ITEM 1.
BUSINESS
The Company
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.
Subsidiaries
FirstEnergy’s revenues are primarily derived from electric service provided by its utility operating subsidiaries (OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE, and WP), ATSI and TrAIL, and the sale of energy and related products and services by its unregulated competitive subsidiaries, FES and AE Supply.
The Utilities’ combined service areas encompass approximately 65,000 square miles in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. The areas they serve have a combined population of approximately 13.5 million.
OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.3 million. OE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
OE owns all of Penn’s outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio. Penn furnishes electric service to communities in 1,100 square miles of western Pennsylvania. The area it serves has a population of approximately 0.3 million. Penn complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.7 million. CEI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the distribution and sale of electric energy in an area of 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.7 million. TE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has a 50% ownership interest (210 MW) in a hydroelectric generating facility. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.
ME was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. ME provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. ME complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
PN was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. PN provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. PN, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in the Waverly, New York vicinity. PN complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NYPSC and PPUC.
PE was organized under the laws of the State of Maryland in 1923 and in the Commonwealth of Virginia in 1974. PE is authorized to do business in the Commonwealth of Virginia and the States of West Virginia and Maryland. PE owns property and does business as an electric public utility in those states. PE provides transmission and distribution services in portions of Maryland and West Virginia and provides transmission services in Virginia in an area totaling approximately 5,500 square miles. The area it serves has a population of approximately 0.9 million. PE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, MDPSC, VSCC, and WVPSC.
MP was organized under the laws of the State of Ohio in 1924 and owns property and does business as an electric public utility in the state of West Virginia. MP provides generation, transmission and distribution services in 13,000 square miles of northern West Virginia. The area it serves has a population of approximately 0.8 million. As of December 31, 2015, MP owned or contractually controlled 3,580 MWs of generation capacity that is supplied to its electric utility business. In addition, MP is contractually obligated to provide power to PE to meet its load obligations in West Virginia. MP complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and WVPSC.
WP was organized under the laws of the Commonwealth of Pennsylvania in 1916 and owns property and does business as an electric public utility in that state. WP provides transmission and distribution services in 10,400 square miles of southwestern, south-central and northern Pennsylvania. The area it serves has a population of approximately 1.6 million. WP complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns major, high-voltage transmission facilities, which consist of approximately 7,800 circuit miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV in the PJM Region. ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, ATSI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and applicable state regulatory authorities.
TrAIL was organized under the laws of the State of Maryland and the Commonwealth of Virginia in 2006. TrAIL was formed to finance, construct, own, operate and maintain high-voltage transmission facilities in the PJM Region and has several transmission facilities in operation, including a 500 kV transmission line extending approximately 150 miles from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company in northern Virginia. TrAIL plans, operates and maintains its transmission system and facilities in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, TrAIL complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, and applicable state regulatory authorities.
FES was organized under the laws of the State of Ohio in 1997. FES provides energy-related products and services to retail and wholesale customers. FES also owns and operates, through its FG subsidiary, fossil generating facilities and owns, through its NG subsidiary, nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, organized under the laws of the State of Ohio in 1998, operates and maintains NG’s nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FG and NG, and purchases the uncommitted output of AE Supply, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs.
AE Supply was organized under the laws of the State of Delaware in 1999. AE Supply provides energy-related products and services to wholesale and retail customers. AE Supply also owns and operates fossil generating facilities and purchases and sells energy and energy-related commodities.
AGC was organized under the laws of the Commonwealth of Virginia in 1981. Approximately 59% of AGC is owned by AE Supply and approximately 41% by MP. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility (1,200 MW) and its connecting transmission facilities. AGC provides the generation capacity from this facility to AE Supply and MP.
FES, FG, NG, AE Supply and AGC comply with the regulations, orders, policies and practices prescribed by the SEC, FERC, and applicable state regulatory authorities. In addition, NG and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC.
FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.
Operating Segments
FirstEnergy's reportable operating segments are as follows: Regulated Distribution, Regulated Transmission and CES.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland.
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 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.
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.
Additional information regarding FirstEnergy’s reportable segments is provided in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 18, Segment Information, of the Combined Notes to Consolidated Financial Statements. FES does not have separate reportable operating segments.
Competitive and Regulated Generation
As of February 16, 2016, FirstEnergy’s generating portfolio consists of 16,952 MW of diversified capacity (CES - 13,162 MW and Regulated Distribution - 3,790 MW). Of the generation asset portfolio, approximately 9,218 MW (54.4%) consist of coal-fired capacity; 4,048 MW (23.9%) consist of nuclear capacity; 1,410 MW (8.3%) consist of hydroelectric capacity; 1,592 MW (9.4%) consist of oil and natural gas units; 496 MW (2.9%) consist of wind and solar power arrangements; and 188 MW (1.1%) consist of capacity entitlements to output from generation assets owned by OVEC. All units are located within PJM and sell electric energy, capacity and other products into the wholesale markets that are operated by PJM. Within CES' generation portfolio, 10,180 MW consist of FES' facilities that are operated by FENOC and FG (including entitlements from OVEC, wind and solar power arrangements), and except for portions of certain facilities that are subject to the sale and leaseback arrangements with non-affiliates for which the corresponding output of these arrangements is available to FES through power sales agreements, are all owned directly by NG and FG. Another 2,982 MW of the CES' portfolio consists of AE Supply's facilities, including AE Supply's entitlement to 713 MW from AGC's Bath County, Virginia hydroelectric facility and 67 MW of AE Supply's 3.01% entitlement from OVEC's generation output. FES' generating facilities are concentrated primarily in Ohio and Pennsylvania and AE Supply's generating facilities are primarily located in Pennsylvania, West Virginia, Virginia and Ohio.
Within the Regulated Distribution segment's portfolio, 210 MW consist of JCP&L's 50% ownership interest in the Yards Creek hydroelectric facility in New Jersey; and 3,580 MW consist of MP's facilities, including 487 MW from AGC's Bath County, Virginia hydroelectric facility that MP partially owns and 11 MW of MP's 0.49% entitlement from OVEC's generation output. MP's facilities are concentrated primarily in West Virginia.
Utility Regulation
State Regulation
Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, 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.
Federal Regulation
With respect to their wholesale services and rates, the Utilities, AE Supply, ATSI, AGC, FES, FG, NG, PATH and TrAIL are subject to regulation by FERC. Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require ATSI, JCP&L, ME, MP, PE, PN, WP and TrAIL to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of ATSI, JCP&L, ME, MP, PE, PN, WP and TrAIL are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. See FERC Matters below.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities, AE Supply, FES, FG, NG, FGMUC, Buchanan Generation and Green Valley each have been authorized by FERC to sell wholesale power in interstate commerce at market rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to regulation by the relevant state commissions. As a condition to selling electricity on a wholesale basis at market-based rates, the Utilities, AE Supply, FES, FG, NG, FGMUC, Buchanan Generation and Green Valley, like other entities granted market-based rate authority, must file electronic quarterly reports with FERC listing their sales transactions for the prior quarter. However, consistent with its historical practice, FERC has granted AE Supply, FES, FG, NG, FGMUC, Buchanan Generation and Green Valley a waiver from certain reporting, record-keeping and accounting requirements that typically apply to traditional public utilities. Along with market-based rate authority, FERC also granted AE Supply, FES, FG, NG, FGMUC, Buchanan Generation and Green Valley blanket authority to issue securities and assume liabilities under Section 204 of the FPA.
The nuclear generating facilities owned and leased by NG, OE and TE, and operated by FENOC, are subject to extensive regulation by the NRC. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the licenses. FENOC is the licensee for the operating nuclear plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NG’s plants. See Nuclear Regulation below.
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.
Regulatory Accounting
The Utilities, AGC, ATSI, PATH and TrAIL recognize, as regulatory assets and regulatory liabilities, costs which FERC and the various state utility commissions, as applicable, have authorized for recovery/return from/to customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets and regulatory liabilities would have been charged to income as incurred. All regulatory assets and liabilities are expected to be recovered/returned from/to customers. Based on current ratemaking procedures, the Utilities, AGC, ATSI, PATH and TrAIL continue to collect cost-based rates for their transmission and distribution services and, in the case of PATH, for its abandoned plant, which remains regulated; accordingly, it is appropriate that the Utilities, AGC, ATSI, PATH and TrAIL continue the application of regulatory accounting to those operations. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded net regulatory assets or liabilities are removed from the balance sheet in accordance with GAAP.
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.
Maryland Regulatory Matters
PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption 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 Regulatory Matters
JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
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 Regulatory Matters
The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include:
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A base distribution rate freeze through May 31, 2016;
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Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;
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Economic development and assistance to low-income customers for the two-year plan period at levels established in the prior ESP;
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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);
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A requirement to provide power to non-shopping customers at a market-based price set through an auction process;
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Rider DCR that allows continued investment in the distribution system for the benefit of customers;
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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;
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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
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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:
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An eight-year term (June 1, 2016 - May 31, 2024);
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Contemplates continuing a base distribution rate freeze through May 31, 2024;
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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;
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Continuing to provide power to non-shopping customers at a market-based price set through an auction process;
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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;
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Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;
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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;
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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;
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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;
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An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;
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An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval;
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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;
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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
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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.
Pennsylvania Regulatory Matters
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.
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 Regulatory Matters
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.
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.
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.
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:
*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.
Capital Requirements
The centerpiece of FirstEnergy's regulated investment strategy is the Energizing the Future transmission expansion plan, with an initial phase that includes $4.2 billion in investments from 2014 to 2017 to modernize FirstEnergy's transmission system. 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 $1 billion. Planned capital expenditures for 2016 for Regulated Distribution, CES, and Corporate/Other will be dependent upon the outcome of the Ohio Companies' ESP IV and remain subject to Board approval.
Actual capital expenditures for 2015 by operating company and reportable segment are shown in the following tables. Such costs include expenditures for the improvement of existing facilities and for the construction of transmission lines, distribution lines and substations, and other assets.
(1)
Includes an increase of approximately $127 million related to the capital component of the non-cash pension and OPEB mark-to-market adjustment.
The following table presents scheduled debt repayments for outstanding long-term debt as of December 31, 2015, excluding capital leases for the next five years. PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered.
