected, changes in timing and closure plan
requirements in the future could impact our asset retirement obligations significantly.
Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-
closure activities and to complete closure within a 12-year period, but authorizing FE 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 Bruce Mansfield
plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal
options will be sufficient for the ongoing operation of the plant. 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 Notice of Appeals 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, 2015 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
$126 million have been accrued through December 31, 2015. Included in the total are accrued liabilities of approximately $87 million
for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered
by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional
amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
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
OTHER LEGAL PROCEEDINGS
day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a
Nuclear Plant Matters
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 substantial.
The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating
category (40 CFR Part 423) in April 2013. On September 30, 2015, the EPA finalized new, more stringent effluent limits for arsenic,
mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.
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.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of
December 31, 2015, FirstEnergy had approximately $2.3 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 required by the NRC, FirstEnergy annually recalculates and adjusts the
amount of its parental guaranties, as appropriate.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional
twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue
operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record
and admit a contention on the NRC’s Continued Storage Rule. On August 6, 2015, this intervenor sought review of the NRC
Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC has moved to intervene in that proceeding.
128
129
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. Management believes that these allocation
methods are reasonable. 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, and may purchase 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 and the Utilities are parties to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that
provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy 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 5, Taxes).
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 related to the Shield Building analysis in 2016.
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. These and other NRC requirements adopted as a result of the accident at
Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FirstEnergy's nuclear
facilities.
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 14,
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.
16. 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, 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, 2015 are as follows:
FES
2015
2014
(In millions)
2013
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
$
664 $
6
861 $
6
353
1
705
2
4
3
271
1
619
3
3
4
652
6
486
—
619
2
4
6
130
131
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. Management believes that these allocation
methods are reasonable. 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, and may purchase 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 and the Utilities are parties to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that
provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy 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 5, Taxes).
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 related to the Shield Building analysis in 2016.
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. These and other NRC requirements adopted as a result of the accident at
Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FirstEnergy's nuclear
facilities.
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 14,
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.
16. 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, 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, 2015 are as follows:
Electric sales to affiliates
$
664 $
861 $
FES
Revenues:
Other
Expenses:
Fuel
Purchased power from affiliates
Support services
Investment Income:
Interest income from FE
Interest Expense:
Interest expense to affiliates
Interest expense to FE
2015
2014
2013
(In millions)
6
353
1
705
2
4
3
6
271
1
619
3
3
4
652
6
486
—
619
2
4
6
130
131
17. 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,
2015, 2014, and 2013, Condensed Consolidating Balance Sheets as of December 31, 2015 and December 31, 2014, and
Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2015, 2014, and 2013, for FES (parent and
guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES 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 FES using the equity method. Results of operations for FG and NG are, therefore, reflected in FES’ 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.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FIRSTENERGY SOLUTIONS CORP.
For the Year Ended December 31, 2015
FES
FG
NG
Eliminations Consolidated
STATEMENTS OF INCOME
(In millions)
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
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
NET INCOME
STATEMENTS OF COMPREHENSIVE INCOME
—
3,826
1,684
399
(8 )
12
45
5,958
(1,134 )
844
1
(29 )
(52 )
—
764
(370 )
(452 )
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
(6 )
(3 )
(9 )
(18 )
(7 )
(11 )
71 $
$
$
$
679
—
—
275
10
124
26
1,114
687
17
2
(8 )
(104 )
6
(87 )
600
224
(5 )
—
—
(5 )
(2 )
(3 )
192
285
—
618
55
191
27
1,368
770
(5 )
—
(4 )
(49 )
29
(29 )
741
278
—
—
(8 )
(8 )
(3 )
(5 )
(3,758 )
—
—
49
—
(3 )
—
(3,712 )
(46 )
(870 )
—
34
58
—
(778 )
(824 )
15
5
—
8
13
5
8
82 $
376 $
463 $
(839 ) $
82 $
376 $
463 $
(839 ) $
373 $
458 $
(831 ) $
871
353
1,684
1,341
57
324
98
4,728
277
(14 )
3
(7 )
(147 )
35
(130 )
147
65
82
82
(6 )
(3 )
(9 )
(18 )
(7 )
(11 )
71
132
133
17. 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.
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2015
FES
FG
NG
Eliminations Consolidated
STATEMENTS OF INCOME
(In millions)
$
4,824 $
1,801 $
2,138 $
(3,758 ) $
5,005
The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31,
2015, 2014, and 2013, Condensed Consolidating Balance Sheets as of December 31, 2015 and December 31, 2014, and
REVENUES
Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2015, 2014, and 2013, for FES (parent and
guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES fully and unconditionally
OPERATING EXPENSES:
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 FES using the equity method. Results of operations for FG and NG are, therefore, reflected in FES’ 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.
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 (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
—
3,826
1,684
399
(8 )
12
45
5,958
(1,134 )
844
1
(29 )
(52 )
—
764
(370 )
(452 )
679
—
—
275
10
124
26
1,114
687
17
2
(8 )
(104 )
6
(87 )
600
224
192
285
—
618
55
191
27
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 ) $
Income tax benefits on other comprehensive loss
Other comprehensive loss, net of tax
COMPREHENSIVE INCOME
(6 )
(3 )
(9 )
(18 )
(7 )
(5 )
—
—
(5 )
(2 )
—
—
(8 )
(8 )
(3 )
$
(11 )
71 $
(3 )
373 $
(5 )
458 $
5
—
8
13
5
8
(831 ) $
871
353
1,684
1,341
57
324
98
4,728
277
(14 )
3
(7 )
(147 )
35
(130 )
147
65
82
82
(6 )
(3 )
(9 )
(18 )
(7 )
(11 )
71
132
133
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
STATEMENTS OF INCOME (LOSS)
(In millions)
REVENUES
$
5,990 $
1,902 $
2,172 $
(3,920 ) $
6,144
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FIRSTENERGY SOLUTIONS CORP.
