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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): November 4, 2016



Commission
 
Registrant; State of Incorporation;
 
I.R.S. Employer
File Number
 
Address; and Telephone Number
 
Identification No.
 
 
 
 
 
333-21011
 
FIRSTENERGY CORP.
 
34-1843785
 
 
(An Ohio Corporation)
 
 
 
 
76 South Main Street
 
 
 
 
Akron, OH  44308
 
 
 
 
Telephone (800)736-3402
 
 
 
 
 
 
 
















Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2.):

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))





Item 7.01 Regulation FD Disclosure

On November 8, 2016, Charles E. Jones, President and Chief Executive Officer of FirstEnergy Corp. (FirstEnergy) will present at the Edison Electric Institute Financial Conference in Phoenix, Arizona. The presentation for use at the conference is attached as Exhibit 99.1 to this Current Report on Form 8-K and incorporated by reference herein.

Mr. Jones’s presentation at the conference will be webcast at approximately 10:15 a.m. EST on FirstEnergy’s Investor information website, www.firstenergycorp.com/ir, by clicking the Edison Electric Institute Financial Conference link. The webcast and presentation will also be archived on FirstEnergy’s website and available for replay for up to one year. The company also posted the attached presentation slides to its website on November 4, 2016. These materials include 2017 guidance and other business targets.

The information contained or incorporated by reference herein, including Exhibit 99.1, shall not be deemed filed for purposes of the Securities Exchange Act of 1934, nor shall such information and Exhibit 99.1 be deemed incorporated by reference in any fling under the Securities Act of 1993, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01 Financial Statements and Exhibits
(d)
Exhibits

Exhibit No.
 
Description
99.1
 
Slide Presentation, dated as of November 4, 2016


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Forward-Looking Statements: This Form 8-K includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following: the 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; 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 Mid-Atlantic Interstate Transmission, LLC, 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 and resulting outcomes on the matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the Electric Security Plan IV; the impact of the federal regulatory process on Federal Energy Regulatory Commission (FERC)-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM Interconnection, L.L.C. (PJM) markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates, including FERC Opinion No. 531's revised Return on Equity methodology for FERC-jurisdictional wholesale generation and transmission utility service; and FERC’s compliance and enforcement activity, including compliance and enforcement activity related to North American Electric Reliability Corporation’s mandatory reliability standards; the uncertainties of various cost recovery and cost allocation issues resulting from American Transmission Systems, Incorporated'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, including without limitation impairments thereon; the risks and uncertainties at the Competitive Energy Services (CES) segment, including FirstEnergy Solutions Corp. and its subsidiaries and FirstEnergy Nuclear Operating Company, related to continued depressed wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives, such as potential CES generating unit asset sales, the potential conversion of the remaining generation fleet from competitive operations to a regulated or regulated-like construct or the potential need to deactivate additional generating units; the 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 United States Environmental Protection Agency’s Clean Power Plan, Coal Combustion Residuals regulations, Cross-State Air Pollution Rule and Mercury and Air Toxics Standards programs, including our estimated costs of compliance, Clean Water Act (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 New Source Review 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 older regulated and competitive units, including the impact on vendor commitments, such as long-term fuel and transportation agreements, and as it relates to the reliability of the transmission grid, the timing thereof; the impact of other future changes to the operational status or availability of our generating units and any capacity performance charges associated with unit unavailability; 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 Nuclear Regulatory Commission 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, such as long-term fuel and transportation agreements; the impact of labor disruptions by our unionized workforce; replacement power costs being higher than anticipated or not fully hedged; the ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates; changes in customers' demand for power, including, but not limited to, changes resulting from the implementation of state and federal energy efficiency and peak demand reduction mandates; the ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, the ability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our cash flow improvement plan and other proposed capital raising initiatives; our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins; changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our Nuclear Decommissioning Trusts, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated; the impact of changes to significant accounting policies; the ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries; further actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries' access to financing, increase the costs thereof, increase requirements to post additional collateral to support, or accelerate payments under outstanding commodity positions, letters of credit and other financial guarantees, and the impact of these events on the financial condition and liquidity of FirstEnergy and/or its subsidiaries, specifically the subsidiaries within the CES segment; the risks and uncertainties surrounding FirstEnergy's need to obtain waivers from its bank group under FirstEnergy's credit facilities caused by a debt to total capitalization ratio in excess of 65% resulting from impairment charges or other events at CES; 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

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or rulings; issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business; the risks associated with cyber-attacks and other disruptions to our information technology system that may compromise our generation, transmission and/or distribution services and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks; and the risks and other factors discussed from time to time in our United States Securities and Exchange Commission (SEC) filings, and other similar factors. Dividends declared from time to time on FirstEnergy Corp.'s common stock during any period may in the aggregate vary from prior periods due to circumstances considered by FirstEnergy Corp.'s Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating. The foregoing factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements and risks that are included in our filings with the SEC, including but not limited to the most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. FirstEnergy expressly disclaims any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.



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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



November 4, 2016

 
 FIRSTENERGY CORP.
 
 Registrant
 
 
 
 
 By:
/s/ K. Jon Taylor
 
K. Jon Taylor
Vice President, Controller and
Chief Accounting Officer


5



Exhibit Index

Exhibit No.
 
Description
99.1
 
Slide Presentation, dated as of November 4, 2016



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Section 2: EX-99.1 (EXHIBIT 99.1)

a2016110608eeifinancialc
November 4, 2016 EEI Financial Conference Phoenix, Arizona


 
EEI Financial Conference November 2016 1 FirstEnergy Transforming to a Regulated Company Charles E. Jones, President and CEO Phoenix, AZ • November 2016 November 2016EEI Financial Conference 2 Forward-Looking Statements This presentation includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following: the speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in particular; the ability to experience growth in the Regulated Distribution and Regulated Transmission segments; 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 Mid-Atlantic Interstate Transmission, LLC, 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 and resulting outcomes on the matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the Electric Security Plan IV; the impact of the federal regulatory process on Federal Energy Regulatory Commission (FERC)-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM Interconnection, L.L.C. (PJM) markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates, including FERC Opinion No. 531's revised Return on Equity methodology for FERC-jurisdictional wholesale generation and transmission utility service; and FERC’s compliance and enforcement activity, including compliance and enforcement activity related to North American Electric Reliability Corporation’s mandatory reliability standards; the uncertainties of various cost recovery and cost allocation issues resulting from American Transmission Systems, Incorporated'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, including without limitation impairments thereon; the risks and uncertainties at the Competitive Energy Services (CES) segment, including FirstEnergy Solutions Corp. and its subsidiaries and FirstEnergy Nuclear Operating Company, related to continued depressed wholesale energy and capacity markets, and the viability and/or success of strategic business alternatives, such as potential CES generating unit asset sales, the potential conversion of the remaining generation fleet from competitive operations to a regulated or regulated-like construct or the potential need to deactivate additional generating units; the 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 United States Environmental Protection Agency’s Clean Power Plan, Coal Combustion Residuals regulations, Cross-State Air Pollution Rule and Mercury and Air Toxics Standards programs, including our estimated costs of compliance, Clean Water Act (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 New Source Review 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 older regulated and competitive units, including the impact on vendor commitments, such as long-term fuel and transportation agreements, and as it relates to the reliability of the transmission grid, the timing thereof; the impact of other future changes to the operational status or availability of our generating units and any capacity performance charges associated with unit unavailability; 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 Nuclear Regulatory Commission 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, such as long-term fuel and transportation agreements; the impact of labor disruptions by our unionized workforce; replacement power costs being higher than anticipated or not fully hedged; the ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates; changes in customers' demand for power, including, but not limited to, changes resulting from the implementation of state and federal energy efficiency and peak demand reduction mandates; the ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, the ability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our cash flow improvement plan and other proposed capital raising initiatives; our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins; changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our Nuclear Decommissioning Trusts, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated; the impact of changes to significant accounting policies; the ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries; further actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries' access to financing, increase the costs thereof, increase requirements to post additional collateral to support, or accelerate payments under outstanding commodity positions, letters of credit and other financial guarantees, and the impact of these events on the financial condition and liquidity of FirstEnergy and/or its subsidiaries, specifically the subsidiaries within the CES segment; the risks and uncertainties surrounding FirstEnergy's need to obtain waivers from its bank group under FirstEnergy's credit facilities caused by a debt to total capitalization ratio in excess of 65% resulting from impairment charges or other events at CES; changes in national and regional economic conditions affecting us, our subsidiaries and/or our major industrial and commercial customers, and other counterparties with which we do business, including fuel suppliers; the impact of any changes in tax laws or regulations or adverse tax audit results or rulings; issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business; the risks associated with cyber-attacks and other disruptions to our information technology system that may compromise our generation, transmission and/or distribution services and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks; and the risks and other factors discussed from time to time in our United States Securities and Exchange Commission (SEC) filings, and other similar factors. Dividends declared from time to time on FirstEnergy Corp.'s common stock during any period may in the aggregate vary from prior periods due to circumstances considered by FirstEnergy Corp.'s Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating. The foregoing factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements and risks that are included in our filings with the SEC, including but not limited to the most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. FirstEnergy expressly disclaims any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.


