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Regulatory Matters | 12 Months Ended
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Dec. 31, 2016
Regulated Operations [Abstract] |
REGULATORY MATTERS | REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. MARYLAND PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings set in PE's plan for 2016, and increasing 0.2% per year thereafter to reach 2%. The costs of the 2015-2017 plan are expected to be approximately $70 million, of which $43 million was incurred through December 31, 2016. PE continues to recover program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. Initial comments in the proceeding were filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. NEW JERSEY JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L filed to participate as a respondent in that proceeding. Briefing has been completed. The oral argument was held on October 25, 2016. On April 28, 2016, JCP&L filed tariffs with the NJBPU proposing a general rate increase associated with its distribution operations to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. The filing requested approval to increase annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30, 2016. On November 30, 2016, JCP&L submitted to the ALJ a Stipulation of Settlement achieved with all the intervening parties providing for an annual $80 million distribution revenue increase, effective January 1, 2017. The ALJ filed an Initial Decision concluding that the Stipulation of Settlement should be approved, and the NJBPU approved the Stipulation of Settlement on December 12, 2016. As part of the Stipulation of Settlement the intervening parties agreed that JCP&L can accelerate the amortization of the 2012 major storm expenses (approximately $19 million annually) that are recovered through the SRC to achieve full recovery by December 31, 2019. On November 23, 2016, JCP&L filed an Amendment to its January 15, 2016 SRC Filing with the NJBPU, requesting that JCP&L be able to accelerate the amortization of the 2012 major storm expenses as agreed to in the Stipulation of Settlement, and a Stipulation of Settlement with NJBPU Staff and the Division of Rate Counsel regarding the SRC Filing was filed on December 27, 2016. The NJBPU approved this Stipulation of Settlement at the January 25, 2017 public meeting. OHIO The Ohio Companies currently operate under an ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinions and Orders issued on March 31, 2016 and October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. Other material terms of ESP IV include the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs, an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016), a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045, and contributions, totaling $51 million, to fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territory, and a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers, and to establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications for rehearing on the Ohio Companies’ ESP IV with the PUCO. On September 6, 2016, while the applications for rehearing were still pending before the PUCO, the OCC and NOAC filed a notice of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner Entries on the parties’ applications for rehearing. On September 16, 2016, the Ohio Companies intervened and filed a motion to dismiss the appeal. The PUCO resolved such applications for rehearing in the October 12, 2016 Opinion and Order. The OCC and NOAC appeal remains pending before the Ohio Supreme Court. On November 10, 2016 and November 14, 2016, several parties, including the Ohio Companies, filed additional applications for rehearing on the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On December 7, 2016, the PUCO granted the applications for rehearing for further consideration of the matters specified in the applications for rehearing. The matter remains pending before the PUCO. For additional information, see “FERC Matters - Ohio ESP IV PPA,” below. Under ORC 4928.66, the Ohio Companies were required to implement energy efficiency programs that achieved a total annual energy savings of 1,990 GWHs and total peak demand reduction of 486 MWs in 2015. On May 12, 2016, the Ohio Companies filed their Energy Efficiency and Peak Demand Reduction Program Status Report indicating compliance with their 2015 statutory benchmarks. In 2016, the Ohio Companies estimated the annual energy savings target and peak demand reduction target will be comparable to the 2015 targets due to the energy efficiency requirements under SB310, which amended ORC 4928.66 to freeze the energy efficiency and peak demand reduction benchmarks for 2015 and 2016. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. The hearings were held in January 2017. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except 2015 and 2016 that remain at the 2014 level. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. The matter remains pending before the PUCO. PENNSYLVANIA The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn. Following the expiration of the current DSPs, the Pennsylvania Companies will operate under new DSPs for the June 1, 2017 through May 31, 2019 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the new DSPs, the supply will be provided by wholesale suppliers through a mix of 12- and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. In addition, the new DSPs include modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans were effective through May 31, 2016. Total Phase II costs of these plans were $174 million and are recoverable through the Pennsylvania Companies' reconcilable EE&C riders. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies' Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five-year period of 2016 to 2020 for the following costs: WP- $88.34 million; PN- $56.74 million; Penn- $56.35 million; and ME- $43.44 million. On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. On June 9, 2016, the PPUC approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation among customers. The four proceedings were consolidated by the ALJ. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, discussed below, the PPUC referred the issue of whether ADIT should be included in DSIC calculations to the consolidated DSIC proceeding. On February 2, 2017, the parties to the consolidated DSIC proceeding submitted a Joint Settlement to the ALJ to resolve issues referred to by the ALJ in its June 9, 2016 Order, subject to PPUC approval, and would not result in any refund or reallocation among customers. The ADIT issue will be considered separately from the issues resolved in the Joint Settlement Petition of February 2, 2017, and is the sole issue to be litigated in the consolidated DSIC proceeding through a procedural schedule to be determined by the ALJ. On April 28, 2016, each of the Pennsylvania Companies filed tariffs with the PPUC proposing general rate increases associated with their distribution operations to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. The filings requested approval to increase annual operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. As a result of the enactment of Act 40 of 2016 that terminated the practice of making a CTA when calculating a utility’s federal income taxes for ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7, 2016, that quantified the value of the elimination of the CTA and outlined their plan for investing 50 percent of that amount in rate base eligible equipment as required by the new law. Formal settlement agreements for each of the Pennsylvania Companies were filed on October 14, 2016, which proposed increases in annual operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP. One item related to the calculation of DSIC rates was reserved for briefing, with briefs filed by two parties. On November 21, 2016, the ALJ issued a Recommended Decision recommending approval of the settlement agreements and dismissal of the one issue reserved for briefing. Exceptions to that Recommended Decision were filed by one party on December 1, 2016, and reply exceptions were filed by the Pennsylvania Companies on December 8, 2016. On January 19, 2017, the PPUC issued an order approving the settlements and referring the reserved issue to the Pennsylvania Companies’ consolidated DSIC proceeding. On February 3, 2017, one party filed a Petition for Reconsideration or Clarification relating to the limited issue of the scope of the record to be transferred to the DSIC proceeding, discussed above. The outcome of this request will not affect the new rates which took effect on January 27, 2017. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. On March 31, 2016, MP and PE filed with the WVPSC seeking approval of their Phase II energy efficiency program including three MP and PE energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of the Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. A unanimous settlement was reached by the parties on all issues and presented to the WVPSC on August 18, 2016. An order approving the settlement in full without modification was issued by the WVPSC on September 23, 2016. The Phase II program began initial implementation in November 2016. The Staff of the WVPSC and the Consumer Advocate Division filed a Show Cause petition on August 5, 2016, requesting that the WVPSC order MP and PE to file and implement RFPs for all future capacity and energy requirements above 100 MWs and that they comply with an RFP settlement provision from the Harrison power station acquisition. MP and PE filed a timely response to the petition arguing for dismissal on September 7, 2016. On October 17, 2016, the WVPSC denied the petition filed by the Staff of the WVPSC and the Consumer Advocate Division and dismissed the case. On August 16, 2016, MP and PE filed their annual ENEC case proposing an annual increase in rates of approximately $65 million effective January 1, 2017, which is a 4.7% increase over existing rates. The increase is comprised of a $119 million under-recovered balance as of June 30, 2016, and a projected $54 million over-recovery for the 2017 rate effective period. The parties reached a unanimous settlement providing for a $25 million increase beginning January 1, 2017 and keeping ENEC rates at the same level for a two year period. The settlement was presented to the WVPSC at a hearing on November 9, 2016. On December 9, 2016, the WVPSC approved the settlement as submitted. On August 22, 2016, MP and PE filed an application for approval of a modernization and improvement plan for coal-fired boilers at electric power plants and cost-recovery surcharge proposing an approximate $6.9 million annual increase in rates to be effective May 1, 2017, which is a 0.5% increase over existing rates. The filing is in response to recent legislation by the West Virginia Legislature permitting accelerated recovery of costs related to modernizing and improving coal-fired boilers, including costs related to meeting environmental requirements and reducing emissions. The filing was supplemented on September 28, 2016, to add two additional projects, resulting in an approximate $7.4 million annual increase in rates. The Staff of the WVPSC filed a motion to dismiss the case arguing the new statute was not meant to recover these types of projects, but the WVPSC set the case for hearing for February 21-23, 2017. As part of the annual ENEC settlement described above, the parties agreed that MP and PE will increase ENEC rates to provide for a return of and on MATS/CSPR capital costs incurred during 2016-2017. Accordingly, MP and PE withdrew this case as part of the ENEC approval. On December 30, 2015, MP filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP finding that IRPs are informational and that it must not approve or disapprove the IRP. MP issued a RFP to address its generation shortfall identified in the IRP on December 16, 2016 along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. MP expects to execute definitive agreements with selected respondent(s) and file the appropriate applications with the WVPSC and FERC by March 15, 2017. RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and its subsidiaries, AE Supply, FENOC, ATSI and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy, including FES, believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy, including FES, occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy, including FES, develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's, including FES, part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS Ohio ESP IV PPA On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV. ESP IV included a proposed Rider RRS, which would flow through to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV, and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016. On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review the ESP IV PPA under Section 205 of the FPA. On April 27, 2016, FERC issued an order granting the complaint, prohibiting any transactions under the ESP IV PPA pending authorization by FERC, and directing FES to submit the ESP IV PPA for FERC review if the parties desired to transact under the agreement. FES and the Ohio Companies did not file the ESP IV PPA for FERC review but rather agreed to suspend the ESP IV PPA. FES and the Ohio Companies subsequently advised FERC of this course of action. On January 19, 2017, FERC issued an order accepting compliance filings by FES, its subsidiaries, and the Ohio Companies updating their respective market-based rate tariffs to clarify that affiliate sales restrictions under the tariffs apply to the ESP IV PPA, and also that the ESP IV PPA does not affect certain other waivers of its affiliate restrictions rules FERC previously granted these entities. On May 2, 2016, the Ohio Companies filed an Application for Rehearing with the PUCO that included a modified Rider RRS proposal that did not involve a FERC-jurisdictional PPA. Several parties subsequently filed protests and comments with FERC alleging, among other things, that the modified Rider RRS constituted a "virtual PPA". FERC rejected these protests in its January 19, 2017 order accepting the updated market-based rate tariffs of FES, its subsidiaries, and the Ohio Companies discussed below. On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protest to the amended complaint, demonstrating that the question of the proper role for state participation in generation development should be addressed in the PJM stakeholder process. This proceeding remains pending before FERC. PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. The PJM TOs responded to the protesting parties' various pleadings and motions. The settlement is pending before FERC. RTO Realignment On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis. Separately, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC and certain United States appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which FERC denied on May 19, 2016. On July 15, 2016, the MISO TOs filed an appeal of FERC's orders with the Sixth Circuit. On November 16, 2016, the Sixth Circuit granted FirstEnergy's intervention on behalf of ATSI, the Ohio Companies, and PP, and a procedural schedule has been established. On a related issue, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. The requests for rehearing remain pending before FERC. In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under PJM Transmission Rates. The outcome of the proceedings that address the remaining open issues related to costs for the "Michigan Thumb" transmission project and "legacy RTEP" transmission projects cannot be predicted at this time. Transfer of Transmission Assets to MAIT On June 10, 2015, MAIT, a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the purposes of owning and operating all FERC-jurisdictional transmission assets of JCP&L, ME and PN following the receipt of all necessary state and federal regulatory approvals. In February and August 2016, respectively, FERC and the PPUC granted the authorization for PN and ME to contribute their transmission assets to MAIT at book value, together with the approval of related intercompany agreements, including MAIT’s participation in FirstEnergy’s regulated companies' money pool. FirstEnergy subsequently withdrew its request for authorization before the NJBPU to also transfer JCP&L's transmission assets to MAIT. On October 28, 2016, MAIT and PJM submitted joint applications to FERC requesting authorization for (i) PJM to update its Tariff and other agreements to reflect the withdrawal of ME and PN as TOs, and (ii) MAIT to become a participating PJM TO. FERC approval would authorize MAIT to be a PJM TO, and would permit PJM to implement MAIT’s formula rate on MAIT’s behalf. On January 26, 2017, FERC issued an order granting the requested authorization and MAIT now owns and operates the transmission assets of ME and PN. On January 31, 2017, MAIT issued membership interests to FET, PN and ME in exchange for their respective cash and asset contributions. On October 14 and 28, 2016, MAIT submitted applications to FERC requesting authorization to issue equity, short-term debt, and long-term debt. On December 8, 2016, FERC issued an order authorizing the application to issue equity as requested. MAIT is expected to issue short-term debt and participate in the FirstEnergy regulated companies' money pool for working capital, to fund day-to-day operations, and for other general corporate purposes. Over the long-term, MAIT is expected to issue long-term debt to support capital