For the Year Ended December 31, 2013
FES
FG
NG
Eliminations Consolidated
STATEMENTS OF INCOME
(In millions)
REVENUES
$
6,068 $
2,399 $
1,634 $
(3,928 ) $
6,173
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):
Loss on debt redemptions
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 $70)
—
3,920
2,767
790
19
10
72
7,578
(1,588 )
(3 )
791
2
(12 )
(53 )
—
725
(863 )
(619 )
(244 )
—
1,055
—
4
269
90
119
31
1,568
334
(1 )
8
4
(6 )
(101 )
4
(92 )
242
87
155
116
198
271
—
527
188
193
25
1,402
770
(2 )
61
—
(4 )
(52 )
30
33
803
298
505
—
—
(3,920 )
—
49
—
(3 )
—
(3,874 )
(46 )
—
(799 )
—
15
60
—
(724 )
(770 )
6
(776 )
—
NET INCOME (LOSS)
$
(244 ) $
271 $
505 $
(776 ) $
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
1,253
271
2,771
1,635
297
319
128
6,674
(530 )
(6 )
61
6
(7 )
(146 )
34
(58 )
(588 )
(228 )
(360 )
116
(244 )
NET INCOME (LOSS)
$
(244 ) $
271 $
505 $
(776 ) $
(244 )
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)
$
(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 )
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):
Loss on debt redemptions
investees
Miscellaneous income
Interest expense — affiliates
Interest expense — other
Capitalized interest
Total other income (expense)
Investment income, including net income from equity
INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
INCOME FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of $8)
NET INCOME
NET INCOME
STATEMENTS OF COMPREHENSIVE INCOME
—
4,148
2,326
635
(8 )
6
80
7,187
(1,119 )
(103 )
847
4
(13 )
(63 )
1
673
(446 )
(506 )
60
—
1,056
—
7
275
(37 )
127
34
1,462
937
—
1
24
(5 )
(104 )
2
(82 )
855
365
490
14
60 $
504 $
333 $
(837 ) $
60 $
504 $
333 $
(837 ) $
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
(15 )
(6 )
(8 )
(29 )
(11 )
(18 )
42 $
(13 )
—
—
(13 )
(5 )
(8 )
496 $
328 $
(824 ) $
$
$
$
206
266
—
529
(36 )
178
24
1,167
467
—
25
—
(6 )
(54 )
36
1
468
135
333
—
—
—
(8 )
(8 )
(3 )
(5 )
(3,928 )
—
—
48
—
(5 )
—
(3,885 )
(43 )
—
(857 )
—
14
61
—
(782 )
(825 )
12
(837 )
—
13
—
8
21
8
13
1,262
486
2,333
1,487
(81 )
306
138
5,931
242
(103 )
16
28
(10 )
(160 )
39
(190 )
52
6
46
14
60
60
(15 )
(6 )
(8 )
(29 )
(11 )
(18 )
42
134
135
STATEMENTS OF INCOME (LOSS)
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):
Loss on debt redemptions
investees
Miscellaneous income
Interest expense — affiliates
Interest expense — other
Capitalized interest
Total other income (expense)
Investment income, including net income from equity
INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (BENEFITS)
INCOME TAXES (BENEFITS)
INCOME (LOSS) FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of $70)
—
3,920
2,767
790
19
10
72
7,578
(1,588 )
(3 )
791
2
(12 )
(53 )
—
725
(863 )
(619 )
(244 )
—
1,055
—
4
269
90
119
31
1,568
334
(1 )
8
4
(6 )
(101 )
4
(92 )
242
87
155
116
NET INCOME (LOSS)
$
(244 ) $
271 $
505 $
(776 ) $
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)
$
(244 ) $
271 $
505 $
(776 ) $
(244 )
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)
(6 )
(10 )
21
5
2
3
(5 )
—
—
(5 )
(2 )
(3 )
$
(241 ) $
268 $
518 $
5
—
(21 )
(16 )
(6 )
(10 )
(786 ) $
(3,920 )
—
—
49
—
(3 )
—
(3,874 )
(46 )
—
(799 )
—
15
60
—
(724 )
(770 )
6
(776 )
—
198
271
—
527
188
193
25
1,402
770
(2 )
61
—
(4 )
(52 )
30
33
803
298
505
—
—
—
21
21
8
13
1,253
271
2,771
1,635
297
319
128
6,674
(530 )
(6 )
61
6
(7 )
(146 )
34
(58 )
(588 )
(228 )
(360 )
116
(244 )
(6 )
(10 )
21
5
2
3
(241 )
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
FIRSTENERGY SOLUTIONS CORP.