 
EEI Financial Conference November 2016 2 Non-GAAP Financial Matters November 2016EEI Financial Conference 3 This presentation contains references to non-GAAP financial measures including, among others, Operating earnings, CES Adjusted EBITDA, Funds from Operations, and Free Cash Flow. In addition, Basic EPS and Basic EPS-Operating, each calculated on a segment basis, are also non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company’s historical or future financial performance, financial position, or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). Operating earnings are not calculated in accordance with GAAP because they exclude the impact of “special items”. Basic EPS for each segment is calculated by dividing segment net income (loss) on a GAAP basis by the basic weighted average shares outstanding for the period. Basic EPS-Operating for each segment is calculated by dividing segment Operating earnings, which exclude special items as discussed above, by the basic weighted average shares outstanding for the period. Management uses non-GAAP financial measures such as Operating earnings, CES Adjusted EBITDA, Funds from Operations, and Free Cash Flow to evaluate the company’s performance and manage its operations and frequently references these non-GAAP financial measures in its decision-making, using them to facilitate historical and ongoing performance comparisons. Additionally, management uses Basic EPS and Basic EPS-Operating by segment to further evaluate FirstEnergy’s performance by segment and references these non-GAAP financial measures in its decision-making. Management believes that the non-GAAP financial measures of “Operating earnings,” “Basic EPS” by segment and “Basic EPS-Operating” by segment provide consistent and comparable measures of performance of its businesses to help shareholders understand performance trends. All of these non-GAAP financial measures are intended to complement, and are not considered as alternatives to, the most directly comparable GAAP financial measures. Also, the non-GAAP financial measures may not be comparable to similarly titled measures used by other entities. Pursuant to the requirements of Regulation G, FirstEnergy has provided quantitative reconciliations within this presentation of the non- GAAP financial measures to the most directly comparable GAAP financial measures. Refer to slides 21-25 of the Guidance Materials. Agenda ■ FirstEnergy Overview – Regulated Distribution & Transmission – Competitive Generation ■ Strategic Review of Competitive Generation ■ Investing for Growth in Regulated Operations ■ Building a Stronger FirstEnergy ■ Q&A November 2016EEI Financial Conference 4


 
EEI Financial Conference November 2016 3 Regulated Distribution ■ One of the largest contiguous service territories in the U.S. ■ Includes 3,790 MW of regulated generation; primarily serving West Virginia ■ Balanced customer sales mix of approximately 1/3 residential, 1/3 commercial, 1/3 industrial ■ Low customer bills in each state ■ Strong reliability performance against targets November 2016EEI Financial Conference 5 Our regulated operations provide stable, predictable earnings and cash flows, and fully support the dividend 106M 6 Operating Companies Customers States Regulated Transmission ■ One of the largest transmission systems in PJM ■ Includes FERC-regulated transmission assets recovered through formula rates owned by ATSI, TrAIL, MAIT, and JCP&L ■ Includes FERC-regulated transmission assets recovered through stated rates owned by MP, PE, and WPP ■ $20B+ in future opportunities November 2016EEI Financial Conference 6 Line Miles 24,200+ Average annual capital expenditures through 2021 $0.8B-$1.2B Formula Companies’ Rate Base Growth 2016-2021 ~9% Our regulated operations provide stable, predictable earnings and cash flows, and fully support the dividend


 
EEI Financial Conference November 2016 4 Competitive Generation ■ Segment primarily comprised of three legal entities: FES, AES, and FENOC ■ 100% of power generated from low or non-emitting sources ■ ~75M MWH generated annually, about half sold through various retail channels and half through forward wholesale and spot sales ■ Business is run conservatively, focused on minimizing overall risk ■ Treated as a standalone business, with no equity contribution planned from FE Corp., since these operations are expected to be free cash flow positive through 2018 November 2016EEI Financial Conference 7 MWs of Competitive Generation ~13,000 Positive Annual Free Cash Flow Through 2018 FCF+ Retail Customers 1.4M The competitive business has been challenged, and market conditions have led to tough decisions Strategic Review of Competitive Generation While CES is expected to maintain positive free cash flow each year through 2018, FES in particular faces risks … ■ Sustained weak energy and capacity prices ■ Potential adverse outcome from rail disputes ■ Refinancing of upcoming debt maturities and extension of credit facility – Debt maturities total ~$645M through 2018 ■ Potential collateral postings November 2016EEI Financial Conference 8 Targeting 12-18 month timeline to implement decisions from strategic review … prompting FirstEnergy to assess alternatives to move away from competitive generation Transfer assets to regulated or regulated-like construct Asset sales Asset closures Restructuring


 
EEI Financial Conference November 2016 5 Investing for Growth in Regulated Operations November 2016EEI Financial Conference 9 The scale and diversity of our regulated operations position FirstEnergy for sustained growth into the future 2016F Weather-Adjusted Operating EPS Midpoint* 2019F Operating EPS Targeting 4% - 6% Compound Annual Growth Rate Incremental 3% with Ohio DMR $2.47 Traditional Utility Growth 2016F – 2019F Including Ohio DMR 4% - 6% 7% - 9% * Estimated 2016 operating earnings for Regulated Distribution and Regulated Transmission segments of $2.59-$2.63 per share include $0.14 from the impact of weather. Refer to slide 21 in the Guidance Materials for reconciliation between 2016F GAAP and Operating (non-GAAP) earnings. Ohio Grid Modernization: Incremental Opportunity ■ Business plan filed with PUCO includes three scenarios that provide the opportunity for significant investments over time: – Full AMI deployment – Different levels of DA/VVC deployment – Net benefits to customers ■ Business plan is subject to PUCO review and approval November 2016EEI Financial Conference 10 Estimates Included in Business Plan Length Total Estimated Costs AMI Deployment 5 to 8 years Capital: $2.2B - $3.5B DA/VVC 8 to 15 years O&M: $1.5B - $1.9B Total: $3.7B - $5.4B* * Not included in current finance plan In ESP IV, the Ohio companies agreed to empower customers through grid modernization initiatives, e.g., AMI, Distribution Automation Circuit Reconfiguration, and VOLT/VAR Control


 
EEI Financial Conference November 2016 6 Continued Transmission Investment ■ Energizing the Future (2017-2021) – $4.2B - $5.8B of investment – $1B in 2017, and then $800M - $1.2B annually 2018-2021 – $500M equity 2017-2019 annually to fund growth ■ Filed with FERC for forward-looking rate structure at JCP&L and MAIT (ME/PN assets) ■ Majority of investments over the next five years will be focused on entities with forward-looking rates November 2016EEI Financial Conference 11 Transmission Operating Companies Company Rate Structure ATSI Forward-Looking TrAIL Forward-Looking MAIT* Forward-Looking JCP&L* Forward-Looking Utility (WPP, MP, PE) Stated Rate * Filed for Formula Rates with FERC on October 28, 2016 Building a Stronger FirstEnergy ■ Equity – ~$100M ongoing through employee benefit and other plans – $500M in 2016 previously announced (into the pension) – $500M 2017-2019 annually to support ETF Transmission growth ■ Committed to investment grade credit ratings at all regulated entities and FE Corp. November 2016EEI Financial Conference 12 Basic EPS* 2016F 2017F Regulated Distribution $1.25 - $1.47 $2.20 - $2.30 Regulated Transmission $0.78 $0.81 - $0.85 Competitive Energy Services ($2.81) - ($2.63) ($0.05) – $0.07 Corporate / Other ($0.52) ($0.49) - ($0.45) FE Consolidated ($1.30) - ($0.90) $2.47 - $2.77 Basic EPS – Operating (Non-GAAP) 2016F 2017F $1.81 - $1.85 $2.24 - $2.34 $0.78 $0.81 - $0.85 $0.53 - $0.59 ($0.01) - $0.11 ($0.52) ($0.49) - ($0.45) $2.60 - $2.70 $2.55 - $2.85 Special Items** 2016F 2017F $0.38 - $0.56 $0.04 - - $3.22 - $3.34 $0.04 - - $3.60 - $3.90 $0.08 Note: 2016F reflects reclassification of $0.07 per share from Regulated Distribution to Regulated Transmission related to transmission assets at MAIT and JCP&L that will be recovered through formula rates * Before excluding special items ** See slides 21-25 of Guidance Materials for additional details regarding special items Fully committed to achieving our plans for the future and unlocking the full value of FirstEnergy for our investors


