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ITEM 1.	BUSINESS

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•	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.

•	An eight-year term (June 1, 2016 - May 31, 2024);

•	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;

•	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;

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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;

•	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;

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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

•	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.

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(1)	Includes an increase of approximately $127 million related to the capital component of the non-cash pension and OPEB mark-to-market adjustment.

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(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.

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•	OE—5,391 MW on July 29, 2015;

•	Penn—983 MW on July 29, 2015;

•	CEI—4,057 MW on August 19, 2015;

•	TE—2,149 MW on September 8, 2015;

•	JCP&L—5,789 MW on July 20, 2015;

•	ME—2,770 MW on July 20, 2015;

•	PN—3,024 MW on February 19, 2015;

•	MP—2,031 MW on January 7, 2015;

•	PE—3,631 MW on February 20, 2015; and

•	WP—3,942 MW on February 20, 2015.

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ITEM 1A.	RISK FACTORS

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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;

•	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;

•	uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and

•	uncertainties with respect to the technological and financial aspects of spent fuel storage and decommissioning nuclear plants, including but not limited to, waste disposal at the end of their licensed operation and increases in minimum funding requirements or costs of decommissioning.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 2.	PROPERTIES

(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.

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(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.	LEGAL PROCEEDINGS

ITEM 4.	MINE SAFETY DISCLOSURES

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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ITEM 6.	SELECTED FINANCIAL DATA

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES

•	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.

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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.

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•	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.

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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.

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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.

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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.

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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.

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•	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.

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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.

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•	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.

•	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.

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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.

•	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.

•	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.

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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.

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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.

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•	Fuel expense decreased $34 million in 2015 primarily related to lower economic dispatch resulting from low spot market energy prices.

•	Purchased power costs were $163 million higher in 2015 primarily due to increased volumes reflecting lower customer shopping as described above, higher unit costs related to higher default service auction results, and higher capacity expense at MP, partially offset by lower purchases resulting from the termination of certain NUG contracts at JCP&L and PN.

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•	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.

•	Increased regulated generation operating and maintenance expenses of $7 million, reflecting higher planned outage expenses in 2015 compared to 2014.

•	Higher retirement benefit costs of $22 million, reflecting higher net benefit costs before the pension and OPEB mark-to-market adjustment described below.

•	Higher distribution operating and maintenance expenses of $54 million, reflecting increased reliability maintenance in New Jersey and the Pennsylvania companies and other employee benefit costs, partially offset by lower storm restoration costs.

•	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.

•	Depreciation expense increased $14 million due to a higher asset base, partially offset by lower depreciation rates at JCP&L effective with the implementation of new rates from its distribution base rate case as well as lower depreciation rates in Pennsylvania based on updated asset life studies approved by the PPUC.

•	Net regulatory asset amortization increased $260 million primarily due to:

•	Recovery of storm costs in New Jersey, Pennsylvania, and West Virginia effective with the implementation of new rates as discussed above ($66 million),

•	Higher energy efficiency program cost recovery ($66 million),

•	Lower deferral of TTS costs in West Virginia ($37 million),

•	Higher amortizations of above-market NUG costs in Pennsylvania and New Jersey ($36 million),

•	Lower deferral of West Virginia vegetation management expenses ($31 million),

•	Higher default generation service cost amortization ($28 million), and

•	Recovery of Pennsylvania legacy meter costs ($22 million); partially offset by

•	Higher cost deferral of Ohio network transmission expenses ($33 million).

•	General taxes increased $10 million primarily due to higher revenue-related taxes in Pennsylvania, partially offset by lower property taxes in Ohio.

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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.

•	Nuclear operating costs increased $84 million as a result of higher planned outage costs and higher employee benefit expenses. There were three planned refueling outages in 2015 as compared to two planned outages in 2014.

•	Transmission expenses decreased $273 million primarily due to lower operating reserve and market-based ancillary costs associated with market conditions resulting from the extreme weather events in 2014.