For the Year Ended December 31, 2014
FES
FG
NG
Eliminations Consolidated
REVENUES
$
5,990 $
1,902 $
2,172 $
(3,920 ) $
6,144
REVENUES
$
6,068 $
2,399 $
1,634 $
(3,928 ) $
6,173
(In millions)
For the Year Ended December 31, 2013
FES
FG
NG
Eliminations Consolidated
STATEMENTS OF INCOME
(In millions)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
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):
Loss on debt redemptions
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 FROM CONTINUING OPERATIONS
Discontinued operations (net of income taxes of $8)
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
—
4,148
2,326
635
(8 )
6
80
7,187
(1,119 )
(103 )
847
4
(13 )
(63 )
1
673
(446 )
(506 )
60
—
1,056
—
7
275
(37 )
127
34
1,462
937
—
1
24
(5 )
(104 )
2
(82 )
855
365
490
14
206
266
—
529
(36 )
178
24
1,167
467
—
25
—
(6 )
(54 )
36
1
468
135
333
—
—
(3,928 )
—
48
—
(5 )
—
(3,885 )
(43 )
—
(857 )
—
14
61
—
(782 )
(825 )
12
(837 )
—
60 $
504 $
333 $
(837 ) $
60 $
504 $
333 $
(837 ) $
(15 )
(6 )
(8 )
(29 )
(11 )
(13 )
—
—
(13 )
(5 )
—
—
(8 )
(8 )
(3 )
$
(18 )
42 $
(8 )
496 $
(5 )
328 $
13
—
8
21
8
13
(824 ) $
1,262
486
2,333
1,487
(81 )
306
138
5,931
242
(103 )
16
28
(10 )
(160 )
39
(190 )
52
6
46
14
60
60
(15 )
(6 )
(8 )
(29 )
(11 )
(18 )
42
134
135
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2015
FES
FG
NG
(In millions)
Eliminations
Consolidated
ASSETS
(In millions)
As of December 31, 2014
FES
FG
NG
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
Asset retirement obligations
Retirement benefits
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
384
587
13,185
512
—
8
542
139
76
104
181
1,562
5,605
2,527
8,132
791
600
831
332
38
899
3,491
13,185
$
— $
2 $
— $
— $
—
403
4
1,210
204
—
—
18
1,841
6,367
2,144
4,223
249
4,472
—
—
10
10
16
—
—
12
—
318
346
6,669 $
229 $
389
8
146
118
93
1
61
1,045
2,944
2,122
5,066
—
—
191
305
1
61
558
6,669 $
—
461
19
805
213
—
—
—
1,498
8,233
3,775
4,458
878
5,336
1,327
—
—
1,327
—
—
—
28
—
21
49
8,210 $
308 $
—
—
368
—
62
—
9
747
4,476
847
5,323
—
697
640
—
—
803
2,140
8,210 $
—
(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
33
496
9,506 $
— $
2,021
—
884
21
7
103
66
3,102
5,605
694
6,299
—
6
—
27
37
35
105
9,506 $
136
$
$
$
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
Customers
Affiliated companies
Other
Materials and supplies
Derivatives
Collateral
Prepayments and other
Notes receivable from affiliated companies
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
Unamortized sale and leaseback costs
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
Asset retirement obligations
Retirement benefits
Derivatives
Other
$
— $
2 $
— $
— $
—
487
21
838
202
—
—
19
1,569
6,217
2,058
4,159
206
4,365
—
—
10
10
98
—
—
14
—
—
277
389
321
9
197
202
62
—
56
1,011
2,561
2,215
4,776
—
—
189
288
—
69
546
—
674
20
272
223
—
—
—
1,189
7,628
3,305
4,323
801
5,124
1,365
—
—
1,365
—
—
—
27
—
—
7
34
28
—
219
—
161
—
9
765
4,014
859
4,873
—
678
652
—
—
744
(1,120 )
(1,449 )
—
—
—
—
—
1
(2,568 )
(382 )
(191 )
(191 )
—
(191 )
(6,607 )
—
—
(6,607 )
(382 )
—
—
—
—
—
13
(1,449 )
—
(1,068 )
—
(123 )
—
47
(2,617 )
(6,575 )
(1,161 )
(7,736 )
824
(207 )
—
—
—
1
618
2
415
525
107
—
492
147
229
68
1,985
13,596
5,208
8,388
1,010
9,398
1,365
—
10
1,375
—
78
23
41
—
52
331
525
13,283
506
35
99
416
248
102
166
184
1,756
5,585
2,608
8,193
824
484
841
324
14
847
3,334
13,283
$
$
471
8,973 $
6,333 $
7,712 $
(369 )
(9,735 ) $
18 $
164 $
348 $
(24 ) $
$
8,973 $
6,333 $
2,074
7,712 $
(9,735 ) $
415
484
66
339
67
147
229
48
133
36
97
3
100
1,795
—
6,607
—
6,607
284
78
23
—
—
52
34
1,135
90
1,068
46
2
166
72
2,597
5,585
695
6,280
—
13
—
36
14
33
96
137
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2015
FES
FG
NG
Eliminations
Consolidated
(In millions)
$
— $
2 $
— $
— $
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
$
496
9,506 $
6,669 $
8,210 $
(304 )
(11,200 ) $
13,185
— $
229 $
308 $
(25 ) $
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Receivables-
Customers
Affiliated companies
Other
Materials and supplies
Derivatives
Collateral
Prepayments and other
Notes receivable from affiliated companies
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
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
Asset retirement obligations
Retirement benefits
Derivatives
Other
—
403
4
1,210
204
—
—
18
1,841
6,367
2,144
4,223
249
4,472
—
—
10
10
16
—
—
12
—
318
346
389
8
146
118
93
1
61
1,045
2,944
2,122
5,066
—
—
191
305
1
61
558
—
461
19
805
213
—
—
—
1,498
8,233
3,775
4,458
878
5,336
1,327
—
—
1,327
—
—
—
28
—
21
49
—
—
368
—
62
—
9
747
4,476
847
5,323
—
697
640
—
—
803
—
(846 )
—
(2,410 )
—
—
—
—
(3,256 )
(382 )
(194 )
(188 )
—
(188 )
(7,452 )
—
—
(7,452 )
(316 )
—
—
—
—
12
(2,410 )
—
(856 )
—
(86 )
—
45
(3,332 )
(7,420 )
(1,136 )
(8,556 )
791
(103 )
—
—
—
—
688
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
384
587
512
—
8
542
139
76
104
181
1,562
5,605
2,527
8,132
791
600
831
332
38
899
3,491
13,185
105
9,506 $
$
6,669 $
2,140
8,210 $
(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