 
EEI Financial Conference November 2016 1 Guidance Materials Financial Guidance


 
EEI Financial Conference November 2016 2 Basic EPS* 2016F 2017F Regulated Distribution $1.25 - $1.47 $2.20 - $2.30 Regulated Transmission $0.78 $0.81 - $0.85 Competitive Energy Services ($2.81) - ($2.63) ($0.05) – $0.07 Corporate / Other ($0.52) ($0.49) - ($0.45) FE Consolidated ($1.30) - ($0.90) $2.47 - $2.77 2016F – 2017F Earnings Guidance FE Consolidated Summary EEI Financial Conference Basic EPS – Operating (Non-GAAP) 2016F 2017F $1.81 - $1.85 $2.24 - $2.34 $0.78 $0.81 - $0.85 $0.53 - $0.59 ($0.01) - $0.11 ($0.52) ($0.49) - ($0.45) $2.60 - $2.70 $2.55 - $2.85 * Before excluding special items Special Items** 2016F 2017F $0.38 - $0.56 $0.04 - - $3.22 - $3.34 $0.04 - - $3.60 - $3.90 $0.08 ** See pages 21-25 for additional details regarding special items November 2016 15 Note: 2016F reflects reclassification of $0.07 per share from Regulated Distribution to Regulated Transmission related to transmission assets at MAIT and JCP&L that will be recovered through formula rates Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans and up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans . The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount with the exception of Asset impairment/Plant exit costs that included an impairment of goodwill, of which $433 million of the $800 million pre-tax impairment was non-deductible for tax purposes, and valuation allowances against state and local NOL carryforwards of $159 million. With the exception of these items included in Asset impairment/Plant exit costs, the income tax rates range from 35% to 42%. -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 2016F Basic Loss Per Share GAAP + Special Items of $3.60- $3.90 2016F Basic EPS - Operating (Non-GAAP) Regulated Distribution +$0.46 Regulated Transmission +$0.05 Competitive Energy Services ($0.51) Corporate / Other +$0.05 2017F Basic EPS - Operating (Non-GAAP) - Special Items of $0.08 2017F Basic EPS GAAP 2016F – 2017F Earnings Guidance FE Consolidated q2016 Weather qShare Dilution p Ohio Rate Changes p PA Rate Case p NJ Rate Case p WV Industrial Load Growth qOther Operating p Rate Base p MAIT & JCP&L Formula Rates q Utility Stated Rate Revenue q Share Dilution q Commodity Margin p O&M q Depreciation q Investment Income q Net Financing Costs p O&M p Share Dilution q Interest Expense EEI Financial Conference ($1.30) - ($0.90) $2.60 - $2.70 $2.55 - $2.85 November 2016 16 Asset impairment / plant exit costs $2.97 Regulatory charges $0.13 Merger accounting – commodity contracts $0.05 Trust securities impairments $0.02 Mark-to-market Adjustments: Pension/OPEB: $0.45-$0.75 Other: ($0.02) $2.47 - $2.77 Regulatory charges $0.04 Merger accounting – commodity contracts $0.04 Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans and up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans . The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount with the exception of Asset impairment/Plant exit costs that included an impairment of goodwill, of which $433 million of the $800 million pre-tax impairment was non-deductible for tax purposes, and valuation allowances against state and local NOL carryforwards of $159 million. With the exception of these items included in Asset impairment/Plant exit costs, the income tax rates range from 35% to 42%.


 
EEI Financial Conference November 2016 3 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2016F Basic EPS + Special Items of $0.38-$0.56 2016F Basic EPS - Operating (Non-GAAP) 2016 Weather ($0.14) Share Dilution ($0.08) Ohio - Rate Changes +$0.34 PA Rate Case +$0.28 NJ Rate Case +$0.12 WV Industrial Load Growth +$0.02 Other Operating ($0.08) 2017F Basic EPS - Operating (Non-GAAP) - Special Items of $0.04 2016F Basic EPS 2017F Earnings Guidance Regulated Distribution $2.24 - $2.34 O&M, Depreciation & General Taxes ($0.07) Other Revenues ($0.04) Pension/OPEB +$0.03 $1.25 - $1.47 EEI Financial Conference $1.81 - $1.85 DMR +$0.30 DCR +$0.04 November 2016 17 $2.20 - $2.30 Regulatory charges $0.13 Mark-to-market Adjustments: Pension/OPEB: $0.25-$0.43 Regulatory charges $0.04 Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans and up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans. The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount. The income tax rates range from 35% to 42%. Note: 2016F reflects reclassification of $0.07 per share from Regulated Distribution to Regulated Transmission related to transmission assets at MAIT and JCP&L that will be recovered through formula rates 0.30 0.40 0.50 0.60 0.70 0.80 0.90 2016F Basic EPS Special Items --- 2016F Basic EPS - Operating (Non-GAAP) Share Dilution ($0.03) Rate Base +$0.10 Utility Stated Rate Revenue ($0.02) 2017F Basic EPS - Operating (Non-GAAP) Special Items --- 2017F Basic EPS 2017F Earnings Guidance Regulated Transmission $0.78 EEI Financial Conference November 2016 18 $0.78 $0.81 - $0.85$0.81 - $0.85 Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans and up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans . The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount. The income tax rates range from 35% to 42%. ATSI +$0.05 TrAIL +$0.02 MAIT / JCP&L +$0.03 Note: 2016F reflects reclassification of $0.07 per share from Regulated Distribution to Regulated Transmission related to transmission assets at MAIT and JCP&L that will be recovered through formula rates


 
EEI Financial Conference November 2016 4 (3.00) (2.00) (1.00) - 2016F Basic Loss Per Share + Special Items of $3.22-$3.34 2016F Basic EPS - Operating (Non-GAAP) Commodity Margin ($0.47) O&M +$0.07 Depreciation ($0.06) Investment Income ($0.03) Net Financing Costs ($0.02) 2017F Basic EPS (Loss Per Share) - Operating (Non-GAAP) - Special Items of $0.04 2017F Basic EPS (Loss Per Share) 2017F Earnings Guidance Competitive Energy Services EEI Financial Conference November 2016 19 Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans and up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans . The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount with the exception of Asset impairment/Plant exit costs that included an impairment of goodwill, of which $433 million of the $800 million pre-tax impairment was non-deductible for tax purposes, and valuation allowances against state and local NOL carryforwards of $159 million. With the exception of these items included in Asset impairment/Plant exit costs, the income tax rates range from 35% to 42%. (0.05) 0.10 0.25 0.40 0.55 0.70 ($2.81) - ($2.63) Asset impairment / plant exit costs $2.97 Merger accounting – commodity contracts $0.05 Trust securities impairments $0.02 Mark-to-market Adjustments: Pension/OPEB: $0.20-$0.32 Other: ($0.02) $0.53 - $0.59 ($0.01) - $0.11 ($0.05) - $0.07 Merger Accounting – Commodity Contracts $0.04 -$0.80 -$0.60 -$0.40 -$0.20 $0.00 2016F Basic EPS Special Items --- 2016F Basic EPS - Operating (Non-GAAP) Interest Expense ($0.04) O&M +$0.07 Share Dilution +$0.02 2017F Basic EPS - Operating (Non-GAAP) Special Items --- 2017F Basic EPS 2017F Earnings Guidance Corporate /Other EEI Financial Conference ($0.52)($0.52) November 2016 20 ($0.49) - ($0.45)($0.49) - ($0.45) Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans and up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans . The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount. The income tax rates range from 35% to 42%. Net Sale- Leaseback +$0.04 Other O&M +$0.03