The following tables display consolidated operating lease commitments as of December 31, 2015.
(1)
PNBV purchased a portion of the lease obligation bonds associated with certain sale and leaseback transactions. These arrangements effectively reduce lease costs related to those transactions.
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. In the future, FirstEnergy may consider equity issuances to fund capital requirements in the regulated operations.
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.
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 $4.1 billion.
In January 2016, FirstEnergy’s Board of Directors declared a quarterly dividend of $0.36 per share of outstanding common stock. The dividend is payable March 1, 2016, to shareholders of record at the close of business on February 5, 2016. This dividend equates to an indicated annual dividend of $1.44 per share and is consistent with the dividends declared in 2015.
Nuclear Operating Licenses
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.
The following table summarizes the current operating license expiration dates for FES' nuclear facilities in service.
Nuclear Regulation
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.
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.
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.
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 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.
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.
Fuel Supply
FirstEnergy currently has coal contracts with various terms to acquire approximately 21.5 million tons of coal for the year 2016 which is approximately 100% of its estimated 2016 coal requirements. This contract coal is produced primarily from mines located in Ohio, Pennsylvania, and West Virginia. The contracts expire at various times through 2028. See Environmental Matters for additional information pertaining to the impact of increased environmental regulations on coal supply and transportation contracts applicable to certain deactivated coal-fired generating units.
FirstEnergy has contracts for all uranium requirements through 2018 and a portion of uranium material requirements through 2024. Conversion services contracts fully cover requirements through 2018 and partially fill requirements through 2024. Enrichment services are contracted for essentially all of the enrichment requirements for nuclear fuel through 2020. A portion of enrichment requirements is also contracted for through 2024. Fabrication services for fuel assemblies are contracted for both Beaver Valley units through 2020 and Davis-Besse through 2025 and through the current operating license period for Perry.
On-site spent fuel storage facilities are currently adequate for all FENOC operating units. An on-site dry cask storage facility has been constructed at Beaver Valley sufficient to extend spent fuel storage capacity through the end of current operating licenses at Beaver Valley Unit 1 and Beaver Valley Unity 2. Davis-Besse is planning to resume dry cask storage operations in 2017 which will extend on-site spent fuel storage capacity through the end of its recently extended operating license. Perry completed plant modification for dry cask storage in 2012, loaded spent fuel into dry cask storage in 2012 and 2014 (referred to as a loading campaign), and has planned to conduct additional dry cask storage loading campaigns that will provide for sufficient spent fuel storage capacity through 2046 (end of current operating license plus a 20-year operating license extension).
The Federal Nuclear Waste Policy Act of 1982 provided for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NG has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE
submitted the license application for Yucca Mountain to the NRC on June 3, 2008. The current Administration has stated the Yucca Mountain repository will not be completed and a Federal review of potential alternative strategies has been performed.
In light of this uncertainty, FirstEnergy has made arrangements for storage capacity as a contingency for the continuing delays of the DOE acceptance of spent fuel for disposal.
Natural gas demand at the combined cycle and peaking units is forecasted at approximately 30 million cubic feet in 2016. Fuel oil and natural gas are also used to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecasted to remain so. Requirements are expected to average approximately 9 million gallons per year over the next five years.
System Demand
The 2015 maximum hourly demand for each of the Utilities was:
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OE-5,391 MW on July 29, 2015;
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Penn-983 MW on July 29, 2015;
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CEI-4,057 MW on August 19, 2015;
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TE-2,149 MW on September 8, 2015;
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JCP&L-5,789 MW on July 20, 2015;
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ME-2,770 MW on July 20, 2015;
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PN-3,024 MW on February 19, 2015;
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MP-2,031 MW on January 7, 2015;
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PE-3,631 MW on February 20, 2015; and
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WP-3,942 MW on February 20, 2015.
Supply Plan
Regulated Commodity Sourcing
Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service or BGS supply is secured through a statewide competitive procurement process approved by the NJBPU. Default service for the Ohio Companies, Pennsylvania Companies and PE's Maryland jurisdiction are provided through a competitive procurement process approved by the PUCO (under the ESP), PPUC (under the DSP) and MDPSC (under the SOS), respectively. If any supplier fails to deliver power to any one of those Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a LSE. West Virginia electric generation continues to be regulated by the WVPSC.
Unregulated Commodity Sourcing
The CES segment, through FES and AE Supply, primarily provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES and AE Supply provide the power requirements of their competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES and AE Supply have retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey, serving both affiliated and non-affiliated companies. FES and AE Supply provide energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. Geographically, most of FES’ and AE Supply's obligations are in the PJM market area where all of their respective generation facilities are located.
Regional Reliability
All of FirstEnergy's facilities are located within the PJM Region and operate under the reliability oversight of a regional entity known as RFC. This regional entity operates under the oversight of NERC in accordance with a delegation agreement approved by FERC.
Competition
Within FirstEnergy’s Regulated Distribution segment, generally there is no competition for electric distribution service in the Utilities’ respective service territories in Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York. Additionally, there has traditionally been no competition for transmission service in PJM. However, pursuant to FERC’s Order No. 1000 and subject to state and local siting and permitting approvals, non-incumbent developers now can compete for certain PJM transmission projects in the service territories of FirstEnergy’s Regulated Transmission segment. This could result in additional competition to build transmission facilities in the Regulated Transmission segment’s service territories while also allowing the Regulated Transmission segment the opportunity to seek to build facilities in non-incumbent service territories.
FirstEnergy's CES segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, through FES and AE Supply. In these markets, the CES segment competes: (1) to provide retail generation service directly to end users; (2) to provide wholesale generation service to utilities, municipalities and co-operatives, which, in turn, resell to end users; and (3) in the wholesale market.
Seasonality
The sale of electric power is generally a seasonal business and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at those times. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
Research and Development
The Utilities, FES, FG, FENOC and ATSI participate in the funding of EPRI, which was formed for the purpose of expanding electric R&D under the voluntary participation of the nation’s electric utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, and delivery, efficient management of energy use, environmental effects and energy analysis. The majority of EPRI’s R&D programs and projects are directed toward business solutions and their applications to problems facing the electric utility industry.
FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant
operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.
* Indicates position held at least since January 1, 2011
(E) Denotes executive officer of FES
(J) Denotes executive officer of FG
(A) Denotes executive officer of FE
(F) Denotes executive officer of FENOC
(K) Denotes executive officer of OE
(B) Denotes executive officer of FESC
(G) Denotes executive officer of AGC
(L) Denotes executive officer of ATSI
(C) Denotes executive officer of OE, CEI and TE
(H) Denotes executive officer of MP, PE and WP
(M) Denotes executive officer of CEI
(D) Denotes executive officer of ME, PN and Penn
(I) Denotes executive officer of TrAIL and FET
Employees
As of December 31, 2015, FirstEnergy’s subsidiaries had 15,781 employees located in the United States as follows:
As of December 31, 2015, the IBEW, the UWUA and the OPEIU unions collectively represented approximately 6,900 of FirstEnergy's employees. There are 22 CBAs between FirstEnergy's subsidiaries and its unions, most of which have three year terms. In 2015, certain of FirstEnergy's subsidiaries reached new agreements on CBAs with four different IBEW locals, covering approximately 1,680 employees. These contracts will expire in 2018 and 2019. Additionally, in early 2016, PN reached a new agreement with IBEW local 459, covering approximately 425 employees, which will expire in 2021.
On July 1, 2015, IBEW Local 29, which represents approximately 17 employees at the Beaver Valley nuclear plant, ratified a new agreement that will expire September 30, 2018. On October 14, 2015, IBEW Local 777 CC, which represents approximately 161 call center employees in Reading, PA, ratified a new agreement that will expire on October 31, 2018. On November 12, 2015, IBEW Local 1289, which represents approximately 1,086 employees at JCP&L, ratified a new agreement that will expire on October 31, 2018. On November 24, 2015, IBEW Local 245, which represents approximately 416 employees of TE, the Davis-Besse nuclear plant and the Bay Shore generating station, ratified a new agreement that will expire on October 31, 2019.
The agreement with IBEW Local 272, which represents approximately 238 employees at the Bruce Mansfield Plant, expired on February 15, 2014. On October 27, 2015, following nearly two years of bargaining, FirstEnergy declared impasse and implemented terms and conditions of employment from its last comprehensive offer to settle. FirstEnergy continues to engage in negotiations with IBEW Local 272, and work continuation plans are in place in the event of a work stoppage. The agreement with UWUA Local 270, which represents approximately 76 employees at the Perry Nuclear Plant expired on November 16, 2015. The parties continue to negotiate for a new contract and work continuation plans are in place in the event of a work stoppage.
FirstEnergy Website and Other Social Media Sites and Applications
Each of the registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through the "Investors" page of FirstEnergy’s Internet website at www.firstenergycorp.com. The public may read and copy any reports or other information that the registrants file with the SEC at the SEC's public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the SEC's public reference room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.
These SEC filings are posted on FirstEnergy's website as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post additional important information including press releases, investor presentations and notices of upcoming events, under the "Investors" section of FirstEnergy’s Internet website and recognize FirstEnergy’s Internet website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and RSS feeds on the "Investors" page of FirstEnergy's Internet website or through push alerts from FirstEnergy Investor Relations apps for Apple Inc.'s iPad® and iPhone® devices, which can be installed for free at the Apple® online store. FirstEnergy also uses Twitter® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means
of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s Internet website, posted on FirstEnergy's Facebook® page or disseminated through Twitter®, and any corresponding applications, shall not be deemed incorporated into, or to be part of, this report.
ITEM 1A.
ITEM 1A.
RISK FACTORS
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrants' businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. Additional information on risk factors is included in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Registrant and Subsidiaries” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to Business Operations
We Have Taken a Series of Actions to Focus Our Growth on Our Regulated Operations. Whether This Will Deliver the Desired Result is Subject to Certain Risks Which Could Adversely Affect Profitability and our Financial Condition in the Future
We focus on capitalizing on investment opportunities available to our regulated operations - particularly in transmission - as we focus on delivering enhanced customer service and reliability. The success of these efforts will depend, in part, on successful recovery of our transmission investments. Factors that may affect rate recovery of our transmission investments may include: (1) whether the investments are included in PJM's RTEP; (2) FERC's evolving policies with respect to incentive rates for transmission assets; (3) FERC's evolving policies with respect to the base ROE component of transmission rates, as articulated in FERC's Opinion No. 531 and related orders; (4) consideration of the objections of those who oppose such investments and their recovery; and (5) timely development, construction, and operation of the new facilities.