33
2,021
—
884
21
7
103
66
3,102
5,605
694
6,299
—
6
—
27
37
35
136
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
As of December 31, 2014
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
Unamortized sale and leaseback costs
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
Asset retirement obligations
Retirement benefits
Derivatives
Other
2
415
525
107
—
492
147
229
68
1,985
13,596
5,208
8,388
1,010
9,398
1,365
—
10
1,375
—
78
23
41
—
52
331
525
13,283
506
35
99
416
248
102
166
184
1,756
5,585
2,608
8,193
824
484
841
324
14
847
3,334
13,283
$
— $
2 $
— $
— $
—
487
21
838
202
—
—
19
1,569
6,217
2,058
4,159
206
4,365
—
—
10
10
98
—
—
14
—
—
277
389
6,333 $
164 $
321
9
197
202
62
—
56
1,011
2,561
2,215
4,776
—
—
189
288
—
69
546
6,333 $
—
674
20
272
223
—
—
—
1,189
7,628
3,305
4,323
801
5,124
1,365
—
—
1,365
—
—
—
27
—
—
7
34
7,712 $
348 $
28
—
219
—
161
—
9
765
4,014
859
4,873
—
678
652
—
—
744
2,074
7,712 $
—
(1,120 )
—
(1,449 )
—
—
—
1
(2,568 )
(382 )
(191 )
(191 )
—
(191 )
—
(6,607 )
—
(6,607 )
(382 )
—
—
—
—
—
13
(369 )
(9,735 ) $
(24 ) $
(1,449 )
—
(1,068 )
—
(123 )
—
47
(2,617 )
(6,575 )
(1,161 )
(7,736 )
824
(207 )
—
—
—
1
618
(9,735 ) $
415
484
66
339
67
147
229
48
1,795
133
36
97
3
100
—
6,607
—
6,607
284
78
23
—
—
52
34
471
8,973 $
18 $
1,135
90
1,068
46
2
166
72
2,597
5,585
695
6,280
—
13
—
36
14
33
96
8,973 $
137
$
$
$
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
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
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
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
—
796
(17 )
—
(70 )
—
709
(5 )
—
10
—
—
(10 )
(67 )
—
45
67
(70 )
—
—
(5 )
37
(223 )
—
3
—
—
—
(372 )
4
296
—
(348 )
(28 )
—
(1 )
(81 )
(399 )
(190 )
—
733
(791 )
—
(533 )
—
—
(863 )
24
(98 )
—
—
(937 )
—
—
—
—
—
—
961
—
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
$
(72 )
—
—
— $
(588 )
—
2
2 $
(1,180 )
—
—
— $
961
—
—
— $
341
—
(411 )
(126 )
(70 )
(6 )
(272 )
(627 )
(190 )
13
733
(791 )
(10 )
(11 )
4
(879 )
—
2
2
Other
activities
Net cash provided from (used for) financing
745
264
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
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
—
247
500
(1 )
—
(1 )
(8 )
—
—
—
—
(136 )
(1 )
(145 )
—
—
431
114
—
(269 )
—
(12 )
(169 )
—
307
—
—
(815 )
5
(672 )
—
2
447
—
—
(568 )
(123 )
(2 )
(246 )
(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 )
(817 )
—
4
—
2
2
Cash and cash equivalents at end of period
$
— $
2 $
— $
— $
138
139
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
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
activities
Net cash provided from (used for) financing
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
(223 )
—
3
—
—
—
(372 )
4
296
—
(348 )
(28 )
—
(1 )
(81 )
(399 )
(190 )
—
733
(791 )
—
(533 )
—
(588 )
(1,180 )
—
2
2 $
—
—
— $
—
(863 )
24
(98 )
—
—
(937 )
—
—
—
—
—
—
961
—
961
—
—
— $
341
—
(411 )
(126 )
(70 )
(6 )
(272 )
(627 )
(190 )
13
733
(791 )
(10 )
(11 )
4
(879 )
—
2
2
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
138
139
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
18. SEGMENT INFORMATION
For the Year Ended December 31, 2013
FES
FG
NG
Eliminations Consolidated
FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES.
(In millions)
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate
reportable operating segments.
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES
$
(1,429 ) $
753
$
776
$
(22 ) $
78
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net
Equity contribution from parent
Redemptions and Repayments-
Long-term debt
Short-term borrowings, net
Tender premiums
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
Loans to affiliated companies, net
Other
Net cash provided from (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
$
864
1,500
(770 )
(244 )
(67 )
(4 )
1,279
(12 )
—
—
—
—
163
(1 )
150
—
—
— $
371
—
(364 )
(505 )
—
(5 )
(503 )
(256 )
—
21
—
—
(15 )
(1 )
(251 )
(1 )
3
2 $
150
—
(90 )
—
—
—
60
(449 )
(250 )
—
940
(1,000 )
(77 )
—
(836 )
—
—
— $
(954 )
—
22
749
—
—
(183 )
—
—
—
—
—
205
—
205
—
—
— $
431
1,500
(1,202 )
—
(67 )
(9 )
653
(717 )
(250 )
21
940
(1,000 )
276
(2 )
(732 )
(1 )
3
2
During the fourth quarter of 2015, management concluded that FEV's 33-1/3% equity investment in Global Holding was no longer a
strategic asset to CES. Because of this decision, the segment reporting was modified to reflect how management now views and
makes investment decisions regarding CES and Global Holding. 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 2014 and 2013 have been
reclassified to conform to the current presentation reflecting the activity of FEV's investment in Global Holding in Corporate/Other.
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 includes regulated electric generation facilities located primarily in West Virginia, Virginia and New
Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing
electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls 3,790 MWs of
generation capacity.