 
EEI Financial Conference November 2016 5 2016F GAAP to Operating (Non-GAAP) Earnings1 Reconciliation EEI Financial Conference 1 Operating earnings exclude special items as described in the reconciliation table above and is a non-GAAP financial measure. 2 Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016, of which ~$100 million relates to employee benefit and other plans. The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount with the exception of Asset impairment/Plant exit costs that included an impairment of goodwill, of which $433 million of the $800 million pre-tax impairment was non-deductible for tax purposes, and valuation allowances against state and local NOL carryforwards of $159 million. With the exception of these items included in Asset impairment/Plant exit costs, the income tax rates range from 35% to 42%. 3 Based on current discount rates of approximately 4.00% to 3.75% for the pension plans and 3.75% to 3.50% for the OPEB plans and actual gains on plan assets through September 30, 2016, of 11%. November 2016 21 2016 Forecast (In $M, except per share amounts) FirstEnergy Consolidated Regulated Distribution Regulated Transmission Regulated Distribution and Transmission Subtotal Competitive Energy Services Corporate/ Other Net Income (Loss) – GAAP ($555) - ($385) $530 - $625 $335 $865 - $960 ($1,200) - ($1,125) ($220) Basic EPS (Loss Per Share) ($1.30) – ($0.90) $1.25 - $1.47 $0.78 $2.03 - $2.25 ($2.81) - ($2.63) ($0.52) Excluding Special Items2: Regulatory Charges 0.13 0.13 - 0.13 - - Trust Securities Impairments 0.02 - - - 0.02 - Merger Accounting – Commodity Contracts 0.05 - - - 0.05 - Asset Impairment/Plant Exit Costs 2.97 - - - 2.97 - Mark-to-market Adjustments Pension/OPEB actuarial assumptions3 0.45 – 0.75 0.25 – 0.43 - 0.25 – 0.43 0.20 – 0.32 - Other (0.02) - - - (0.02) - Total Special Items2 $3.60 - $3.90 $0.38 - $0.56 - $0.38 - $0.56 $3.22 - $3.34 - Basic EPS – Operating (Non-GAAP) $2.60 - $2.70 $1.81 - $1.85 $0.78 $2.59 - $2.63 $0.53 - $0.59 ($0.52) Note: 2016F reflects reclassification of $0.07 per share from Regulated Distribution to Regulated Transmission related to transmission assets at MAIT and JCP&L that will be recovered through formula rates Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2016 of which, ~$100 million relates to employee benefit and other plans. The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount with the exception of Asset impairment/Plant exit costs that included an impairment of goodwill, of which $433 million of the $800 million pre-tax impairment was non-deductible for tax purposes, and valuation allowances against state and local NOL carryforwards of $159 million. With the exception of these items included in Asset impairment/Plant exit costs, the income tax rates range from 35% to 42%. 2016F Special Items (In $M, except per share amounts) EEI Financial Conference November 2016 22 2016 Forecast FirstEnergy Consolidated Regulated Distribution Competitive Energy Services Pre-Tax After-Tax EPS Pre-Tax After-Tax EPS Pre-Tax After-Tax EPS Regulatory Charges $89 $56 $0.13 $89 $56 $0.13 $ - $ - $ - Trust Securities Impairments 13 8 0.02 1 - - 12 8 0.02 Merger Accounting – Commodity Contracts 32 21 0.05 - - - 32 21 0.05 Asset Impairment/Plant Exit Costs 1,505 1,269 2.97 - - - 1,505 1,269 2.97 Impact of Non-Core Asset Sales/Impairments (2) (1) - - - - (2) (1) - Mark-to-market Adjustments Pension/OPEB actuarial assumptions 300 - 525 186 - 316 0.45 – 0.75 170 – 300 104 – 184 0.25 - 0.43 130 - 225 82 – 132 0.20 - 0.32 Other (10) (6) (0.02) - - - (10) (6) (0.02) Loss on Debt Redemptions 4 2 - - - - 4 2 - Total Special Items $1,931-$2,156 $1,535-$1,665 $3.60-$3.90 $260-$390 $160-$240 $0.38-$0.56 $1,671-$1,766 $1,375-$1,425 $3.22-$3.34


 
EEI Financial Conference November 2016 6 2017F GAAP to Operating (Non-GAAP) Earnings1 Reconciliation EEI Financial Conference 1 Operating earnings exclude special items as described in the reconciliation table above and is a non-GAAP financial measure. 2 Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans. The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount. The income tax rates range from 35% to 42%. November 2016 23 2017F (In $M, except per share amounts) FirstEnergy Consolidated Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Net Income (Loss) – GAAP $1,095 - $1,230 $975 - $1,020 $360 - $375 ($20) - $35 ($220) - ($200) Basic EPS (Loss Per Share) (average shares outstanding 443M) $2.47 - $2.77 $2.20 - $2.30 $0.81 - $0.85 ($0.05) - $0.07 ($0.49) - ($0.45) Excluding Special Items: Regulatory Charges 0.04 0.04 - - - Merger Accounting – Commodity Contracts 0.04 - - 0.04 - Total Special Items2 $0.08 $0.04 - $0.04 - Basic EPS – Operating (Non-GAAP) (average shares outstanding 443M) $2.55 - $2.85 $2.24 - $2.34 $0.81 - $0.85 ($0.01) - $0.11 ($0.49) - ($0.45) Per share amounts for the special items and earnings drivers above and throughout these materials are based on the after-tax effect of each item divided by the weighted average basic shares outstanding and assumes up to $600 million of additional equity in 2017, of which ~$100 million relates to employee benefit and other plans. The current and deferred income tax effect was calculated by applying the subsidiaries’ statutory tax rate to the pre-tax amount. The income tax rates range from 35% to 42%. 2017F Special Items (In $M, except per share amounts) EEI Financial Conference November 2016 24 2017F FirstEnergy Consolidated Regulated Distribution Competitive Energy Services Pre-Tax After-Tax EPS Pre-Tax After-Tax EPS Pre-Tax After-Tax EPS Regulatory Charges $26 $15 $0.04 $26 $15 $0.04 - - - Merger Accounting – Commodity Contracts 26 15 0.04 - - - 26 15 0.04 Total Special Items $52 $30 $0.08 $26 $15 $0.04 $26 $15 $0.04


 
EEI Financial Conference November 2016 7 2016F – 2017F Special Items ■ Mark-to-market adjustments – Pension/OPEB actuarial assumptions – Reflects changes in fair value of plan assets and net actuarial gains and losses associated with the company’s pension and other postemployment benefit plans. – Other – Primarily reflects non-cash mark-to-market gains and losses on commodity contract positions. ■ Merger accounting – commodity contracts – Primarily reflects the non-cash amortization of acquired commodity contracts from the Allegheny Merger. ■ Regulatory charges – Primarily reflects the impact of regulatory orders requiring certain commitments and/or disallowing the recoverability of costs. ■ Impact of non-core asset sales/impairments – Primarily reflects the non-cash amortization / impairment of certain non-core investments and impact of non-core asset sales. ■ Trust securities impairments – Primarily reflects non-cash other than temporary impairment charges on nuclear decommissioning trust assets. ■ Asset impairments/plant exit costs – Primarily reflects the impairments of CES' goodwill, the Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station, valuation allowances against net operating loss carryforwards and other costs associated with the deactivation of certain power plants. ■ Loss on debt redemptions – Primarily reflects costs associated with the early redemption and retirement of debt. EEI Financial Conference November 2016 25 Capital Expenditures Forecast Summary EEI Financial Conference ($ Millions) 2016F 2017F 2018F 2019F Regulated Distribution $1,295 $1,325 $1,305 $1,265 Stated Rate $800 $815 $830 $875 Formula Rate $495 $510 $475 $390 ($ Millions) 2016F 2017F 2018F 2019F 2020F 2021F Regulated Transmission $1,000 $1,000 $800-$1,200 $800-$1,200 $800-$1,200 $800-$1,200 Stated Rate $295 $90 $90 $95 $95 $95 Formula Rate $705 $910 $710-$1,110 $705-$1,105 $705-$1,105 $705-$1,105 ($ Millions) 2016F 2017F 2018F 2019F Corp / Other $90 $95 $90 $100 ($ Millions) 2016F 2017F 2018F CES $540 $370 $300 Baseline - FENOC* $195 $190 $175 Baseline - Fossil $150 $125 $100 Major Projects $195 $55 $25 2016F 2017F 2018F 2019F FE Consolidated $2.9B $2.8B $2.7B $2.4B November 2016 26 85+% of 2017F-2019F capital expenditures from Regulated Operations * Excludes nuclear fuel All capital expenditures throughout the materials exclude the capital component of year-end Pension/OPEB mark-to market adjustment