•	General taxes decreased $31 million primarily due to lower gross receipts taxes associated with decreased retail sales volumes.

•	Pension and OPEB mark-to-market adjustment decreased $267 million to $60 million, which was impacted by lower than expected asset returns, partially offset by an increase in the discount rate used to measure benefit obligations.

•	Other operating expenses decreased $212 million primarily due to a $141 million decrease in mark-to-market expenses on commodity contract positions reflecting lower market prices and a $71 million decrease in retail-related costs.

•	Impairments of long-lived assets increased $34 million due to impairment charges associated with non-core assets.

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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.

•	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.

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Higher transmission expenses of $130 million primarily due to PJM transmission costs associated with higher congestion rates at MP as a result of market conditions related to extreme weather events in January 2014 and higher PJM transmission costs resulting from the October 2013 Harrison/Pleasants asset transfer. The differences between current transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.

•	Higher distribution operating and maintenance expenses of $75 million resulting from higher maintenance activities and storm related restoration expenses, including $26 million of storm expenses deferred for future recovery.

•	Higher vegetation management expenses in West Virginia of $33 million, which were deferred for future recovery per authorization of the WVPSC.

•	Higher retirement benefit costs of $33 million primarily reflecting higher net periodic benefit costs before the pension and OPEB mark-to-market adjustments discussed below.

•	Increased regulated generation operating and maintenance expenses of $23 million, reflecting increased costs associated with the October 2013 Harrison/Pleasants asset transfer and a planned outage at Fort Martin.

•	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.

•	Depreciation expense increased $52 million due to a higher asset base, including $22 million at MP associated with the October 2013 Harrison/Pleasants asset transfer.

•	Net regulatory asset amortization decreased $528 million primarily due to:

◦	Impairment charges on regulatory assets of $305 million associated with the recovery of marginal transmission losses at ME and PN ($254 million) and the recovery of RECs for the Ohio Companies ($51 million) that occurred in 2013,

◦	Decreased energy efficiency amortization reflecting a rate decrease associated with certain programs for the Pennsylvania Companies ($67 million),

◦	Lower default generation service and NUG costs recovery in Pennsylvania ($48 million),

◦	Increased deferral of West Virginia vegetation management expenses ($33 million) and customer refunds associated with the gain on the Pleasants plant resulting from the October 2013 Harrison/Pleasants asset transfer ($36 million), and

◦	Higher storm cost deferrals ($26 million).

•	General taxes decreased $4 million primarily due to lower revenue-related taxes, partially offset by higher property taxes and an increase in the West Virginia business and occupation tax as a result of the October 2013 Harrison/Pleasants asset transfer.

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•	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.

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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.

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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.

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•	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.

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(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.

(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

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(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.

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(1)	Excludes approximately $1 million of applicable interest coverage.

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•	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.

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•	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.

(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.

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(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.

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(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.

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•	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.

•	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;

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•	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.

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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.

•	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.

•	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.

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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.

•	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.

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(1)	Represents exchange traded New York Mercantile Exchange futures and options.

(2)	Primarily represents contracts based on broker and ICE quotes.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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*	Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.

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*	Includes excise tax collections of $44 million, $69 million and $78 million in 2015, 2014 and 2013, respectively.

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(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.

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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.

•	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.

•	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.

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(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.

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(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.

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(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.

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(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.

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•

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.

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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.

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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.

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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.

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•	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.

•

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.

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(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.

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(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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(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.

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(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.

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•	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.

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(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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(1)	Includes approximately $1 million of applicable interest

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(1)	FE and the Utilities

(2)	Includes FET, ATSI and TrAIL as subsidiary borrowers

(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.

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•	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);

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•	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.

•	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.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

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ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

(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.

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ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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(1)	Represents recoveries and reinstatements of accounts previously written off.

(2)	Represents the write-off of accounts considered to be uncollectible.

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(1)	Represents recoveries and reinstatements of accounts previously written off.

(2)	Represents the write-off of accounts considered to be uncollectible.

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