The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, 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 rates that recover costs and provide a return on
transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are
primarily from transmission services provided pursuant to its PJM Tariff to LSEs. 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. This business segment currently controls 13,162 MWs of capacity. The CES segment’s net income is 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.
Corporate support 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. As of
December 31, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to
variable-interest rates and $1.7 billion was borrowed under the FE revolving credit facility.
140
141
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
18. SEGMENT INFORMATION
For the Year Ended December 31, 2013
FES
FG
NG
Eliminations Consolidated
FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES.
(In millions)
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate
reportable operating segments.
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES
$
(1,429 ) $
753
$
776
$
(22 ) $
78
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net
Equity contribution from parent
Redemptions and Repayments-
Long-term debt
Short-term borrowings, net
Tender premiums
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
Loans to affiliated companies, net
Other
activities
Net cash provided from (used for) investing
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
— $
864
1,500
(770 )
(244 )
(67 )
(4 )
1,279
(12 )
—
—
—
—
163
(1 )
150
—
—
371
—
(364 )
(505 )
—
(5 )
(503 )
(256 )
—
21
—
—
(15 )
(1 )
150
—
(90 )
—
—
—
60
(449 )
(250 )
—
940
(1,000 )
(77 )
—
(251 )
(836 )
(1 )
3
2 $
—
—
— $
(954 )
—
22
749
—
—
(183 )
—
—
—
—
—
205
—
205
—
—
— $
431
1,500
(1,202 )
—
(67 )
(9 )
653
(717 )
(250 )
21
940
(1,000 )
276
(2 )
(732 )
(1 )
3
2
During the fourth quarter of 2015, management concluded that FEV's 33-1/3% equity investment in Global Holding was no longer a
strategic asset to CES. Because of this decision, the segment reporting was modified to reflect how management now views and
makes investment decisions regarding CES and Global Holding. 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 2014 and 2013 have been
reclassified to conform to the current presentation reflecting the activity of FEV's investment in Global Holding in Corporate/Other.
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 includes regulated electric generation facilities located primarily in West Virginia, Virginia and New
Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing
electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls 3,790 MWs of
generation capacity.
The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, 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 rates that recover costs and provide a return on
transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are
primarily from transmission services provided pursuant to its PJM Tariff to LSEs. 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. This business segment currently controls 13,162 MWs of capacity. The CES segment’s net income is 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.
Corporate support 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. As of
December 31, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to
variable-interest rates and $1.7 billion was borrowed under the FE revolving credit facility.
140
141
On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to a subsidiary of LS Power 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 and $26 million (FES - $186
million and $22 million) for the years ended December 31, 2014 and 2013, respectively, was included in discontinued operations in
the Consolidated Statement of Income. 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 and $33
million (FES - $5 million and $31 million) for years ended December 31, 2014 and 2013, respectively, were included in discontinued
operations in the Consolidated Statement of Income.
Segment Financial Information
19. DISCONTINUED OPERATIONS
For the Years Ended December 31,
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate
/ Other
Reconciling
Adjustments Consolidated
(In millions)
2015
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of long-lived assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Total assets
Total goodwill
Property additions
2014
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of long-lived assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Total assets
Total goodwill
Property additions
2013
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of long-lived assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Total assets
Total goodwill
Property additions
$
$
$
9,625 $
—
9,625
672
261
8
42
—
586
342
618
—
618
27,876
5,092
1,108
9,102 $
—
9,102
658
1
—
56
—
589
227
465
—
465
28,085
5,092
972
8,720 $
—
8,720
606
529
322
57
—
543
301
501
—
501
27,683
5,092
1,272
1,011 $
—
1,011
156
7
—
—
—
161
174
298
—
298
7,439
526
952
769 $
—
769
127
11
—
—
—
131
121
223
—
223
6,252
526
1,329
731 $
—
731
114
10
—
—
—
93
129
214
—
214
5,247
526
461
4,698 $
686
5,384
394
—
34
(16 )
—
192
50
89
—
89
16,365
800
588
5,470 $
819
6,289
387
—
—
54
—
189
(223 )
(417 )
86
(331 )
16,518
800
939
5,728 $
770
6,498
439
—
473
14
—
222
(140 )
(235 )
17
(218 )
16,782
800
827
(168 ) $
—
(168 )
60
—
—
(9 )
362
193
(262 )
(427 )
—
(427 )
507
—
56
(146 ) $
—
(146 )
48
—
—
2
—
168
(178 )
(58 )
—
(58 )
793
—
72
(121 ) $
—
(121 )
43
—
—
6
—
148
(105 )
(105 )
—
(105 )
712
—
78
(140 ) $
(686 )
(826 )
—
—
—
(39 )
—
—
11
—
—
—
—
—
—
(146 ) $
(819 )
(965 )
—
—
—
(40 )
—
(4 )
11
—
—
—
—
—
—
(166 ) $
(770 )
(936 )
—
—
—
(44 )
—
10
10
—
—
—
—
—
—
15,026
—
15,026
1,282
268
42
(22 )
362
1,132
315
578
—
578
52,187
6,418
2,704
15,049
—
15,049
1,220
12
—
72
—
1,073
(42 )
213
86
299
51,648
6,418
3,312
14,892
—
14,892
1,202
539
795
33
—
1,016
195
375
17
392
50,424
6,418
2,638
142
143
Segment Financial Information
19. DISCONTINUED OPERATIONS
For the Years Ended December 31,
Regulated
Distribution
Regulated
Transmission
Energy
Services
Corporate
/ Other
Reconciling
Adjustments Consolidated
Competitive
(In millions)
$
9,625 $
1,011 $
4,698 $
On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to a subsidiary of LS Power 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 and $26 million (FES - $186
million and $22 million) for the years ended December 31, 2014 and 2013, respectively, was included in discontinued operations in
the Consolidated Statement of Income. 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 and $33
million (FES - $5 million and $31 million) for years ended December 31, 2014 and 2013, respectively, were included in discontinued
operations in the Consolidated Statement of Income.