 
EEI Financial Conference November 2016 8 2016F-2017F Funds From Operations EEI Financial Conference ($ Millions) FE Consolidated 2016F 2017F Cash From Operations $3,375 - $3,475 $3,890 - $4,090 Working Capital1 (100) – (120) 20 – (80) Collateral2 (25) - Pension Contribution3 385 - Funds From Operations (Non-GAAP) $3,635 - $3,715 $3,910- $4,010 1 Working Capital is included in “Changes in Current Assets and Liabilities” on the Consolidated Statements of Cash Flows. 2 Collateral is included in “Cash Collateral, net” on the Consolidated Statements of Cash Flows through September 30, 2016, and excludes the impact of collateral calls associated with potential rating agency downgrades 3 Pension Contribution is included in “Pension Trust Contributions” on the Consolidated Statements of Cash Flows. Funds from Operations (FFO) is a non-GAAP measure and represents cash from operations less changes in working capital and collateral plus pension trust contributions. FFO is used by management to monitor its credit metrics consistent with credit rating agencies. November 2016 27 2016F-2017F Free Cash Flow ($ Millions) FE Consolidated 2016F 2017F Funds From Operations (FFO) (Non-GAAP) $3,635 - $3,715 $3,910 - $4,010 Capital Expenditures1 (2,890) (2,760) Nuclear Fuel (215) (175) Cash Before Other Items $530 - $610 $975 - $1,075 Pension Contribution (385) - Collateral 25 - Working Capital/Other2 25 – (15) (175) – (155) Cash Before Dividends and Equity $195 - $235 $800 - $920 Dividends (615) (635) Equity - 500 Free Cash Flow 3 (Non-GAAP) ($420) – ($380) $665 - $785 1 Excludes capital component of year-end Pension/OPEB mark-to-market adjustment and AFUDC equity. 2 Primarily includes changes in working capital which is included in “Changes in Current Assets and Liabilities” on the Consolidated Statements of Cash Flows, asset removal costs which is included in the Consolidated Statements of Cash Flows, NDT interest and dividend income which is included in “Purchases of Investment Securities Held in Trust” on the Consolidated Statements of Cash Flows, and non-cash stock based compensation expense included in Form 10-K “Note 4. Stock-Based Compensation Plans”. 3 Excludes cash items related to debt financing activity. EEI Financial Conference Free Cash Flow (FCF) is a non-GAAP measure and represents funds from operations less capital expenditures, nuclear fuel purchases, pension trust contributions, and dividends as well as changes in collateral and working capital. FCF is used by management to evaluate the net cash flow from operations less capital and capital related investments and dividends. November 2016 28


 
EEI Financial Conference November 2016 9 Regulated Guidance Support Investing for Growth in the Regulated Business November 2016EEI Financial Conference 30 The scale and diversity of our regulated operations position FirstEnergy for sustained growth into the future Regulated Scale & Diversity 2016-2019 4-6% CAGR 2016-2019 7-9% CAGR with OH DMR OH Smart Grid Investment (Incremental Opportunity) Continuing Energizing the Future Forward- Looking Rates ATSI, TrAIL, MAIT, JCP&L


 
EEI Financial Conference November 2016 10 2016F Weather-Adjusted Operating EPS Midpoint* 2019F Operating EPS Regulated Operating Earnings Growth November 2016EEI Financial Conference 31 Targeting 4% - 6% Compound Annual Growth Rate Incremental 3% with Ohio DMR $2.47 Traditional Utility Growth 2016F – 2019F Including Ohio DMR 4% - 6% 7% - 9% * Estimated 2016 operating earnings for Regulated Distribution and Regulated Transmission segments of $2.59-$2.63 per share include $0.14 from the impact of weather. Refer to slide 21 for reconciliation between 2016F GAAP and Operating (non-GAAP) earnings. Regulated Weather-Adjusted Distribution Deliveries November 2016EEI Financial Conference 32 Residential Commercial Industrial M MWH 2016F 2017F 2018F 2019F 2016F-2019F CAGR % Sub-Total 42.9 42.7 42.6 42.3 -0.4% OH 15.2 15.2 15.2 15.1 -0.2% PA 12.9 12.8 12.8 12.7 -0.5% WV 3.7 3.7 3.7 3.7 - NJ 9.0 8.9 8.8 8.7 -1.0% MD 2.1 2.1 2.1 2.1 - M MWH 2016F 2017F 2018F 2019F 2016F-2019F CAGR % Sub-Total 50.3 51.9 52.6 53.3 2.0% OH 20.3 20.2 20.4 20.5 0.3% PA 20.4 21.5 21.1 21.1 1.2% WV 5.8 6.3 7.1 7.7 10.3% NJ 2.2 2.2 2.2 2.2 - MD 1.6 1.7 1.8 1.8 2.8% M MWH 2016F 2017F 2018F 2019F 2016F-2019F CAGR % Sub-Total 53.0 51.6 51.8 51.7 -0.9% OH 17.0 16.8 16.8 16.9 -0.1% PA 18.1 17.2 17.4 17.3 -1.6% WV 5.4 5.4 5.5 5.5 0.6% NJ 9.3 8.9 8.8 8.7 -2.3% MD 3.2 3.3 3.3 3.3 0.3% M MWH 2016F 2017F 2018F 2019F 2016F-2019F CAGR % Total 146.2 146.2 147.0 147.3 0.3% OH 52.5 52.2 52.4 52.5 0.0% PA 51.4 51.5 51.3 51.1 -0.2% WV 14.9 15.4 16.3 16.9 4.5% NJ 20.5 20.0 19.8 19.6 -1.5% MD 6.9 7.1 7.2 7.2 1.0% Total Deliveries Regulated Distribution


 
EEI Financial Conference November 2016 11 Guidance Sensitivities November 2016EEI Financial Conference 33 Estimated Impact of Annual Retail Sales Volumes + / - 1% Change in Residential MWH Sold ~$0.02/share + / - 1% Change in Commercial MWH Sold ~$0.01/share + / - 1% Change in Industrial MWH Sold ~$0.004/share Weather Impact on Residential/Commercial Sales Volumes + / - 90 HDD vs. normal (Dec-Mar) ~$0.01/share + / - 30 CDD vs. normal (June-Sept) ~$0.01/share Regulated Distribution Regulated Distribution Capital Plan (2016F - 2017F) November 2016EEI Financial Conference 34 $ Millions Stated Rate Formula Rate Total 2016F 2017F 2016F 2017F 2016F 2017F OH CEI $30 $30 $105 $95 $135 $125 OE 30 30 120 115 150 145 TE 10 10 35 35 45 45 Sub-total 70 70 260 245 330 315 NJ JCP&L 200 180 0 0 200 180 PA ME 75 90 35 45 110 135 PN 95 110 50 50 145 160 PP 25 20 20 25 45 45 WPP 110 105 45 70 155 175 Sub-total 305 325 150 190 455 515 WV / MD MP 145 150 75 60 220 210 PE 80 90 10 15 90 105 Sub-total 225 240 85 75 310 315 Total $800 $815 $495 $510 $1,295 $1,325 FE Consolidated


 
EEI Financial Conference November 2016 12 Regulated Transmission Regulated Transmission Capital Plan (2016F - 2021F) November 2016EEI Financial Conference 35 $ Millions 2016F 2017F 2018F 2019F 2020F 2021F Former Allegheny (WPP/MP/PE) $55 $90 $90 $95 $95 $95 Former GPU (ME/PN) 55 - - - - - JCP&L 185 - - - - - Stated Rate Sub-total 295 90 90 95 95 95 ATSI 495 420 270 - 470 290 - 490 300 - 500 300 - 500 TrAIL Co. 210 60 35 30 25 25 MAIT - 260 280 - 480 260 - 460 250 - 450 250 - 450 JCP&L - 170 125 125 130 130 Formula Rate Sub-total 705 910 710 - 1,110 705 - 1,105 705 - 1,105 705 - 1,105 Regulated Transmission – Total $1,000 $1,000 $800 - $1,200 $800 - $1,200 $800 - $1,200 $800 - $1,200 Last 2 Years of Our 2014-2017 Energizing the Future Plan $2B Continuing Our Energizing the Future Plan $4.2B - $5.8B Regulated Transmission Capital Opportunities November 2016EEI Financial Conference 36 $ Millions Phase 2 Energizing The Future Future Opportunities Beyond 2021F 2017F – 2021F ATSI $1,580 – $2,380 • Existing transmission infrastructure creates $1B+ in reliability improvement investment opportunities annually TrAIL Co. 175 MAIT 1,300 – 2,100 JCP&L 680 Formula Rates Sub-total $3,735 – $5,335 Stated Rates $465 Regulated Transmission – Total $4,200 - $5,800 $20,000+ Regulated Transmission Long runway for growth to increase reliability for customers