The success of these efforts will also depend, in part, on our achieving positive outcomes in the ESP IV before the PUCO and any future distribution rate cases and transmission rate filings. Any denial of, or delay in, the approval of ESP IV or any future distribution or transmission rate request could restrict us from fully recovering our cost of service, may impose risk on operations, and could have a material adverse effect on our regulatory strategy. In addition, CES' continued operation of the generating units included in the PPA portion of the ESP IV is uncertain.
Our efforts also could be impacted by our ability to finance the proposed expansion projects while maintaining adequate liquidity. There can be no assurance that our efforts to reflect a more regulated business profile will deliver the desired result which could adversely affect our future profitability and financial condition.
We Are Subject to Risks Arising from the Operation of Our Power Plants and Transmission and Distribution Equipment
Operation of generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, human error in operations or maintenance, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operation and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our sales obligations. Moreover, if we were unable to perform under contractual obligations, including, but not limited to, our coal and coal transportation contracts, penalties or liability for damages could result.
FES, FG, OE and TE are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FG, OE and TE have a maximum exposure to loss under those provisions of approximately $1.2 billion for FES, $368 million for OE and $192 million for TE. In addition, new and certain existing environmental requirements may force us to shut down such generating facilities or change their operating status, either temporarily or permanently, if we are unable to comply with such environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are unreasonable.
Failure to Provide Safe and Reliable Service and Equipment Could Result in Serious Injury or Loss of Life That May Harm Our Business Reputation and Adversely Affect our Operating Results
We are obligated to provide safe and reliable service and equipment in our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. However, our employees, contractors and the general public may be exposed to dangerous environments, due to the nature of our operations. Failure to provide safe and reliable service and equipment due to a number of factors, including, equipment failure, accidents and weather, could result in serious injury or loss of life that may harm our business reputation and adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
Continued Pressure on Commodity Prices Including, but Not Limited to Natural Gas, Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive retail and wholesale markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Competition and changes in the short or long-term market price of electricity, which are affected by changes in other commodity costs and other factors including, but not limited to, weather, energy efficiency mandates, DR initiatives and deactivations and retirements at power production facilities, may impact our results of operations and financial position by decreasing sales margins or increasing the amount we pay to purchase power to satisfy our sales obligations in the states in which we do business. We are exposed to risk from the volatility of the market price of natural gas. Our ability to sell at a profit is highly dependent on the price of natural gas. With low natural gas prices, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices, so the margins we realize from sales will be lower and, on occasion, we may curtail or cease operation of marginal plants. The availability of natural gas and issues related to its accessibility may have a long-term material impact on the price of natural gas. In addition, deterioration or weakness in the global economy has led to lower international demand for coal, oil and natural gas, which has lowered fossil fuel prices and may continue to put downward pressure on electricity prices.
We Are Exposed to Operational, Price and Credit Risks Associated With Marketing and Selling Products in the Power Markets That We Do Not Always Completely Hedge Against
We purchase and sell power at the wholesale level under market-based rate tariffs authorized by FERC, and also enter into agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages, including significant penalties under PJM's Capacity Performance market reform. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages and penalties could be significant. A single outage could result in penalties that exceed capacity revenues for a given unit in a given year. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.
We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected. In addition, these risk management related contracts could require the posting of additional collateral in the event market prices or market conditions change.
The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market value of these contracts if a counterparty fails to perform or if there is limited liquidity of these contracts in the market.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs and Impose Additional Regulatory Burdens
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) was enacted into law in July 2010 with the primary objective of increasing oversight of the United States financial system, including the regulation of most financial transactions, swaps and derivatives. Dodd-Frank requires CFTC and SEC rulemaking to implement such provisions. Although the CFTC and the SEC have completed certain of their rulemaking, other rulemaking remains.
We rely on the OTC derivative markets as part of our program to hedge the price risk associated with our power portfolio. As a qualified end-user, we are required to comply with regulatory obligations under Dodd-Frank, which includes record-keeping, reporting requirements and the clearing of some transactions that we would otherwise enter into over-the-counter and the posting of margin. Also, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swap market to decrease. These rules could impede our ability to meet our hedge targets in a cost-effective manner. FirstEnergy cannot predict the future impact Dodd-Frank rulemaking will have on its results of operations, cash flows or financial position.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Subject to Uncertainties, and We Could Suffer Economic Losses Despite Our Efforts to Manage and Mitigate Our Risks
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposure in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts, and also to pay significant penalties under PJM's Capacity Performance market reform. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, actual events may lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the creditworthiness of counterparties, future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be adversely affected if the judgments and assumptions underlying those calculations prove to be inaccurate.
Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning, Which Could Have a Material Adverse Effect on Our Business, Results of Operations and Financial Condition
We are subject to the risks of nuclear generation, including but not limited to the following:
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the potential harmful effects on the environment and human health, including loss of life, resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;
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limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations, including any incidents of unplanned radiological release, or those of others in the United States;
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uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and
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uncertainties with respect to the technological and financial aspects of spent fuel storage and decommissioning nuclear plants, including but not limited to, waste disposal at the end of their licensed operation and increases in minimum funding requirements or costs of decommissioning.
The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. See "Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Affect Our Business and Financial Condition" below and Note 15, Commitments, Guarantees and Contingencies - Environmental Matters of the Combined Notes to the Consolidated Financial Statements. Any one of these risks relating to our nuclear generation could have a material adverse effect on our business, results of operations and financial condition.
The Outcome of Litigation, Arbitration, Mediation, and Similar Proceedings, Involving Our Business, or That of One or More of Our Operating Subsidiaries, is Unpredictable and an Adverse Decision in Any Material Proceeding Could Have a Material Adverse Effect on Our Financial Position and Results of Operations
We are involved in a number of litigation, arbitration, mediation, and similar proceedings including, but not limited to, such proceedings relating to certain fuel and fuel transportation contracts as described in Note 15, Commitments, Guarantees, and Contingencies, of the Combined Notes to the Consolidated Financial Statements. These and other matters may divert financial and management resources that would otherwise be used to benefit our operations. Further, no assurances can be given that the resolution of these matters will be favorable to us. If certain matters were ultimately resolved unfavorably to us, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.
In addition, we are sometimes subject to investigations and inquiries by various state and federal regulators due to the heavily regulated nature of our industry. Any material inquiry or investigation could potentially result in an adverse ruling against us, which could have a material adverse impact on our financial position and operating results.
We Have a Significant Percentage of Coal-Fired Generation Capacity Which Exposes Us to Risk from Regulations Relating to Coal and CCRs
Approximately 55% of FirstEnergy's generation fleet capacity is coal-fired. Historically, coal-fired generating plants have greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to air emissions, including GHGs, and CCR disposal, than other types of electric generation facilities. In December 2014, the EPA finalized regulations for CCRs (non-hazardous waste), establishing national standards for the safe disposal of CCRs from electric generating plants. In August 2015, the EPA finalized the CPP requiring reductions in GHG emissions from existing electric generating plants. These legal requirements and any future initiatives could impose substantial additional costs and, in the case of GHG requirements, could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements.
Capital Market Performance and Other Changes May Decrease the Value of Pension Fund Assets, Decommissioning and Other Trust Funds, Which Then Could Require Significant Additional Funding
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other postemployment benefit plans. Certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pension and other obligations, requires significant judgment and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or that negatively impact the discount rate and increase the present value of liabilities may have significant impacts on the value of the pension, decommissioning and other trust funds, which could negatively impact our results of operations and financial position.
We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets
Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the perceived potential for exercise of market power and to ensure the markets function appropriately. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted, Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs and RTOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to our results of operations.
In addition, as with all utilities, potential concerns over transmission capacity could result in PJM or FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures that we may be unable to recover fully or at all.
FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs or RTOs in applicable markets will operate the transmission networks, and provide related services, efficiently.
Disruptions in Our Fuel Supplies and Changes in Our Fuel Transportation Needs Could Adversely Affect Our Relationships With Suppliers, Our Ability to Operate Our Generation Facilities or Lead to Business Disputes, Any of Which May Adversely Impact Financial Results
We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. We have long-term contracts in place for a majority of our coal supply and transportation needs, one of which runs through 2028 and certain of which relate to deactivated plants. We have asserted force majeure defenses for delivery shortfalls under certain of these agreements relating to our deactivated plants. One such agreement relates to the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain deactivated coal-fired power plants owned by FG, and this agreement is now in arbitration. Another such agreement relates to the delivery of 2.5 million tons annually through 2025 to an operating plant as well as a deactivated plant. In addition, in one coal supply agreement, FirstEnergy, through a subsidiary, has also asserted termination rights effective in 2015 and is in litigation with the counterparty.
We can provide no assurance that negotiations with counterparties, or any litigation or arbitration, will be favorably resolved. An adverse resolution of any of these material matters could have a material adverse impact on our financial position and results of operations. In addition, we may from time to time enter into new contracts, or renegotiate certain of these contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. In addition, if prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.
Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snowstorms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period and could have an adverse effect on our financial condition and results of operations.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required to provide the energy supply to fulfill this increased demand at fixed rates, which we expect would remain below the wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. A significant decrease in demand, resulting from factors including but not limited to increased customer shopping, more stringent energy efficiency mandates and increased DR initiatives could cause a decrease in the market price of power. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel
Our business follows economic cycles. Economic conditions impact the demand for electricity and declines in the demand for electricity will reduce our revenues. The regional economy in which our Utilities operate is influenced by conditions in industries in our business territories, e.g. shale gas, automotive, chemical, steel and other heavy industries, and as these conditions change, our revenues will be impacted. Additionally, the primary market areas of our CES segment overlap, to a large degree, with our Utilities' territories and hence its revenues are substantially impacted by the same economic conditions, such as changes in industrial demand.