2015
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of long-lived assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Total assets
Total goodwill
Property additions
2014
External revenues
Internal revenues
Total revenues
Depreciation
Net income (loss)
Total assets
Total goodwill
Property additions
2013
External revenues
Internal revenues
Total revenues
Depreciation
Amortization of regulatory assets, net
Impairment of long-lived assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Amortization of regulatory assets, net
Impairment of long-lived assets
Investment income (loss)
Impairment of equity method investment
Interest expense
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Total assets
Total goodwill
Property additions
$
9,102 $
769 $
5,470 $
—
9,625
672
261
8
42
—
586
342
618
—
618
27,876
5,092
1,108
—
9,102
658
1
—
56
—
589
227
465
—
465
28,085
5,092
972
606
529
322
57
—
543
301
501
—
501
27,683
5,092
1,272
—
1,011
156
7
—
—
—
161
174
298
—
298
7,439
526
952
—
769
127
11
—
—
—
131
121
223
—
223
6,252
526
1,329
—
731
114
10
—
—
—
93
129
214
—
214
5,247
526
461
686
5,384
394
—
34
(16 )
—
192
50
89
—
89
800
588
16,365
819
6,289
387
—
—
54
—
189
(223 )
(417 )
86
(331 )
16,518
800
939
770
6,498
439
—
473
14
—
222
(140 )
(235 )
17
(218 )
16,782
800
827
(168 ) $
—
(168 )
(146 ) $
—
(146 )
60
—
—
(9 )
362
193
(262 )
(427 )
—
(427 )
507
—
56
48
—
—
2
—
168
(178 )
(58 )
—
(58 )
793
—
72
43
—
—
6
—
148
(105 )
(105 )
—
(105 )
712
—
78
(140 ) $
(686 )
(826 )
—
—
—
(39 )
—
—
11
—
—
—
—
—
—
—
(4 )
11
—
—
—
—
—
—
(146 ) $
(819 )
(965 )
—
—
—
(40 )
(166 ) $
(770 )
(936 )
—
—
—
(44 )
—
10
10
—
—
—
—
—
—
15,026
—
15,026
1,282
268
42
(22 )
362
1,132
315
578
—
578
52,187
6,418
2,704
15,049
—
15,049
1,220
12
—
72
—
1,073
(42 )
213
86
299
51,648
6,418
3,312
14,892
—
14,892
1,202
1,016
539
795
33
—
195
375
17
392
50,424
6,418
2,638
$
8,720 $
—
8,720
731 $
5,728 $
(121 ) $
—
(121 )
142
143
20. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarizes certain consolidated operating results by quarter for 2015 and 2014.
FirstEnergy
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
2015
2014
Positions Held During Past Five Years
Dates
Revenues
Other operating expense
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Operating Income (Loss)
Income (loss) from continuing operations
before income taxes (benefits)
Income taxes (benefits) (1)
Income (loss) from continuing operations
Discontinued operations (net of income taxes)
Net Income (Loss)
Earnings (loss) per share of common stock-(2)
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Earnings Available to FirstEnergy
Corp.
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Earnings Available to FirstEnergy
Corp.
952
242
313
236
(396 )
(170 )
(226 )
—
(226 )
(0.53 )
—
(0.53 )
(0.53 )
—
(0.53 )
Dec. 31 Sept. 30 June 30
$ 3,541 $
4,123 $
850
—
328
908
Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31
4,182
1,182
—
294
391
3,897 $ 3,483 $
1,057
—
319
594
3,888 $
858
—
308
716
3,496 $
1,021
—
302
292
901
835
316
(337 )
3,465 $
916
—
322
554
621
226
395
—
395
0.94
—
0.94
0.93
—
302
115
187
—
187
0.44
—
0.44
0.44
—
366
144
222
—
222
0.53
—
0.53
0.53
—
0.93
0.44
0.53
(574 )
(268 )
(306 )
—
(306 )
(0.73 )
—
(0.73 )
(0.73 )
—
(0.73 )
485
152
333
—
333
0.79
—
0.79
0.79
—
90
26
64
—
64
0.16
—
0.16
0.15
—
170
48
122
86
208
0.29
0.21
0.50
0.29
0.20
0.79
0.15
0.49
(1) During the fourth quarter of 2014, income tax benefits of $16 million were recorded that related to prior periods. The out-of-period
adjustment primarily related to the correction of amounts included in the Company’s tax basis balance sheet. Management determined that
this adjustment was not material to 2014 or any prior period.
(2) Total quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year.
See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 4. Stock-Based Compensation for additional information.