 
EEI Financial Conference November 2016 13 Regulated Distribution Rate Base Growth (2016F-2019F) November 2016EEI Financial Conference 37 $0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 2016F 2017F 2018F 2019F MD WV NJ PA OH $M Regulated Distribution Regulated Transmission Rate Base Growth (2016F-2021F) Formula Rate Transmission Companies $0 $1,500 $3,000 $4,500 $6,000 $7,500 2016F 2017F 2018F 2019F 2020F 2021F JCP&L TrAIL MAIT ATSI November 2016EEI Financial Conference 38 $M Regulated Transmssion Note: 2018F – 2021F assumes midpoint of ~$900M per year of Regulated Transmission formula rate spend Regulated Transmission


 
EEI Financial Conference November 2016 14 Competitive Guidance Support 2016F Adjusted EBITDA Competitive Energy Services November 2016EEI Financial Conference Closed Q1-Q3 Contract Sales: 41M MWH $825 $90 - $100 $815 $920 - $950CES 2016F Adjusted EBITDA(2) Closed Q1-Q3 Wholesale: 10M MWH(1) $175 Committed Q4 Contract Sales: 12M MWH $210 - $230 Q4 Open: 3M MWH (Excludes ~3M MWH of annual distribution losses/pumping) ($1,365) 2016F ($M) Capacity Revenue Other Revenue Average $/MWh $54 Contract Rate less ($18) Supply Cost less ($16) Delivery Cost $20 avg. net margin $28 Wholesale Price plus $7 Financial Gain less ($18) Supply Cost $17 avg. net margin $27-$29 Wholesale Price plus $4 - $3 Financial Gain less ($18) Supply Cost $13-14 avg. net margin $51 Contract Rate less ($18) Supply Cost less ($14 – 15) Delivery Cost $18-19 avg. net margin Other Operating Expenses $170 Q4 Financially-Hedged: 4M MWH Total Q4 Wholesale:7M MWH See slide 41 for additional notes describing the line items 1 9M MWH notional amount of Q1-Q3 wholesale sales were hedged financially 2 Total CES 2016F Adjusted EBITDA, a non-GAAP financial measure, is reconciled to 2016F CES Net Income on slide 46, and is based on market prices as of September 30, 2016 40 Competitive


 
EEI Financial Conference November 2016 15 Notes on 2016F Adjusted EBITDA Competitive Energy Services November 2016EEI Financial Conference 41 Closed Q1- Q3 Contract Sales:  Includes actual physical volume of contract sales through 09/30/2016  Contract Rate represents average realized rate based on actual committed contract prices and customer usage  Supply Cost rate represents the overall realized cost of all supply sources to serve contract sales obligations, including Fuel (coal, natural gas and nuclear generation) and Purchased Power (firm and spot purchased power). Average Fossil fuel rate = $24/MWH and Average Nuclear fuel rate = $7/MWH.  Delivery Cost rate represents the average realized capacity and transmission expenses, including delivery expenses associated with serving loads and net of transmission revenues (including Financial Transmission Rights and ancillary services) Committed Q4 Contract Sales:  Expected physical volume and average realized rate of contract sales based on expected power flow for the remainder of 2016  Volume is subject to fluctuations due to weather and customer behavior Closed Q1-Q3 Wholesale:  Includes actual volume of physical wholesale spot sales at the average realized price and Financial Gains through 9/30/2016  Financial Gains represent the impact of realized gains on settlement of forward financially-settled transactions Total Q4 Wholesale:  Includes expected volume of physical wholesale spot sales for the remainder of 2016 at a range of expected realized prices at CES’ generation resources and based on 9/30/2016 market forwards. Includes volumes that may be sold through incremental Contract Sales  A portion of the total expected volume of physical spot sales into PJM is price-hedged through forward financial transactions that will settle at Q4 market prices. Financial gain range is based on expected settlement value of the notional amount of firm forward financial wholesale sales transactions at a forward AD Hub price range of $27-$29/MWH.  Volume is subject to energy market prices and generating unit performance Capacity Revenue:  Capacity revenue includes revenues from legacy BRA, incremental/transitional capacity auctions, bilateral transactions and capacity transmission rights Other Revenue:  Projected annual non-commodity revenue primarily comprised of lease revenue on sale and leaseback transactions and other affiliated transactions, that is included in “Revenues – Unregulated Businesses” on the Consolidated Statements of Income.  Excludes Investment Income that is excluded from Adjusted EBITDA (see slide 46) Other Operating Expenses:  Projected annual expenses related primarily to generation, retail, corporate support and general taxes, that are included in “Other Operating Expenses” on the Consolidated Statements of Income  Excludes Income Taxes, Depreciation, Amortization and Interest Expense, net, that is excluded from Adjusted EBITDA (see slide 46) Competitive 2017F Adjusted EBITDA Competitive Energy Services November 2016EEI Financial Conference 42 Committed Contract Sales: 32M MWH Total 2017 Wholesale: 41M MWH Capacity Revenue 2017F ($M) $51 Contract Rate less ($18) Supply Cost less ($14 – 15) Delivery Cost $18 - 19 avg. net margin $580 - $620 $30-$32 Wholesale Price plus $2 - $1 Financial Gain less ($18) Supply Cost $14-$15 avg. net margin $580 - $605 $590 $595 - $660CES 2017F Adjusted EBITDA(1) Average $/MWh (Excludes ~3M MWH of annual distribution losses/pumping) 2017 Open: 25M MWH 2017 Financially-Hedged: 16M MWH Other Revenue Other Operating Expenses ($1,230) $75 See slide 43 for additional notes describing the line items 1 Total CES 2017F Adjusted EBITDA, a non-GAAP financial measure, is reconciled to 2017F CES Net Income on slide 46, and is based on market prices as of September 30, 2016 Competitive


 
EEI Financial Conference November 2016 16 Notes on 2017F Adjusted EBITDA Competitive Energy Services November 2016EEI Financial Conference 43 Committed Contract Sales:  Includes expected physical volume of contract sales  Volume is subject to fluctuations due to weather and customer behavior  Contract Rate represents average expected rate based on committed contract prices and customer usage. Portions of “committed” governmental aggregation sales are not priced-fixed as they are indexed to utility price-to-compare  Supply Cost rate represents the overall average expected cost of all supply sources to serve contract sales obligations, including Fuel (coal, natural gas and nuclear generation) and Purchased Power (firm and spot purchased power) Average Fossil fuel rate = $24/MWH and Average Nuclear fuel rate = $7/MWH  Delivery Cost rate represents the average expected capacity and transmission expenses, including delivery expenses associated with serving loads and net of transmission revenues (including Financial Transmission Rights and ancillary services) Total 2017 Wholesale:  Includes expected physical volume of wholesale spot sales given current Committed Contract Sales at a range of expected realized prices at CES’ generation resources and based on 9/30/2016 market forwards. Includes volumes that may be sold through incremental Contract Sales  A portion of the total expected volume of physical spot sales into PJM is price-hedged through forward financial transactions that will settle at 2017 market prices. Financial gain range is based on expected settlement value of the notional amount of firm forward financial wholesale sales transactions at a forward AD Hub price range of $30-$32/MWH  Volume is subject to energy market prices and generating unit performance Capacity Revenue:  Capacity revenue includes revenues from Base Residual/Capacity Performance auctions, incremental/transitional capacity auctions, bilateral transactions and capacity transmission rights Other Revenue:  Projected annual non-commodity revenue primarily comprised of lease revenue on sale and leaseback transactions and other affiliated transactions, that is included in “Revenues – Unregulated Businesses” on the Consolidated Statements of Income.  Excludes Investment Income that is excluded from Adjusted EBITDA (see slide 46) Other Operating Expenses:  Projected annual expenses related primarily to generation, retail, corporate support and general taxes, that is included in “Other Operating Expenses” on the Consolidated Statements of Income  Excludes Income Taxes, Depreciation, Amortization and Interest Expense, net, that is excluded from Adjusted EBITDA (see slide 46) Competitive 2018F Adjusted EBITDA Competitive Energy Services November 2016EEI Financial Conference 44 Committed Contract Sales: 16M MWH Capacity Revenue 2018F ($M) $50 Contract Rate less ($17) Supply Cost less ($15 – 16) Delivery Cost $17 - 18 avg. net margin $270 - $290 $29-$31 Wholesale Price less ($17) Supply Cost $12-$14 avg. net margin $650 - $750 $620 $275 - $395CES 2018F Adjusted EBITDA(1) Average $/MWh (Excludes ~2M MWH of distribution losses/pumping) Total 2018 Wholesale: 55M MWH 2018 Open: 43M MWH 2018 Financially-Hedged: 12M MWH Other Revenue Other Operating Expenses ($1,285) $20 See slide 45 for additional notes describing the line items 1 Total CES 2018F Adjusted EBITDA, a non-GAAP financial measure, is reconciled to 2018F CES Net Income on slide 46, and is based on market prices as of September 30, 2016 Competitive