The Recognition of Impairments of Goodwill, Long-Lived Assets, Including Certain Investments, Could Have an Adverse Effect on Our Results of Operations
We have approximately $6.4 billion of goodwill on our consolidated balance sheet as of December 31, 2015, of which $800 million is attributable to our CES segment. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. Key assumptions incorporated in the estimated cash flows used for the impairment analysis requiring significant management judgment include: discount rates, growth rates, future energy and capacity pricing, projected operating income, changes in working capital, projected capital expenditures, projected funding of pension plans, expected results of future rate proceedings, the impact of pending carbon and other environmental legislation and terminal multiples. Although the annual goodwill impairment test in 2015 resulted in a conclusion that goodwill was not impaired, the fair value of the CES reporting unit exceeded its carrying value by only approximately 10%. We are unable to predict whether future impairment charges to goodwill may be necessary.
In addition, we also review our long-lived assets and investments for impairment when circumstances indicate the carrying value of these assets may not be recoverable. For example, in 2015, we recorded a $362 million non-cash, pre-tax impairment charge associated with our investment in Global Holding, primarily as a result of distress in the coal market and industry. We are unable to predict whether impairments of one or more of our long-lived assets or investments may occur in the future. The actual timing and amounts of any impairments to goodwill, or long-lived assets in the future would depend on many factors, including interest rates, sector market performance, our capital structure, natural gas or other commodity prices, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable acquisitions, environmental regulations and other factors. A determination that goodwill, a long-lived asset, or other investments are impaired would result in a non-cash charge that could materially adversely affect our results of operations and capitalization.
We Face Certain Human Resource Risks Associated with Potential Labor Disruptions and/or With the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We must find ways to balance the retention of our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Further, a significant number of our physical workforce are represented by unions and while we believe that our relations with our employees are generally fair, we cannot provide assurances that the company will be completely free of labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, lockouts or that any labor disruption will be favorably resolved. Mitigating these risks could require additional financial commitments and the failure to retain or attract trained and qualified labor could have an adverse effect on our business.
Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures related to operation and maintenance expenses, including in the areas of health care and pension costs. We have experienced health care cost inflation in recent years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, discount rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. While we anticipate that our operation and maintenance expenses will continue to increase, if actual results differ materially from our assumptions, our costs could be significantly higher than expected which could adversely affect our future earnings and liquidity.
Our Results May be Adversely Affected by the Volatility in Pension and OPEB Expenses
FirstEnergy recognizes in income the change in the fair value of plan assets and net actuarial gains and losses for its defined Pension and OPEB plans. This adjustment is recognized in the fourth quarter of each year and whenever a plan is determined to qualify for a remeasurement, which could result in greater volatility in pension and OPEB expenses and may materially impact our results of operations.
Cyber-Attacks, Data Security Breaches and Other Disruptions to Our Information Technology Systems Could Compromise Our Business Operations, Critical and Proprietary Information and Employee and Customer Data, Which Could Have a Material Adverse Effect on Our Business, Financial Condition and Reputation
In the ordinary course of our business, we use and are dependent upon information technology systems that utilize sophisticated operational systems and network infrastructure to run all facets of our generation, transmission and distribution services. Additionally, we store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks. The secure maintenance of information and information technology systems is critical to our operations.
Over the last several years, there has been an increase in the frequency of cyber-attacks by terrorists, hackers, international activist organizations, countries and individuals. These and other unauthorized parties may attempt to gain access to our network systems or facilities, or those of third parties with whom we do business in many ways, including directly through our network infrastructure or through fraud, trickery, or other forms of deceiving our employees, contractors and temporary staff. Additionally, our information and information technology systems may be increasingly vulnerable to data security breaches, damage and/or interruption due to viruses, human error, malfeasance, faulty password management or other malfunctions and disruptions. Further, hardware, software, or applications we develop or procure from third parties may contain defects in design or manufacture or other problems that could unexpectedly compromise information and/or security.
Despite security measures and safeguards we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may be increasingly vulnerable to such attacks as a result of the rapidly evolving and increasingly sophisticated means by which attempts to defeat our security measures and gain access to our information technology systems may be made. Also, we may be at an increased risk of a cyber-attack and/or data security breach due to the nature of our business.
Any such cyber-attack, data security breach, damage, interruption and/or defect could: (i) disable our generation, transmission (including our interconnected regional transmission grid) and/or distribution services for a significant period of time; (ii) delay development and construction of new facilities or capital improvement projects; (iii) adversely affect our customer operations; (iv) corrupt data; and/or (v) result in unauthorized access to the information stored in our data centers and on our networks, including, company proprietary information, supplier information, employee data, and personal customer data, causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in economic loss and liability and harmful effects on the environment and human health, including loss of life. Additionally, because our generation, transmission and distribution services are part of an interconnected system, disruption caused by a cybersecurity incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our operations.
Although we maintain cyber insurance and property and casualty insurance, there can be no assurance that liabilities or losses we may incur will be covered under such policies or that the amount of insurance will be adequate. Further, as cyber threats become more difficult to detect and successfully defend against, there can be no assurance that we can implement adequate preventive measures, accurately assess the likelihood of a cyber-incident or quantify potential liabilities or losses. Also, we may not discover any data security breach and loss of information for a significant period of time after the data security breach occurs. For all of these reasons, any such cyber incident could result in significant lost revenue, the inability to conduct critical business functions and serve customers for a significant period of time, the use of significant management resources, legal claims or proceedings, regulatory penalties, increased regulation, increased capital costs, increased protection costs for enhanced cyber security systems or personnel, damage to our reputation and/or the rendering of our internal controls ineffective, all of which could adversely effect our business and financial condition.
Physical Acts of War, Terrorism or Other Attacks on any of Our Facilities or Other Infrastructure Could Have an Adverse Effect on Our Business, Results of Operations and Financial Condition
As a result of the continued threat of physical acts of war, terrorism, or other attacks in the United States, our electric generation, fuel storage, transmission and distribution facilities and other infrastructure, including nuclear and other power plants, transformer and high voltage lines and substations, or the facilities or other infrastructure of an interconnected company, could be direct targets of, or indirect casualties of, an act of war, terrorism, or other attack, which could result in disruption of our ability to generate, purchase, transmit or distribute electricity for a significant period of time, otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such disruption or incident could result in a significant decrease in revenue, significant additional capital and operating costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our assets over and above any available insurance reimbursement, higher insurance deductibles, higher premiums and more restrictive insurance policies, greater regulation with higher attendant costs, generally, and significant damage to our reputation, which could have a material adverse effect on our business, results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters or Could be Canceled Which Could Adversely Affect Our Business and Results of Operations
Our business plan calls for execution of extensive capital investments in electric generation, transmission and distribution, including but not limited to our Energizing the Future transmission expansion program. We may be exposed to the risk of substantial price increases in, or the adequacy or availability of, the costs of labor and materials used in construction, nonperformance of equipment and increased costs due to delays, including delays relating to the procurement of permits or approvals, adverse weather or environmental matters. We engage numerous contractors and enter into a large number of construction agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. Also,
because we enter into construction agreements for the necessary materials and to obtain the required construction related services, any cancellation by FirstEnergy of a construction agreement could result in significant termination payments or penalties. Any delays, increased costs or losses or cancellation of a construction project could adversely affect our business and results of operations, particularly if we are not permitted to recover any such costs in rates.
Changes in Technology and Regulatory Policies May Significantly Make Our Generating Facilities Less Competitive and Adversely Affect Our Results of Operations
We primarily generate electricity at large central station generation facilities. This method results in economies of scale and lower unit costs than newer generation technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in newer generation technologies will make them more cost-effective, or that changes in regulatory policy will create benefits that otherwise make these new technologies more competitive with central station electricity production. Increased competition, whether from such advances in technologies or from changes in regulatory policy, could result in permanent reductions in our historical load, adversely impact scheduling of generation, and decrease sales and revenues from our existing generation assets, which could have a material adverse effect on our results of operations.
Further, to the extent that new generation technologies are connected directly to load, bypassing the transmission and distribution systems, potential impacts could include decreased transmission and distribution revenues, stranded assets and increased uncertainty in load forecasting and integrated resource planning and could adversely affect our business and results of operations.
Certain FirstEnergy Companies May Not be Able to Meet Their Obligations to or on behalf of Other FirstEnergy Companies or Their Affiliates
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services and hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone. Certain FirstEnergy companies also provide guarantees to third party creditors on behalf of other FirstEnergy affiliate companies under transactions of the type described above or under financing transactions. Any failure to perform under such a guarantee by such FirstEnergy guarantor company or under the underlying transaction by the FirstEnergy company on whose behalf the guarantee was issued could have similar adverse impacts on one or both FirstEnergy companies or their affiliates.
Certain FirstEnergy Companies Have Guaranteed the Performance of Third Parties, Which May Result in Substantial Costs or the Incurrence of Additional Debt
Certain FirstEnergy companies have issued guarantees of the performance of others, which obligates such FirstEnergy companies to perform in the event that the third parties do not perform. For instance, FE is a guarantor under a syndicated senior secured term loan facility, under which Global Holding borrowed $300 million. In the event of non-performance by the third parties, FirstEnergy could incur substantial cost to fulfill this obligation and other obligations under such guarantees. Such performance guarantees could have a material adverse impact on our financial position and operating results.
Additionally, with respect to FEV's investment in Global Holding, due to distress in the coal market and industry, Global Holding could require additional capital from its owners, including FEV, to fund operations and meet its obligations under its term loan facility. These capital requirements could be significant and if other partners do not fund the additional capital, resulting in FEV increasing its equity ownership and obtaining the ability to direct the significant activities of Global Holding, FEV may be required to consolidate Global Holding, increasing FirstEnergy's long term debt by $300 million.
Energy Companies are Subject to Adverse Publicity Which Make Them Vulnerable to Negative Regulatory and Legislative Outcomes
Energy companies, including FirstEnergy's utility subsidiaries, have been the subject of criticism on matters including the reliability of their distribution services and the speed with which they are able to respond to power outages, such as those caused by storm damage. Adverse publicity of this nature, as well as negative publicity associated with the operation of nuclear and/or coal-fired facilities or proceedings seeking regulatory recoveries may cause less favorable legislative and regulatory outcomes and damage our reputation, which could have an adverse impact on our business.