FES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
2015
2014
Revenues
Other operating expense
Pension and OPEB mark-to-market adjustment
Provision for depreciation
Operating Income (Loss)
Income (loss) from continuing operations
before income taxes (benefits)
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations (net of income taxes)
Net Income (Loss)
Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31
1,829
$ 1,171 $
452
—
74
(148 )
1,521 $
356
—
83
90
1,338 $
246
—
79
240
1,452 $
468
—
79
(151 )
1,119 $
353
—
81
—
359
297
83
(321 )
329
57
84
25
413
—
80
12
1,377 $ 1,342 $
(13 )
1
(14 )
—
(14 )
190
70
120
—
120
(25 )
(4 )
(21 )
—
(21 )
(5 )
(2 )
(3 )
—
(3 )
(347 )
(133 )
(214 )
—
(214 )
72
28
44
—
44
(154 )
(67 )
(87 )
—
(87 )
(159 )
(56 )
(103 )
116
13
144
145
Executive Officers as of February 16, 2016
Name
G. D. Benz
L. M. Cavalier
Age
56
Senior Vice President, Strategy (B)
Vice President, Supply Chain (B)
64
Chief Human Resources Officer (B)
Senior Vice President, Human Resources (B)
D. M. Chack
65
Senior Vice President, Marketing and Branding (B)
President, Ohio Operations (B)
Vice President (C)
Regional President (M)
Senior Vice President, External Affairs (B)
Vice President, External Affairs (B)
M. J. Dowling
B. L. Gaines
51
62
Senior Vice President, Corporate Services and Chief Information Officer (B)
Vice President, Corporate Services and Chief Information Officer (B)
Vice President, Shared Services, Administration and Chief Information Officer (B)
C. E. Jones
60
President and Chief Executive Officer (A)(B)
Chief Executive Officer (F)
Executive Vice President & President, FirstEnergy Utilities (A)(B)
Senior Vice President & President, FirstEnergy Utilities (B)
President (H)(I)
President (C)(D)(L)
J. H. Lash
65
Executive Vice President & President, FE Generation (A)(B)
Senior Vice President & President, FirstEnergy Utilities (A)
C. D. Lasky
53
President, FE Generation (B)
President (G)(J)
Chief Nuclear Officer (F)
President and Chief Nuclear Officer (F)
President, FirstEnergy Nuclear Operating Company (B)
Senior Vice President, Human Resources (B)
Vice President, Fossil Operations (J)
Vice President, Fossil Operations & Engineering (J)
Vice President (G)
Vice President, Fossil Fleet Operations (J)
Vice President (J)
Vice President, Fossil Operations (E)
J. F. Pearson
61
Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Senior Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Senior Vice President and Treasurer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Vice President and Treasurer (A)(B)(C)(D)(E)(F)(J)(L)
Vice President and Treasurer (G)(H)(I)
D. R. Schneider
S. E. Strah
54
52
President (E)
Senior Vice President & President, FirstEnergy Utilities (B)
K. J. Taylor
42
Vice President, Controller and Chief Accounting Officer (A)(B)
Vice President and Controller (C)(D)(E)(F)(G)(H)(I)(J)(L)
Vice President and Assistant Controller (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
President (C)(D)(H)(I)(L)
Vice President, Distribution Support (B)
Regional President (K)
Assistant Controller (A)(B)(C)(D)(L)
Assistant Controller (H)(I)
Assistant Controller (E)(F)(G)(J)
2015-present
2012-2015
2015-present
*-2015
2015-present
2011-2015
2011-2015
*-2011
2011-present
*-2011
2012-present
2011-2012
*-2011
2015-present
2015-present
2014
*-2013
2011-2015
*-2015
*-2011
2015-present
2011-2015
2011-present
2011-2012
*-2011
*-2011
2015-present
2014-2015
2014
2011-2015
2011-2013
*-2011
*-2011
2015-present
2013-2015
2012
*-2012
2011-2012
*-present
2015-present
2015-present
2011-2015
*-2011
2013-present
2013-present
2012-2013
*-2012
2011-2012
2012
2014-present
*-2013
2011-2013
L. L. Vespoli
56
Executive Vice President, Markets & Chief Legal Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F)(J)(L)
Executive Vice President and General Counsel (G)(H)(I)
* Indicates position held at least since January 1, 2011
(E) Denotes executive officer of FES
(A) Denotes executive officer of FE
(B) Denotes executive officer of FESC
(F) Denotes executive officer of FENOC
(G) Denotes executive officer of AGC
(J) Denotes executive officer of FG
(K) Denotes executive officer of OE
(L) Denotes executive officer of ATSI
(C) Denotes executive officer of OE, CEI and TE
(H) Denotes executive officer of MP, PE and WP
(M) Denotes executive officer of CEI
(D) Denotes executive officer of ME, PN and Penn
(I) Denotes executive officer of TrAIL and FET
Executive Officers as of February 16, 2016
Name
G. D. Benz
Age
56
L. M. Cavalier
D. M. Chack
M. J. Dowling
B. L. Gaines
C. E. Jones
64
65
51
62
60
J. H. Lash
65
C. D. Lasky
53
(1) During the fourth quarter of 2014, income tax benefits of $16 million were recorded that related to prior periods. The out-of-period
adjustment primarily related to the correction of amounts included in the Company’s tax basis balance sheet. Management determined that
J. F. Pearson
61
this adjustment was not material to 2014 or any prior period.
(2) Total quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year.
See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 4. Stock-Based Compensation for additional information.
D. R. Schneider
S. E. Strah
54
52
K. J. Taylor
42
L. L. Vespoli
56
20. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarizes certain consolidated operating results by quarter for 2015 and 2014.
FirstEnergy
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
2015
2014
Dec. 31 Sept. 30 June 30
Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31
$ 3,541 $
4,123 $
3,465 $
3,897 $ 3,483 $
3,888 $
3,496 $
1,021
4,182
1,182
Revenues
Other operating expense
Provision for depreciation
Operating Income (Loss)
Pension and OPEB mark-to-market adjustment
Income (loss) from continuing operations
before income taxes (benefits)
Income taxes (benefits) (1)
Income (loss) from continuing operations
Discontinued operations (net of income taxes)
Net Income (Loss)
Earnings (loss) per share of common stock-(2)
Basic - Continuing Operations
Basic - Discontinued Operations (Note 19)
Basic - Earnings Available to FirstEnergy
Corp.
Corp.