 
EEI Financial Conference November 2016 17 Notes on 2018F Adjusted EBITDA Competitive Energy Services November 2016EEI Financial Conference 45 Committed Contract Sales:  Includes expected physical volume of contract sales  Volume is subject to fluctuations due to weather and customer behavior  Contract Rate represents average expected rate based on committed contract prices and customer usage. Portions of “committed” governmental aggregation sales are not priced-fixed as they are indexed to utility price-to-compare  Supply Cost rate represents the overall average expected cost of all supply sources to serve contract sales obligations, including Fuel (coal, natural gas and nuclear generation) and Purchased Power (firm and spot purchased power). Average Fossil fuel rate = $24/MWH and Average Nuclear fuel rate = $7/MWH  Delivery Cost rate represents the average expected capacity and transmission expenses, including delivery expenses associated with serving loads and net of transmission revenues (including Financial Transmission Rights and ancillary services) Total 2018 Wholesale:  Includes expected physical volume of wholesale spot sales given current Committed Contract Sales. Includes volumes that may be sold through incremental Contract Sales  Volume is subject to energy market prices and generating unit performance Capacity Revenue:  Capacity revenue includes revenues from Base Residual/Capacity Performance auctions, incremental/transitional capacity auctions, bilateral transactions and capacity transmission rights Other Revenue:  Projected annual non-commodity revenue primarily comprised of lease revenue on sale and leaseback transactions and other affiliated transactions, that is included in “Revenues – Unregulated Businesses” on the Consolidated Statements of Income  Excludes Investment Income that is excluded from Adjusted EBITDA (see slide 46) Other Operating Expenses:  Projected annual expenses related primarily to generation, retail, corporate support and general taxes, that is included in “Other Operating Expenses” on the Consolidated Statements of Income  Excludes Income Taxes, Depreciation, Amortization and Interest Expense, net, that is excluded from Adjusted EBITDA (see slide 46) Competitive Net Income (Loss) to Adjusted EBITDA1 Reconciliation Competitive Energy Services November 2016EEI Financial Conference 46 ($ Millions) 2016F 2017F 2018F Net Income (Loss) – GAAP ($1,200) - ($1,125) ($20) – $35 ($225) - ($140) Special Items (after tax)1 1,425 – 1,375 15 - Operating Earnings (Loss) $225 - $250 ($5) – $50 ($225) - ($140) Income Taxes2 130 – 145 0 – 30 (130) – (75) Interest Expense, Net 150 – 145 165 – 155 170 – 160 Depreciation 390 - 385 430 – 425 455 – 450 Amortization3 95 55 55 Investment Income (70) (50) – (55) (50) – (55) Adjusted EBITDA1 $920 – $950 $595 - $660 $275 - $395 Competitive 1 Adjusted EBITDA is a non-GAAP measure and represents GAAP net income adjusted for special items listed on slides 21-25 and the addition of Income Taxes; Interest Expense, net; Depreciation, Amortization and Investment Income 2 Income taxes excluding the tax effect of special items are summarized on slides 21-25 3 Amortization expense included in Other Operating Expenses on the Consolidated Statements of Income. Primarily relates to amortization of customer contract intangible assets, as disclosed in Form 10-K Note 7 - Intangible Assets, including a $32M non-cash charge in 2016 associated with the termination of an FES customer contract, and deferred costs on sale leaseback transaction, net, as disclosed in the Consolidated Statements of Cash Flows. Does not include nuclear fuel amortization of approximately $225M, $210M and $215M, in 2016, 2017 and 2018, respectively


 
EEI Financial Conference November 2016 18 Guidance Sensitivities November 2016EEI Financial Conference 47 Sensitivities on Open Position to Adjusted EBITDA Sensitivity 2016 2017 2018 + / - $5/MWH ATC Energy Prices $15M $125M $215M Fuel Cost Exposure + / - $1/MMBTU Natural Gas - $20M $30M + / - $5/Ton Eastern Coal - $20M $50M + / - $1/MWH Nuclear Fuel - - - Hedged Fuel Percentages 2016 2017 2018 Coal (Volume) 100% 70 - 75% 70 - 75% Coal (Price) 100% 70 - 75% 20 - 25% Nuclear Fuel 100% 100% 100% Nuclear Refueling Outage Impact Average O&M Expense per RFO ~$45M + / - 1 RFO ~$0.07/share Competitive CES Generation Forecast (2016F-2018F) November 2016EEI Financial Conference 48 Nuclear Coal 0 20 40 60 80 100 2016F 2017F 2018F Incremental generation based on market conditions Purchased Power* * Purchased Power includes renewables/OVEC and additional bilateral and spot purchases M MWH Gas/Hydro Available generation resources of ~80 - 85M MWH annually Competitive


 
EEI Financial Conference November 2016 19 ($ Millions) $195 $190 $175 $150 $125 $100 $195 $55 $25 $0 $100 $200 $300 $400 $500 $600 2016F 2017F 2018F Major Projects Baseline - Fossil Baseline - FENOC* Competitive Energy Services Capital Plan (2016F - 2018F) November 2016EEI Financial Conference 49 Baseline nuclear spend of $175M- $195M annually to ensure safety, maintain assets, and meet regulatory standards Baseline fossil spend of $100M- $150M annually to ensure safety and preserve strategic options going forward Decreasing major projects spend due to completion of Mansfield Dewatering Facility, MATS spend, and the delay of the BV2 steam generator & reactor head replacement * Excludes nuclear fuel $540 $370 $300 Competitive 2016F-2018F CES Funds From Operations EEI Financial Conference Funds from Operations (FFO) is a non-GAAP measure that management uses to monitor its credit metrics consistent with credit rating agencies November 2016 50 ($ Millions) Competitive Energy Services 2016F 2017F 2018F Net Income (Loss) – GAAP ($1,200) – ($1,125) ($20) – $35 ($225) – ($140) Income Taxes (Benefits)1 (195) – (165) (10) – 20 (130) – (80) Income (Loss) Before Income Taxes (Benefits) (1,395) – (1,290) (30) - 55 (355) – (220) Cash Receipts on Income Taxes2 120 – 100 225 – 200 250 – 200 Depreciation & Amortization3 710 – 705 695 – 690 725 – 720 Asset and Investment Impairments4 1,460 - - Lease Payments on Sale & Leaseback Transactions (120) (75) (100) Pension/OPEB Mark-to-Market Adjustment4 225 – 130 - - Other5 40 – 80 50 - 55 60 – 90 Funds From Operations (Non-GAAP) $1,040 - $1,065 $865 - $925 $580 - $690 1 Income Taxes include the current and deferred tax effect on GAAP earnings 2 Current tax receipts under inter-company tax sharing agreement with FirstEnergy affiliates 3 Depreciation & Amortization includes nuclear fuel amortization of $225M, $210M, and $215M in 2016-2018, respectively, and Depreciation & Amortization on slide 46 4 Includes non-cash impairment of assets as included in CES’ Results of Operations for the nine month period ended September 30, 2016, and Investment Impairments as included on FES’ Statement of Cash Flow for the nine month period ended September 30, 2016 5 Other includes other non-cash items and non-operating items according to rating agency methodologies Competitive