investment and to establish an actual capital structure for ratemaking purposes. On February 3, 2017, MAIT amended its debt authorization application to provide additional information regarding recovery of its investment and debt costs. MAIT requested an order from FERC on the debt authorization by February 28, 2017. FERC’s order remains pending. MAIT Transmission Formula Rate On October 28, 2016, MAIT submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. On November 30, 2016, various intervenors submitted protests of the proposed MAIT formula rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. MAIT filed a response to the protests on December 12, 2016. On December 28, 2016, FERC Staff issued a deficiency letter with respect to the PJM-related application, which also requested additional information regarding MAIT’s proposed formula rate. As a result of the deficiency letter, FERC’s order on the formula rate remains pending. MAIT responded to FERC Staff’s request on January 10, 2017, and requested that FERC issue an order approving the formula rate immediately after consummation of the transaction, which occurred on January 31, 2017. On February 15, 2017, MAIT filed a further answer to certain protesting parties' comments on its January 10 th deficiency letter response. JCP&L Transmission Formula Rate On October 28, 2016, after withdrawing its request to the NJBPU to transfer its transmission assets to MAIT, JCP&L submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. On November 18, 2016, a group of intervenors-including the NJBPU and New Jersey Division of Rate Counsel-filed a protest of the proposed JCP&L transmission rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On December 5, 2016, JCP&L filed a response to the protest. On December 28, 2016, FERC Staff issued a deficiency letter requesting additional information regarding JCP&L’s proposed transmission rate. As a result of the deficiency letter, FERC’s order on the rate remains pending. JCP&L responded to FERC Staff’s request on January 10, 2017, and requested that FERC issue an order approving the formula rate effective January 1, 2017. On February 15, 2017, JCP&L filed a further answer to certain protesting parties' comments on its January 10 th deficiency letter response. Competitive Generation Asset Sale On February 17, 2017, AE Supply and AGC submitted filings with FERC for authorization to sell four natural gas generating plants and an undivided ownership interest in Bath County to Aspen for approximately $925 million, in an all cash transaction. The four natural gas plants are: Springdale Generating Facility (638 MWs), Chambersburg Generating Facility (88 MWs), Gans Generating Facility (88 MWs), and Hunlock Creek (45 MWs). The 713 MW ownership interest in Bath County represents AE Supply’s indirect ownership interest in the power station. The FERC applications include a request for authorization to transfer the hydroelectric license under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the hydroelectric projects under Part II of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once regulatory approval is obtained. The VSCC also must approve the sale of the Bath County Hydro interest. The parties expect to close the transaction in the third quarter of 2017, subject to satisfaction of various customary and other closing conditions, including without limitation, receipt of regulatory approvals and third party consents. See "Note 22. Subsequent Events" below for additional information regarding the transaction. California Claims Litigation Since 2002, AE Supply has been involved in litigation and claims based on its power sales to the California Energy Resource Scheduling division of the CDWR during 2001-2003. This litigation and claims are related to litigation and claims advanced by the California Attorney General and certain California utilities regarding alleged market manipulation of the wholesale energy markets in California during the 2000-2001 period. AE Supply negotiated a settlement with the California Attorney General and the California utilities and, on August 24, 2016, filed the settlement agreement for FERC approval. The settlement calls for AE Supply to pay, without admission of any liability, $3.6 million in settlement in principle of all remaining claims that are based on AE Supply’s power sales in the western energy markets during the 2001-2003 time period. On October 27, 2016 FERC approved this settlement, and AE Supply paid the settlement shortly thereafter. PATH Transmission Project On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland which PJM had previously suspended in February 2011. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to settlement proceedings and a hearing if the parties could not agree to a settlement. On March 24, 2014, the FERC Chief ALJ terminated settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531, discussed below, to the PATH proceeding. On September 14, 2015, the ALJ issued his initial decision, disallowing recovery of certain costs. On January 19, 2017, FERC issued an order accepting the initial decision in part and denying it in part. Relying on its revised ROE methodology described in FERC Opinion No. 531, FERC reduced the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017. Additionally, FERC allowed recovery of costs related to land acquisitions and dispositions and legal expenses, but disallowed certain costs related to advertising and outreach. PATH filed a request for rehearing with FERC on February 20, 2017, seeking recovery of the advertising and outreach costs and requesting that the ROE be reset to 10.4%. Market-Based Rate Authority, Triennial Update The Utilities, AE Supply, FES and its subsidiaries, Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. The filings remain pending before FERC.

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