Risks Associated With Regulation
To the Extent Our Policies to Control Costs Designed to Mitigate Low Energy, Capacity and Market Prices are Unsuccessful, We Could Experience a Negative Impact on Our Results of Operations and Financial Condition
Since 2012, as part of our ongoing comprehensive review of competitive operations related to, among other things, plant economics, we have deactivated more than 5,000 MW of competitive generation. To the extent our policies designed to control our costs, or other facets of our financial plan, are unsuccessful, we could experience a negative impact on our results of operations and financial condition. To address problems in the capacity market, PJM in December 2014 proposed significant market reforms, including its
Capacity Performance proposal. 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 the August 2015 PJM RPM auction incorporated the Capacity Performance reforms. To the extent PJM’s Capacity Performance market reforms do not work as intended, energy and capacity market prices may remain volatile and low.
Any Denial of, or Delay in, Cost Recovery Resulting from OE’s, CEI’s and TE’s Pending ESP IV Before the PUCO May Impose Risks on Our Operations and May Negatively Impact Our Credit Ratings, Results of Operations and Financial Condition
ESPs may be filed in Ohio as a means to establish the mechanism by which generation rates are set and may also include other provisions related to distribution and transmission service, all of which is subject to the approval of the PUCO. As a result, OE, CEI, and TE may not be authorized to implement all of the rates, riders, and mechanisms for which they are seeking approval, or there may be a delay in such authorization. OE, CEI, and TE filed their proposed ESP IV entitled Powering Ohio's Progress that, including the impact of stipulations filed in the case, contemplates continuing a base distribution rate freeze and includes proposals to continue their Rider DCR mechanism and competitive bidding process for non-shopping load and to undertake and implement an Economic Stability Program provision, which includes an eight-year FERC-jurisdictional PPA with FES for the output of Sammis, Davis-Besse and FES' share of OVEC, designed to provide customers retail rate stability against market prices over a longer term.
OE, CEI, and TE expect to receive a decision on their ESP IV 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 vigorously to defend against such challenges. The failure to obtain approval of the ESP IV PPA or a successful challenge could negatively and materially impact the future results of operations and financial condition of FE and FES.
Complex and Changing Government Regulations, Including Those Associated With Rates and Rate Cases Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
Our transmission and operating utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may be decreased as a result of actions taken by FERC or by one or more of the state regulatory commissions in which our utility subsidiaries operate. Also, these rates may not be set to recover such utility's expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments or expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner. Further, there can be no assurance that we will retain the expected recovery in future rate cases.
In addition, as a U.S. corporation, we are subject to U.S. laws, Executive Orders, and regulations administered and enforced by the U.S. Department of Treasury and the Department of Justice restricting or prohibiting business dealings in or with certain nations and with certain specially designated nationals (individuals and legal entities). If any of our existing or future operations or investments, including our joint venture investment in Signal Peak or our continued procurement of uranium from existing suppliers, are subsequently determined to involve such prohibited parties we could be in violation of certain covenants in our financing documents and unless we cease or modify such dealings, we could also be in violation of such U.S. laws, Executive Orders and sanctions regulations, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
State Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial of or Delay in, Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition
Each of the Utilities' retail rates are set by its respective regulatory agency for utilities in the state in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC through traditional, cost-based regulated utility ratemaking. As a result, any of the Utilities may not be permitted to recover its costs and, even if it is able to do so, there may be a significant delay between the time it incurs such costs and the time it is allowed to recover them. Factors that may affect outcomes in the distribution rate cases include: (i) the value of plant in service; (ii) authorized rate of return; (iii) capital structure (including hypothetical capital structures); (iv) depreciation rates; (v) the allocation of shared costs, including consolidated deferred income taxes and income taxes payable across the FirstEnergy utilities; (vi) regulatory approval of rate recovery mechanisms for capital spending programs (including for example accelerated deployment of smart meters); and (vii) the accuracy of forecasts used for ratemaking purposes in "future test year"
cases. FirstEnergy can provide no assurance that any base rate request filed by any of the Utilities, including the pending ESP IV in Ohio will be granted in whole or in part. Any denial of, or delay in, any base rate request could restrict the applicable Utility from fully recovering its costs of service, may impose risks on its operations, and may negatively impact its results of operations and financial condition. In addition, to the extent that any of the Utilities seeks rate increases after an extended period of frozen or capped rates, pressure may be exerted on the applicable legislators and regulators to take steps to control rate increases, including through some form of rate increase moderation, reduction or freeze. Any related public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues that are ultimately obtained, and the ability of the Utility to recover costs. Such uncertainty may restrict operational flexibility and resources, and reduce liquidity and increase financing costs.
Federal Rate Regulation May Delay or Deny Full Recovery of Costs and Impose Risks on Our Operations. Any Denial of or Delay in Cost Recovery Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition.
FERC policy currently permits recovery of prudently-incurred costs associated with wholesale power rates and the expansion and updating of transmission infrastructure within its jurisdiction. If FERC were to adopt a different policy regarding recovery of transmission costs or if transmission needs do not continue or develop as projected, our strategy of investing in transmission could be affected. If FERC were to lower the rate of return it has authorized for FirstEnergy's cost-based wholesale power rates or transmission investments and facilities, it could reduce future earnings and cash flows, and impact our financial condition.
Regulatory Changes in the Electric Industry Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of regulatory initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities and competitive energy providers conduct their business. FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry.
If any regulatory efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further regulatory efforts to modify our business or the industry.
The Business Operations of Our Subsidiaries That Sell Wholesale Power Are Subject to Regulation by FERC and Could be Adversely Affected by Such Regulation
FERC granted certain FirstEnergy generating subsidiaries authority to sell electric energy, capacity and ancillary services at market-based rates. These orders also granted waivers of certain FERC accounting, record-keeping and reporting requirements, as well as, for certain of these subsidiaries, waivers of the requirements to obtain FERC approval for issuances of securities. FERC’s orders that grant this market-based rate authority reserve with FERC the right to revoke or revise that authority if FERC subsequently determines that these companies can exercise market power in transmission or generation, or create barriers to entry, or have engaged in prohibited affiliate transactions. In the event that one or more of FirstEnergy's market-based rate authorizations were to be revoked or adversely revised, the affected FirstEnergy subsidiary(ies) may be subject to sanctions and penalties, and would be required to file with FERC for authorization of individual wholesale sales transactions, which could involve costly and possibly lengthy regulatory proceedings and the loss of flexibility afforded by the waivers associated with the current market-based rate authorizations.
There Are Uncertainties Relating to Our Participation in RTOs
RTO rules could affect our ability to sell energy and capacity produced by our generating facilities to users in certain markets. The rules governing the various regional power markets may change from time to time, which could affect our costs or revenues. In some cases these changes are contrary to our interests and adverse to our financial returns. The prices in day-ahead and real-time energy markets and RTO capacity markets have been volatile and RTO rules may contribute to this volatility.
All of our generating assets currently participate in PJM, which conducts RPM auctions for capacity on an annual planning year basis. The prices our generating companies can charge for their capacity are determined by the results of the PJM auctions, which are impacted by the supply and demand of capacity resources and load within PJM and also may be impacted by transmission system constraints and PJM rules relating to bidding for DR, energy efficiency resources, and imports, among others. Auction prices could fluctuate substantially over relatively short periods of time. To the extent PJM's Capacity Performance market reforms do not work as intended, energy and capacity market prices may remain volatile and low. We cannot predict the outcome of future auctions, but if the auction prices are sustained at low levels, our results of operations, financial condition and cash flows could be adversely impacted.
We incur fees and costs to participate in RTOs. Administrative costs imposed by RTOs, including the cost of administering energy markets, may increase. To the degree we incur significant additional fees and increased costs to participate in an RTO, and are limited with respect to recovery of such costs from retail customers, our results of operations and cash flows could be significantly impacted.
We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.
As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
Energy Efficiency and Peak Demand Reduction Mandates and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption. Such conservation programs could result in load reduction and adversely impact our financial results in different ways. To the extent conservation results in reduced energy demand or significantly slows the growth in demand, the value of our competitive generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery time frame in the states where we operate. Currently, only our Ohio Companies recover lost distribution revenues that result between distribution rate cases. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We have already been adversely impacted by reduced electric usage due in part to energy conservation efforts such as the use of efficient lighting products such as CFLs, halogens and LEDs. We could also be adversely impacted if any future energy price increases result in a decrease in customer usage. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Additionally failure to meet regulatory or legislative requirements to reduce energy consumption or otherwise increase energy efficiency could result in penalties that could adversely affect our results.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs
Where federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation does not also provide for adequate cost recovery, it could result in significant changes in our business, including REC purchase costs, purchased power and capital expenditures. Such mandatory renewable portfolio requirements may have an adverse effect on our financial condition or results of operations.
The EPA is Conducting NSR Investigations at a Number of Generating Plants that We Currently or Formerly Owned, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations, including, for example, the applicability of EPA's NSR programs. Under the CAA, modification of our generation facilities in a manner that results in increased emissions could subject our existing generation facilities to the far more stringent new source standards applicable to new generation facilities.
The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work considered by the companies to be routine maintenance. EPA has investigated alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position but we are unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with New Environmental Laws, Including Limitations on GHG Emissions, Could Adversely Affect Cash Flow and Profitability
Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for, among other things, installation and operation of pollution control equipment, emissions monitoring and fees, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. We may be forced to shut down other facilities or change their operating status, either temporarily or permanently, if we are unable to comply with these or other existing or new environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are unreasonable.
In December 2011, the EPA finalized MATS to establish emission standards for, among other things, mercury, PM and HCI, for electric generating units. The costs associated with MATS compliance, and other environmental laws, is substantial. As a result of
a comprehensive review of FirstEnergy's coal-fired generating facilities in light of MATS and other expanded requirements, we deactivated twenty-six (26) older coal-fired generating units in 2012, 2013, and 2015.
Moreover, new environmental laws or regulations including, but not limited to EPA's CPP requiring reductions of GHG emissions and CWA effluent limitations imposing more stringent water discharge regulations, or changes to existing environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of certain of our generation facilities, we will not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, including but not limited to, our assumptions regarding estimated compliance costs, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations or new interpretations of longstanding requirements, even if caused by factors beyond our control, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.