Diluted - Continuing Operations
Diluted - Discontinued Operations (Note 19)
Diluted - Earnings Available to FirstEnergy
952
242
313
236
(396 )
(170 )
(226 )
—
(226 )
(0.53 )
—
(0.53 )
(0.53 )
—
(0.53 )
850
—
328
908
621
226
395
—
395
0.94
—
0.94
0.93
—
916
—
322
554
302
115
187
—
187
0.44
—
0.44
0.44
—
1,057
—
319
594
366
144
222
—
222
0.53
—
0.53
0.53
—
901
835
316
(337 )
(574 )
(268 )
(306 )
—
(306 )
(0.73 )
—
(0.73 )
(0.73 )
—
(0.73 )
858
—
308
716
485
152
333
—
333
0.79
—
0.79
0.79
—
—
302
292
90
26
64
—
64
0.16
—
0.16
0.15
—
—
294
391
170
48
122
86
208
0.29
0.21
0.50
0.29
0.20
0.93
0.44
0.53
0.79
0.15
0.49
FES
(In millions)
CONSOLIDATED STATEMENTS OF INCOME
Revenues
Other operating expense
Provision for depreciation
Operating Income (Loss)
Pension and OPEB mark-to-market adjustment
Income (loss) from continuing operations
before income taxes (benefits)
Income taxes (benefits)
Income (loss) from continuing operations
Discontinued operations (net of income taxes)
Net Income (Loss)
2015
2014
Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31
$ 1,171 $
1,338 $
1,119 $
1,377 $ 1,342 $
1,521 $
1,452 $
329
57
84
25
(13 )
1
(14 )
—
(14 )
246
—
79
240
190
70
120
—
120
353
—
81
—
(25 )
(4 )
(21 )
—
(21 )
413
—
80
12
(5 )
(2 )
(3 )
—
(3 )
359
297
83
(321 )
(347 )
(133 )
(214 )
—
(214 )
356
—
83
90
72
28
44
—
44
468
—
79
(151 )
(154 )
(67 )
(87 )
—
(87 )
1,829
452
—
74
(148 )
(159 )
(56 )
(103 )
116
13
Positions Held During Past Five Years
Senior Vice President, Strategy (B)
Vice President, Supply Chain (B)
Chief Human Resources Officer (B)
Senior Vice President, Human Resources (B)
Senior Vice President, Marketing and Branding (B)
President, Ohio Operations (B)
Vice President (C)
Regional President (M)
Senior Vice President, External Affairs (B)
Vice President, External Affairs (B)
Senior Vice President, Corporate Services and Chief Information Officer (B)
Vice President, Corporate Services and Chief Information Officer (B)
Vice President, Shared Services, Administration and Chief Information Officer (B)
President and Chief Executive Officer (A)(B)
Chief Executive Officer (F)
Executive Vice President & President, FirstEnergy Utilities (A)(B)
Senior Vice President & President, FirstEnergy Utilities (B)
President (H)(I)
President (C)(D)(L)
Senior Vice President & President, FirstEnergy Utilities (A)
Executive Vice President & President, FE Generation (A)(B)
President, FE Generation (B)
President (G)(J)
Chief Nuclear Officer (F)
President and Chief Nuclear Officer (F)
President, FirstEnergy Nuclear Operating Company (B)
Senior Vice President, Human Resources (B)
Vice President, Fossil Operations (J)
Vice President, Fossil Operations & Engineering (J)
Vice President (G)
Vice President, Fossil Fleet Operations (J)
Vice President (J)
Vice President, Fossil Operations (E)
Executive Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Senior Vice President and Chief Financial Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Senior Vice President and Treasurer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Vice President and Treasurer (A)(B)(C)(D)(E)(F)(J)(L)
Vice President and Treasurer (G)(H)(I)
President (E)
Senior Vice President & President, FirstEnergy Utilities (B)
President (C)(D)(H)(I)(L)
Vice President, Distribution Support (B)
Regional President (K)
Vice President, Controller and Chief Accounting Officer (A)(B)
Vice President and Controller (C)(D)(E)(F)(G)(H)(I)(J)(L)
Vice President and Assistant Controller (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Assistant Controller (A)(B)(C)(D)(L)
Assistant Controller (H)(I)
Assistant Controller (E)(F)(G)(J)
Executive Vice President, Markets & Chief Legal Officer (A)(B)(C)(D)(E)(F)(G)(H)(I)(J)(L)
Executive Vice President and General Counsel (A)(B)(C)(D)(E)(F)(J)(L)
Executive Vice President and General Counsel (G)(H)(I)
Dates
2015-present
2012-2015
2015-present
*-2015
2015-present
2011-2015
2011-2015
*-2011
2011-present
*-2011
2012-present
2011-2012
*-2011
2015-present
2015-present
2014
*-2013
2011-2015
*-2015
*-2011
2015-present
2011-2015
2011-present
2011-2012
*-2011
*-2011
2015-present
2014-2015
2014
2011-2015
2011-2013
*-2011
*-2011
2015-present
2013-2015
2012
*-2012
2011-2012
*-present
2015-present
2015-present
2011-2015
*-2011
2013-present
2013-present
2012-2013
*-2012
2011-2012
2012
2014-present
*-2013
2011-2013
* Indicates position held at least since January 1, 2011
(A) Denotes executive officer of FE
(B) Denotes executive officer of FESC
(C) Denotes executive officer of OE, CEI and TE
(D) Denotes executive officer of ME, PN and Penn
(E) Denotes executive officer of FES
(F) Denotes executive officer of FENOC
(G) Denotes executive officer of AGC
(H) Denotes executive officer of MP, PE and WP
(I) Denotes executive officer of TrAIL and FET
(J) Denotes executive officer of FG
(K) Denotes executive officer of OE
(L) Denotes executive officer of ATSI
(M) Denotes executive officer of CEI
144
145
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 www.amstock.com/company/firstenergy.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
www.amstock.com/company/firstenergy.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 Rhonda S. Ferguson, Vice President and Corporate Secretary, 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