At the international level, the Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and 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. Further, due to the uncertainty of control technologies available to reduce GHG emissions, any other legal obligation that requires substantial reductions of GHG emissions could result in substantial additional costs, adversely affecting cash flow and profitability, and raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.
We Could be Exposed to Private Rights of Action Relating to Environmental Matters Seeking Damages Under Various State and Federal Law Theories
Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other relief. For example, claims have been made against certain energy companies alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. While FirstEnergy is not a party to this litigation, it, and/or one of its subsidiaries, could be named in other actions making similar allegations. An unfavorable ruling in any such case could result in the need to make modifications to our coal-fired plants or reduce emissions, suspend operations or pay money damages or penalties. Adverse rulings in these or other types of actions could have an adverse impact on our results of operations and financial condition and could significantly impact our operations.
Various Federal and State Water and Solid, Non-Hazardous and Hazardous Waste Regulations May Require Us to Make Material Capital Expenditures
In September 2015, the EPA finalized new, more stringent effluent limits for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water under the CWA. The EPA has also established performance standards under the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants, specifically, reducing impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) to a 12% annual average and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system) using site-specific controls based on studies to be submitted to permitting authorities. FirstEnergy is studying the cost and effectiveness of various control options to divert fish away from its plants' cooling water intake systems. Depending on the results of such studies and implementation of impingement and entrainment performance standards by permitting authorities, the future costs of compliance with these standards may require material capital expenditures.
We Are or May be Subject to Costs of Remediation of Environmental Contamination at Current or Formerly Owned Facilities
We may be subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We are currently involved in a number of proceedings relating to sites where hazardous substances have been released and we may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former MGP operations are one source of such costs. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining or Renewing the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC
We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Potential NRC Regulation in Response to the Incident at Japan's Fukushima Daiichi Nuclear Plant Could Adversely Affect Our Business and Financial Condition
As a result of the NRC's investigation of the incident at the Fukushima Daiichi nuclear plant, the NRC has begun to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. For example, as a follow up to the NRC near-term Task Force's review and analysis of the Fukushima Daiichi accident, in January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the task force. The NRC has also issued orders and guidance that increases procedural and testing requirements, requires physical modifications to our plants and is expected to increase future compliance and operating costs. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. It is also possible that the NRC could suspend or otherwise delay nuclear relicensing proceedings. The impact of any such regulatory actions could adversely affect FirstEnergy's financial condition or results of operations.
The Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Utilities' service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions, and in some instances we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our operations and operating results. Climate change poses other financial risks as well. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased rates, revenues, margins or earnings.
Future Changes in Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position.
Changes in Local, State or Federal Tax Laws Applicable To Us or Adverse Audit Results or Tax Rulings, and Any Resulting Increases in Taxes and Fees, May Adversely Affect Our Results of Operations, Financial Condition and Cash Flows
FirstEnergy is subject to various local, state and federal taxes, including income, franchise, real estate, sales and use and employment-related taxes. We exercise significant judgment in calculating such tax obligations, booking reserves as necessary to reflect potential adverse outcomes regarding tax positions we have taken and utilizing tax benefits, such as carryforwards and credits. Additionally, various tax rate and fee increases may be proposed or considered in connection with such changes in local, state or federal tax law. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by legislatures or regulatory bodies. Any such changes, or any adverse tax audit results or adverse tax rulings on positions taken by FirstEnergy or its subsidiaries could have a negative impact on its results of operations, financial condition and cash flows.
Risks Associated With Financing and Capital Structure
Volatility or Unfavorable Conditions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Immediate Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. We also deposit cash in short-term investments. Volatility in the capital and credit markets could adversely affect our ability to draw on our credit facilities and cash. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
Fluctuations in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant foreign or domestic financial institutions or foreign governments could adversely affect our access to liquidity needed for our business. Unfavorable conditions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
Energy markets depend heavily on active participation by multiple counterparties, which could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our or Our Subsidiaries' Financing Costs, Ability to Access Capital and Requirement to Post Collateral and the Ability to Continue Successfully Implementing Our Retail Sales Strategy
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings of variable interest rate tax-exempt debt issued to finance certain of our facilities. Similar future disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that are beyond our risk management processes. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs that our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our or our subsidiaries' credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. A downgrade in our credit rating, or that of our subsidiaries, could also preclude certain retail customers from executing supply contracts with us and therefore impact our ability to successfully implement our retail sales strategy. Furthermore, a downgrade could increase the cost of such capital by causing us to incur higher interest rates and fees associated with such capital. A rating downgrade would increase our interest expense on certain of FirstEnergy's long-term debt obligations and would also increase the fees we pay on our various existing credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital.
The Stability of Counterparties Could Adversely Affect Us
We are exposed to the risk that counterparties that owe us money, power, fuel or other commodities could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses. Some of our agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to FirstEnergy or its subsidiaries. If the counterparties to these arrangements fail to perform, we may have a right to receive the proceeds from the credit support provided, however the credit support may not always be adequate to
cover the related obligations. In such event, we may incur losses in addition to amounts, if any, already paid to the counterparties, including by being forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by customers or other counterparties may be greater than the estimates predict, which could have a material adverse effect on our results of operations and financial condition.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries' Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow, including our ability to pay dividends and service debt, is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility and transmission subsidiaries are regulated by various state utility and federal commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state and federal commissions could attempt to impose restrictions on the ability of our utility and transmission subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts They May be Paid
Our Board of Directors will continue to regularly evaluate our common stock dividend and determine an appropriate dividend each quarter taking into account such factors as, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
The first mortgage indentures for the Ohio Companies, Penn, MP, PE, WP, FG and NG constitute direct first liens on substantially all of the respective physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See Note 6, Leases, and Note 11, Capitalization, of the Combined Notes to Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FG’s and NG’s properties.
FirstEnergy controls the following generation sources as of February 16, 2016, shown in the table below. Except for the leasehold interests, OVEC participation and wind and solar power arrangements referenced in the footnotes to the table, substantially all of FES' competitive generating units are owned by NG (nuclear) and FG (non-nuclear); the regulated generating units are owned by JCP&L and MP.
(1)
Includes FE's leasehold interest of 93.83% (779 MW) from non-affiliates.
(2)
Represents FG's 4.85%, AE Supply's 3.01% and MP's 0.49% entitlement based on their participation in OVEC.
(3)
Includes OE’s leasehold interest of 2.60% (24 MW) from non-affiliates of which FES purchases all the output pursuant to full output cost-of-service PSAs.
(4)
Includes OE’s leasehold interest of 3.75% (48 MW) from non-affiliates of which FES purchases all the output pursuant to full output cost-of-service PSAs.
(5)
Represents Buchanan Energy's 50% interest. Buchanan Energy is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan Energy have equal ownership interests in Buchanan Generation, LLC. AE Supply operates and dispatches 100% of Buchanan Generation, LLC's 86 MWs.
(6)
Represents AGC's 40% interest in Bath County, a pumped-storage hydroelectric station. The station is operated by 60% owner Virginia Electric and Power Company. AGC is 59% owned by AE Supply and 41% owned by MP.
(7)
Represents JCP&L’s 50% ownership interest.
(8)
Includes 167 MW from leased facilities and 329 MW under power purchase agreements.
The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. FirstEnergy's overhead and underground transmission lines aggregate 24,211 pole miles.
The Utilities’ electric distribution systems include 268,682 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of approximately 154,612,802 kV-amperes.
All of FirstEnergy's generation, transmission and distribution assets operate in PJM.
FirstEnergy’s distribution and transmission systems as of December 31, 2015, consist of the following:
(1)
Circuit Miles
(2)
Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers.
(3)
Represents transmission line assets of 69 kV and greater located in the service territories of OE, Penn, CEI and TE.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
Reference is made to Note 14, Regulatory Matters, and Note 15, Commitments, Guarantees and Contingencies of the Combined Notes to Consolidated Financial Statements for a description of certain legal proceedings involving FirstEnergy and FES.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included in Item 6.
ITEM 6.
SELECTED FINANCIAL DATA
(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.
Closing prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN
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.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES
Forward-Looking Statements: This Form 10-K includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following:
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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.
•
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, (b) this Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, and (c) other factors discussed herein and in other filings with the SEC by the registrants. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
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):
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.
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.
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:
•
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:
*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.
*Includes revenues from the results of incremental/transitional capacity auctions, bilateral transactions and capacity transfer rights.
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%.
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.
FINANCIAL OVERVIEW
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.
•
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.
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 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.
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:
(1) Consists primarily of interest on stand-alone holding company debt, none-core business related activity and corporate income taxes.
Summary of Results of Operations - 2015 Compared with 2014
Financial results for FirstEnergy’s business segments in 2015 and 2014 were as follows:
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:
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:
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:
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.
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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.
•
Other operating expenses increased $161 million primarily due to:
•
Higher transmission expenses of $73 million primarily due to an increase in network transmission expenses at the Ohio Companies, partially offset by lower congestion expenses at MP. The differences between current retail transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.
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Increased regulated generation operating and maintenance expenses of $7 million, reflecting higher planned outage expenses in 2015 compared to 2014.
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Higher retirement benefit costs of $22 million, reflecting higher net benefit costs before the pension and OPEB mark-to-market adjustment described below.
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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.
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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.
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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.
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Net regulatory asset amortization increased $260 million primarily due to:
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Recovery of storm costs in New Jersey, Pennsylvania, and West Virginia effective with the implementation of new rates as discussed above ($66 million),
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Higher energy efficiency program cost recovery ($66 million),
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Lower deferral of TTS costs in West Virginia ($37 million),
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Higher amortizations of above-market NUG costs in Pennsylvania and New Jersey ($36 million),
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Lower deferral of West Virginia vegetation management expenses ($31 million),
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Higher default generation service cost amortization ($28 million), and
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Recovery of Pennsylvania legacy meter costs ($22 million); partially offset by
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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.
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.
Revenues by transmission asset owner are shown in the following table:
Operating Expenses -
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.
Other Expenses -
Other expenses increased $41 million due to increased interest expense resulting from debt issuances of $1.0 billion at FET and $400 million at ATSI, the proceeds of which, in part, paid off short term borrowings as well as lower capitalized financing costs.
Income Taxes -
Regulated Transmission’s effective tax rate was 36.9% 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 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.
The decrease in total revenues resulted from the following sources:
The following tables summarize the price and volume factors contributing to changes in revenues:
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:
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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.
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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.
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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.
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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.
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General taxes decreased $31 million primarily due to lower gross receipts taxes associated with decreased retail sales volumes.
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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.
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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.
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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.
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:
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:
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:
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.
The following table summarizes the price and volume factors contributing to the $415 million increase in generation revenues in 2014 compared to 2013:
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:
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Fuel expense was $190 million higher in 2014 primarily related to increased generation as a result of the October 2013 Harrison/Pleasants asset transfer.
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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.
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.
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Higher vegetation management expenses in West Virginia of $33 million, which were deferred for future recovery per authorization of the WVPSC.
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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.
•
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.
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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,
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Decreased energy efficiency amortization reflecting a rate decrease associated with certain programs for the Pennsylvania Companies ($67 million),
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Lower default generation service and NUG costs recovery in Pennsylvania ($48 million),
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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.
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:
Operating Expenses -
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.
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:
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.
•
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.
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 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.
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:
(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:
(1)
FE and the Utilities.
(2)
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:
(1)
No limitations.
(2)
No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.
(3)
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.
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.
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:
(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:
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.
Changes in Cash Position
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;
•
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:
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 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 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.
CONTRACTUAL OBLIGATIONS
As of December 31, 2015, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:
(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).
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:
(1)
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
(2)
Includes guarantees of $4 million for nuclear decommissioning funding assurances, $7 million for railcar leases, and $6 million for various leases.
(3)
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 sheets.
(5)
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.
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:
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 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.
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.
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:
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and ICE quotes.
(3)
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.
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%.
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.
CREDIT RISK
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.
Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.
OUTLOOK
STATE REGULATION
Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate
codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.
MARYLAND
PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption 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;
•
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);
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Contemplates continuing a base distribution rate freeze through May 31, 2024;
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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;
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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;
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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;
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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;
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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;
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An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;
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An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval;
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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;
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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
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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.
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.
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.
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.
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:
*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.
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.
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.
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.
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
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 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.
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:
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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.
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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.
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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.
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Discount Rate: A discount rate of 8.25%, based on a capital structure, return on debt and return on equity of selected comparable companies.
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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 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.
FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FE. FES provides energy-related products and services to retail and wholesale customers, and through its principal subsidiaries, FG and NG, owns or leases, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding AE Supply and MP), and owns, through its subsidiary, NG, FirstEnergy’s nuclear generation facilities. FENOC, a wholly owned subsidiary of FE, operates and maintains the nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FG and NG and 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’ revenues are derived primarily from sales to individual retail customers, sales to customers in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. The demand for electricity produced and sold by FES, along with the price of that electricity, is principally impacted by conditions in competitive power markets, global economic activity as well as economic activity and weather conditions in the Midwest and Mid-Atlantic regions of the United States. In 2016 and going forward, FES expects to target approximately 65 to 75 million MWHs in annual contract sales with a projected 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. As of December 31, 2015, committed contract sales for calendar year 2016 and 2017 were 61 million MWHs and 38 million MWHs, respectively.
FES is exposed to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices may be impacted by the prices of other commodities, including coal and natural gas, and energy efficiency and DR programs, as well as regulatory and legislative actions, such as MATS among other factors. FES attempts to mitigate the market risk inherent in its energy position by economically hedging its exposure and continuously monitoring various risk measurement metrics to ensure compliance with its risk management policies.
For additional information with respect to FES, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: FirstEnergy's Business and Executive Summary, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk and Outlook.
Results of Operations
Operating results increased $326 million in 2015 compared to 2014. In 2014, FES sold certain hydroelectric power stations resulting in an after-tax gain of $110 million. Excluding the impact of this gain as well as the impact of lower Pension and OPEB mark-to-market adjustments, year-over-year operating results improved primarily from higher capacity revenue 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.
Revenues -
Total revenues decreased $1,139 million in 2015, compared to 2014, primarily due to decreased sales volumes in line with FES' 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.
The change in total revenues resulted from the following sources:
The following table summarizes the price and volume factors contributing to changes in revenues:
Lower sales volumes in the Direct, Governmental Aggregation and Mass Market sales channels primarily reflect FES' 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 $181 million was due to lower volumes, partially offset by higher rates associated with recent POLR auctions. Structured Sales increased $37 million primarily due to low market prices that increased the gains on various structured financial sales contracts and higher structured transaction volumes.
Wholesale revenues increased $508 million due to an increase in capacity revenue from higher capacity prices, an 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 $76 million primarily due to lower congestion revenue resulting from the market conditions associated with the extreme weather events in 2014.
Other revenue increased $19 million primarily due to higher lease revenues from additional equity interests in affiliated sale and leasebacks repurchased in November 2014. FES earns lease revenue associated with the equity interests it purchased.
Operating Expenses -
Total operating expenses decreased by $1,946 million in 2015 compared to 2014.
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in 2015 compared with 2014:
(1) In 2014, realized losses on financially settled wholesale sales contracts of $252 million resulting from higher market prices were netted in purchased power.
Fossil and nuclear fuel costs decreased $382 million, primarily due to lower economic dispatch of fossil units resulting from low spot market energy prices and an increase in fossil outages. Lower unit prices also contributed to the decrease, resulting from the
suspension of the DOE nuclear disposal fee, effective May 16, 2014, and lower unit prices for coal. Additionally, fuel costs were impacted by a decrease in settlement and termination costs related to coal and transportation contracts. In 2015, a pre-tax gain of approximately $12 million was recognized associated with the elimination of an obligation under an existing coal contract. In 2014, terminations and settlements associated with damages on coal and transportation contracts resulted in a pre-tax loss of $138 million as compared to no charges in 2015.
Affiliated purchased power costs increased $82 million primarily associated with net losses on financially settled contracts with AE Supply resulting from lower market prices in 2015 as compared to 2014.
Non-affiliated purchased power costs decreased $1,087 million due to lower volumes ($1,256 million), partially offset by increased prices, net of financials ($16 million) and higher capacity expenses ($153 million). 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. Lower volumes were primarily due to decreased load requirements resulting from lower sales as discussed above, partially offset by decreased fossil generation as discussed above. The increase in capacity expense, which is a component of FES' retail price, was primarily the result of higher capacity rates associated with FES' retail sales obligations.
Other operating expenses decreased $294 million in 2015, compared to 2014 due to the following:
•
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 $185 million primarily due to lower operating reserve and market-based ancillary costs associated with market conditions resulting from the extreme weather events in 2014.
•
Other operating expenses decreased $186 million primarily due to a $142 million decrease in mark-to-market expenses on commodity contract positions reflecting lower market prices and a $78 million decrease in retail-related costs, partially offset by a $34 million impairment charge associated with non-core assets.
Pension and OPEB mark-to-market adjustment decreased $240 million to $57 million, which was impacted by lower than expected asset returns, partially offset by an increase in the discount rate used to measure benefit obligations.
General taxes decreased $30 million primarily due to lower gross receipts taxes associated with decreased retail sales volumes.
Other Expense -
Total other expense increased $72 million in 2015 compared to 2014, primarily due to higher OTTI on NDT investments, partially offset by the absence of a $6 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 $177 million ($116 million after-tax) associated with the sale of certain hydroelectric facilities on February 12, 2014.
Income Taxes (Benefits) -
FES’ effective tax rate was 44.2% and 38.8% in 2015 and 2014, respectively. The increase in the effective tax rate is primarily due to an increase in reserves associated with uncertain tax positions and the absence of tax benefits recognized in 2014 associated with changes to state apportionment factors, partially offset by lower valuation allowances recorded on state and municipal NOL carryforwards.
Market Risk Information
FES 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
FES 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. FES uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
Sources of information for the valuation of commodity derivative contracts assets and liabilities as of December 31, 2015 are summarized by year in the following table:
(1)
Represents exchange traded New York Mercantile Exchange futures and options.
(2)
Primarily represents contracts based on broker and ICE quotes.
FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. 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 12 months.
Interest Rate Risk
FES’ exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for FES’ investment portfolio and debt obligations.
Equity Price Risk
NDT funds have been established to satisfy NG’s nuclear decommissioning obligations. Included in FES' NDT are fixed income, equities and short-term investments carried at market values of approximately $810 million, $378 million and $137 million, respectively, as of December 31, 2015, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $38 million reduction in fair value as of December 31, 2015. NG recognizes in earnings the unrealized losses on AFS securities held in its NDT as OTTI. A decline in the value of FES' NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FES evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FES may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FES monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FES 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 FES has a legally enforceable right of offset. FES 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 FES' energy contract counterparties maintain investment-grade credit ratings.
Retail Credit Risk
FES' 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.
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, FES' retail credit risk may be adversely impacted.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A relating to market risk is set forth in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 8.
ITEM 8.
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.
MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Solutions 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.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy Corp.'s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’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.
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
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of FirstEnergy Solutions Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows, present fairly, in all material respects, the financial position of FirstEnergy Solutions 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 Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2016
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
*
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.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
*
Includes excise tax collections of $44 million, $69 million and $78 million in 2015, 2014 and 2013, respectively.
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Combined Notes to Consolidated Financial Statements are an integral part of these financial statements.
FIRSTENERGY CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.
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.
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 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.
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:
(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.
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:
(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:
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.
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 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:
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.
•
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.
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.
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.
2. ACCUMULATED OTHER COMPREHENSIVE INCOME
The changes in AOCI for the years ended December 31, 2015, 2014 and 2013 for FirstEnergy are shown in the following table:
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 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:
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 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.
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.
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.
(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)
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:
As of December 31, 2015 and 2014, the OPEB trust investments measured at fair value were as follows:
(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)
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.
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:
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:
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:
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:
FES’ share of the pension and OPEB net (liability) asset as of December 31, 2015 and 2014, was as follows:
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:
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:
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.
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:
(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 common stock (restricted stock) activity for the year ended December 31, 2015, was as follows:
(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:
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.
EDCP
Under the EDCP, covered employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash can vary depending upon the form of the award, the duration of the deferral and other factors. Certain types of deferrals such as dividend equivalent units, Short-Term Incentive Awards, and performance share awards are required to be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement. In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years, effective for deferrals made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant.
DCPD
Under the DCPD, members of the Board of Directors can elect to allocate all or a portion of their equity retainers to deferred stock and their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $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.
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:
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.
Accumulated deferred income taxes as of December 31, 2015 and 2014 are as follows:
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.
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute is utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. As of December 31, 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:
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):
General Taxes
6. LEASES
FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.
In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years, 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:
The future minimum capital lease payments as of December 31, 2015 are as follows:
FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2015, are as follows:
FES' future minimum operating lease payments as of December 31, 2015, are as follows:
7. INTANGIBLE ASSETS
As of December 31, 2015, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following:
(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.
•
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.
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:
9. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:
Level 1
-
Quoted prices for identical instruments in active market
Level 2
-
Quoted prices for similar instruments in active market
-
Quoted prices for identical or similar instruments in markets that are not active
-
Model-derived valuations for which all significant inputs are observable market data
Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
Level 3
-
Valuation inputs are unobservable and significant to the fair value measurement
FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation 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.
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:
(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.
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:
(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:
(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:
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:
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.
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:
(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:
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:
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:
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 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.
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.
As of December 31, 2015 and December 31, 2014, no commodity or interest rate derivatives were designated as cash flow hedges.
Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of December 31, 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
As of December 31, 2015 and 2014, no interest rate swaps were outstanding.
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.
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:
(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:
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2015:
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:
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.
PREFERRED AND PREFERENCE STOCK
FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2015, as follows:
As of December 31, 2015, and 2014, there were no preferred or preference shares outstanding.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31, 2015 and 2014:
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 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.
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.
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.
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:
(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.
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:
(1)
FE and the Utilities
(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:
(1)
No limitations.
(2)
No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.
(3)
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:
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:
The following table summarizes the changes to the ARO balances during 2015 and 2014:
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;
•
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 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.
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.
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.
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.
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:
*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:
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 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.
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.
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:
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).
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.
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
18. SEGMENT INFORMATION
FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES.
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments.
During the fourth quarter of 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.
Segment Financial Information
19. DISCONTINUED OPERATIONS
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.
20. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarizes certain consolidated operating results by quarter for 2015 and 2014.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The respective management of FirstEnergy and FES, with the participation of each respective registrant's chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of their registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer of each registrant have concluded that each respective registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.
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, the respective management of each registrant conducted an evaluation of the effectiveness of their registrant’s internal control over financial reporting under the supervision of each respective registrant’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the respective management of each registrant concluded that their registrant’s internal control over financial reporting was effective as of December 31, 2015. The effectiveness of FirstEnergy’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 included herein. The effectiveness of internal control over financial reporting of FES as of December 31, 2015, has not been audited by the registrant's independent registered public accounting firm.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2015, there were no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy's or FES' internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
On February 16, 2016, upon recommendation of its Compensation Committee, the FE Board of Directors (Board) adopted the ESTIP. The ESTIP is a component of the ICP 2015, which was approved by shareholders at the 2015 Annual Meeting of Shareholders. ESTIP awards are cash-based awards granted pursuant to the terms and conditions of the ICP 2015 and payment is based on the successful achievement of corporate financial and operational KPIs. Participants in the ESTIP consist of the executive officers of FE who are deemed to be "covered persons" under Section 162(m) of the Internal Revenue Code of 1986, as amended, and any regulations promulgated thereunder and any other officer or employee selected by the Compensation Committee of the Board (Compensation Committee), which administers the ESTIP. Participants in the ESTIP are ineligible to participate in any other short-term incentive program sponsored by FE, except as provided for in the ICP 2015.
Financial and operational KPIs for the ESTIP are developed in accordance with the performance measures identified in the ICP 2015, and the performance period for awards is January 1st to December 31st of a given year, unless otherwise determined by the Compensation Committee. The Compensation Committee establishes (i) the KPIs that must be satisfied in order for a participant to receive an award for such performance period, including the relative weightings for each KPI with respect to each participant, and (ii) the threshold, target and maximum award opportunity for each participant, which are expressed as a percentage of the participant's base salary. The ESTIP payout will be zero if FE performance is below threshold. Executives are evaluated based on KPIs applicable to FE and their responsibilities within FE.
ESTIP awards are paid no later than March 15th of the year following the year in which the award is earned. If the participant's employment terminates prior to the end of the performance period due to Retirement (as defined in the ESTIP), Disability (as defined in the ICP 2015), death, or termination by FE without Cause (as defined in the ICP 2015), the participant is entitled to receive a pro-rated portion of his or her ESTIP award that would have been earned, based on actual KPI performance, had he or she remained employed through the performance period. However, if the participant is entitled to receive all or a portion of his or her ESTIP award pursuant to an individual agreement or separate severance or change in control plan in which he or she participates, then his or her ESTIP award would be paid pursuant to such individual agreement or plan to avoid any duplication of payments.
The Compensation Committee has the discretion to adjust the payment amount under any award granted under the ESTIP downward (but not upward) without the participant's consent, notwithstanding FE's or the participant's actual performance against the award's performance goals, either on a formula or discretionary basis, or a combination of the two. Subject to the foregoing, the Board or the Compensation Committee may at any time amend, suspend, discontinue, or terminate the ESTIP, so long as no such amendment,
suspension, discontinuance or termination materially and adversely affects the rights of any participant in respect of any performance period that has already commenced.
The foregoing description of the ESTIP is qualified in its entirety by reference to the full and complete terms of the ESTIP, which is attached as Exhibit 10-56 to this Annual Report on Form 10-K and incorporated herein by reference, and the ICP 2015, which was filed as Appendix A to FE's Definitive Proxy Statement filed April 1, 2015 and is incorporated herein by reference.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 is incorporated herein by reference to FirstEnergy's 2016 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2016 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by Item 12 is incorporated herein by reference to FirstEnergy’s 2016 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated herein by reference to FirstEnergy’s 2016 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
A summary of the audit and audit-related fees for services rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2015 and 2014, are as follows:
(1)
Professional services rendered for the audits of the registrants' annual financial statements and reviews of unaudited financial statements included in the registrants' Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters, agreed upon procedures and consents for financings and filings made with the SEC.
(2)
Professional services rendered in 2015 and 2014 related to SEC Regulation AB. Also, in 2014, professional services rendered related to additional agreed upon procedures for the audit of compliance with certain DOE grants, risk assurance and the audit of PE's cost allocation manual.
Tax Fees and All Other Fees
There were no tax services performed by PricewaterhouseCoopers LLP in 2015 or 2014. PricewaterhouseCoopers LLP performed no other services in 2015 or 2014, however, the registrants paid approximately $15,000 (fifteen-thousand) and $5,000 (five-thousand) in software subscription fees to PricewaterhouseCoopers LLP for 2015 and 2014, respectively.
Additional information required by this item is incorporated herein by reference to FirstEnergy’s 2016 Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report on Form 10-K:
1. Financial Statements:
Management’s Report on Internal Control Over Financial Reporting for FirstEnergy Corp. and FES is listed under Item 8 herein.
Reports of Independent Registered Public Accounting Firm for FirstEnergy Corp. and FES are listed under Item 8 herein.
The financial statements filed as a part of this report for FirstEnergy Corp. and FES are listed under Item 8 herein.
2. Financial Statement Schedules:
Reports of Independent Registered Public Accounting Firm as to Schedules are included herein on pages:
Schedule II - Consolidated Valuation and Qualifying Accounts are included herein on pages:
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FirstEnergy has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FES has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.
SCHEDULE II
FIRSTENERGY CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013
(1)
Represents recoveries and reinstatements of accounts previously written off.
(2)
Represents the write-off of accounts considered to be uncollectible.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FIRSTENERGY CORP.
BY:
/s/ Charles E. Jones
Charles E. Jones
President and Chief Executive Officer
Date: February 16, 2016
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Charles E. Jones
Charles E. Jones
President and Chief Executive Officer and Director
(Principal Executive Officer)
/s/ George M. Smart
George M. Smart
Director
(Non-Executive Chairman of Board)
/s/ James F. Pearson
/s/ K. Jon Taylor
James F. Pearson
K. Jon Taylor
Executive Vice President and Chief Financial Officer
Vice President, Controller and Chief Accounting Officer
(Principal Financial Officer)
(Principal Accounting Officer)
/s/ Paul T. Addison
/s/ Donald T. Misheff
Paul T. Addison
Donald T. Misheff
Director
Director
/s/ Michael J. Anderson
/s/ Thomas N. Mitchell
Michael J. Anderson
Thomas N. Mitchell
Director
Director
/s/ William T. Cottle
/s/ Ernest J. Novak, Jr.
William T. Cottle
Ernest J. Novak, Jr.
Director
Director
/s/ Robert B. Heisler, Jr.
/s/ Christopher D. Pappas
Robert B. Heisler, Jr.
Christopher D. Pappas
Director
Director
/s/ Julia L. Johnson
/s/ Luis A. Reyes
Julia L. Johnson
Luis A. Reyes
Director
Director
/s/ Ted J. Kleisner
/s/ Jerry Sue Thornton
Ted J. Kleisner
Jerry Sue Thornton
Director
Director
Date: February 16, 2016
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FIRSTENERGY SOLUTIONS CORP.
BY:
/s/ Donald R. Schneider
Donald R. Schneider
President
Date: February 16, 2016
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Donald R. Schneider
/s/ James F. Pearson
Donald R. Schneider
James F. Pearson
President
Executive Vice President and Chief Financial Officer, Director
(Principal Executive Officer)
(Principal Financial Officer)
/s/ Charles E. Jones
/s/ K. Jon Taylor
Charles E. Jones
K. Jon Taylor
Director
Vice President and Controller
(Principal Accounting Officer)
/s/ James H. Lash
James H. Lash
Director
Date: February 16, 2016
Exhibit Index
FirstEnergy
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FirstEnergy has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.
FES
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, FES has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but hereby agrees to furnish to the SEC on request any such documents.