 
EEI Financial Conference November 2016 20 2016F-2018F CES Free Cash Flow EEI Financial Conference November 2016 51 ($ Millions) Competitive Energy Services 2016F 2017F 2018F Funds From Operations (FFO) (Non-GAAP) $1,040 - $1,065 $865 - $925 $580 - $690 Capital Expenditures1 (540) (370) (300) Nuclear Fuel (215) (175) (195) Cash Before Other Items $285 - $310 $320 - $380 $85 - $195 Pension Contribution (190) - - Sale-Leaseback Repurchases (50) (40) - Working Capital/Other2 45 - 60 (160) – (120) (20) - 20 Free Cash Flow3 (Non-GAAP) $90 - $130 $120 - $220 $65 - $215 Free Cash Flow (FCF) is a non-GAAP measure and represents funds from operations less capital expenditures, nuclear fuel purchases and pension trust contributions, as well as changes in collateral and working capital. FCF is used by management to evaluate the net cash flow from operations less capital and capital related investments. 1 Excludes capital component of any year-end Pension/OPEB mark-to-market adjustment 2 Primarily includes changes in working capital which is included in “Changes in Current Assets and Liabilities” on the Consolidated Statements of Cash Flows, NDT interest and dividend income which is included in “Purchases of Investment Securities Held in Trust” on the Consolidated Statements of Cash Flows, and non-cash stock based compensation expense included in Form 10-K “Note 4. Stock-Based Compensation Plans” 3 Excludes cash items related to debt financing activity Competitive PJM RPM Capacity Auctions November 2016EEI Financial Conference 52 Base Residual (BRA) and Capacity Performance (CP) Transitional Auction Results Price per MW-Day ATSI RTO MAAC EMAAC ComEd 2016/2017 BRA $114.23 $59.37 $119.13 $59.37 CP $134.00 2017/2018 BRA $120.00 CP $151.50 2018/2019 Base $149.98 $210.63 $200.21 CP $164.77 $225.42 $215.00 2019/2020 Base $80.00 $99.77 $182.77 CP $100.00 $119.77 $202.77 Net Competitive Capacity Position (MW) 2016 / 2017 2017 / 2018 2018 / 2019 2019 / 2020 Legacy CP Uncommitted Legacy CP Uncommitted Base CP Uncommitted Base CP Uncommitted ATSI 2,765 4,210 615 375 6,245 200 - 6,245 525 - 5,680 1,075 RTO 875 3,675 120 985 3,565 - 240 3,930 450 245 3,690 690 All Other Zones 135 - 10 150 - - 35 20 40 35 20 45 TOTAL 3,775 7,885 745 1,510 9,810 200 275 10,195 1,015 280 9,390 1,810 Competitive


 
EEI Financial Conference November 2016 21 Market Prices: Historical Basis Values November 2016EEI Financial Conference 53 A negative value means the Locational Marginal Price (LMP)* at the source is greater than the LMP at the sink Source Sink 2015 ($/MWH) 2016** ($/MWH) FE OH Ill Hub (6.01) (1.68) FE OH Comed (4.66) (2.14) FE OH DTE (3.73) (0.55) FE OH MichFE (4.09) (0.74) FE OH PJM West Hub 3.14 1.02 FE OH DQE (1.73) (0.65) FE OH AD Hub (1.19) (0.67) FE OH AEP (0.47) (0.26) FE OH Duke Ohio (0.85) (0.57) Allegheny Power System AD Hub (3.53) (1.22) Allegheny Power System DQE (4.07) (1.20) Allegheny Power System PJM West Hub 0.80 0.47 Allegheny Power System Penelec (1.37) (1.89) PJM West Hub PPL (2.81) (4.83) PJM West Hub PSEG (0.65) (4.10) PJM West Hub PECO (2.69) (4.89) PJM West Hub JCP&L (2.02) (4.65) PJM West Hub Met-Ed (2.88) (4.41) PJM West Hub Penelec (2.17) (2.36) *Values shown are around-the-clock, day-ahead average basis values ** As of September 30, 2016 Competitive


 
EEI Financial Conference November 2016 22 Financial Support Financial Plan ■ Continued focus on Regulated Transmission growth; expected combination of $500M equity in each year 2017-2019 and long-term financings to support growth ■ Continued focus on strengthening Regulated Distribution balance sheets ■ Expect positive free cash flow at CES through the transition period ■ Continue to issue ~$100M equity annually through the stock investment / employee benefit plans November 2016EEI Financial Conference 55 Committed to investment-grade credit ratings at all regulated entities and FE Corp. Financial


 
EEI Financial Conference November 2016 23 Debt Financing Plan (2017F – 2019F) November 2016EEI Financial Conference 56 Competitive Energy Services Year Entity Amount Purpose 2017 FG $129.6 PCRB mandatory put date 4/1/18 2018 NG $98.9M PCRB mandatory put date 4/1/18 FG $141.3M PCRB final maturity 6/1/18 NG $15.2M PCRB mandatory put date 7/2/18 FG $260.5M PCRB mandatory put date 12/1/18 Regulated Transmission Year Entity Amount Purpose 2017 ATSI $150M New Issuance 2018 ATSI $125M New issuance FET $150M New issuance MAIT $575M New issuance 2019 MAIT $100M New issuance Regulated Distribution Year Entity Amount Purpose 2017 CEI $250M $130M at 5.7% maturing 4/1/17 $300M at 7.88% maturing 11/1/17 MP $300M $150M at 5.7% maturing 3/15/17 PN $300M $300M at 6.05% maturing 9/1/17 2018 CEI $250M $300M at 8.875% maturing 11/15/18 JCP&L $150M $150M at 4.8% maturing 6/15/18 2019 JCP&L $300M $300M at 7.35% maturing 2/1/19 ME $300M $300M at 7.7% maturing 1/15/19 PN $125M $125M at 6.625% maturing 4/1/19 FE Corp Year Entity Amount Purpose 2018 FE Corp $650M $650M at 2.75% maturing 3/15/18 2019 FE Corp $1B Refinance variable-rate term loan maturing 3/31/19 Financial Financial – Pension/OPEB Overview ■ FE is the administrator and guarantor for employees at all of FE’s subsidiaries ■ Pension Status is Open – The plan design was changed to a Cash Balance formula for new hires beginning 1/1/2014 – Employees hired before 1/1/2014 are covered under a Final Average Pay formula ■ Pension/OPEB Expense impacts Operating Earnings based on a post-capitalization calculation of net periodic costs (excluding mark-to- market adj.) – Key assumptions for 2016 expense include: – Expected Return on Assets of 7.50% – Discount Rate (beginning of year): 4.50% (Pension) / 4.25% (OPEB) – Key assumptions for 2017 expense include: – Expected Return on Assets of 7.50% – Discount Rate (beginning of year): 3.75% (Pension) / 3.50% (OPEB) ■ Regulated Utility Recovery – Pension – PA: Based on historical contributions of the last 10 years – OH: Current year service costs – MD: GAAP Expense – WV: GAAP Expense (Last rate case was settled, but included GAAP Expense with modified MTM adjustments) – NJ: GAAP Expense (Last rate case excluded the MTM charge and used a modified calculation) – OPEB – PA: Service cost in 2017 test year (as originally filed for in 2016 rate case – the method of calculating or the amount included in the settlement was not specified) – OH: Current year service costs – MD: GAAP Expense – WV: GAAP Expense (Last rate case was settled, but included GAAP Expense with modified MTM adjustments) – NJ: GAAP Expense (Last rate case excluded the MTM charge and used a modified calculation) November 2016EEI Financial Conference 57 Financial


 
EEI Financial Conference November 2016 24 Financial – Pension/OPEB Overview November 2016EEI Financial Conference 58 Financial $ Millions Corp FEU FES FENOC Total Notes Qualified Pension ($1,366) ($1,155) ($282) ($563) ($3,366) Assuming $500M equity contribution expected in 2016, no funding requirement until 2018 Non-Qualified Pension (154) (156) (22) (43) (375) No minimum funding requirements OPEB 52 (414) 25 44 (293) No minimum funding requirements Total ($1,468) ($1,725) ($279) ($562) ($4,034) ■ Pension/OPEB Funded Status: Year-End 2015 Actual ■ Components of Net Periodic Benefit Costs: 2015A-2017F (excluding Pension/OPEB mark-to-market adjustment) ■ Post-Capitalization – Net Periodic Benefit Costs: 2015A-2017F (excluding Pension/OPEB mark-to-market adjustment) Pension OPEB Total $ Millions 2015A 2016F 2017F 2015A 2016F 2017F 2015A 2016F 2017F Service Cost $193 $190 $230 $5 $5 $5 $198 $195 $235 Interest Cost 383 400 370 29 30 30 412 430 400 Expected Return on Assets (443) (400) (440) (33) (30) (30) (476) (430) (470) Amortization of prior service cost (credit) 8 10 5 (134) (80) (80) (126) (70) (75) Net Periodic Cost (Credit) $141 $200 $165 ($133) ($75) ($75) $8 $125 $90 Pension OPEB Total $ Millions 2015A 2016F 2017F 2015A 2016F 2017F 2015A 2016F 2017F Utilities $23 $55 $35 ($49) ($20) ($20) ($26) $35 $15 FES / FENOC 71 95 90 (41) (35) (35) 30 60 55 -5,000 -4,000 -3,000 -2,000 -1,000 0 Funded Status @ YE2015 Interest & Service Costs Impact of Discount Rate Planned Contributions EROA 7.50%, ~11% Earned YTD Expected Funded Status @ YE2016 Qualified Pension – Additional Details ■ Key assumptions: – Expected Return on Assets of 7.50% – Discount Rate of 4.50% BOY; 3.75% EOY – 25 bps change in discount rate  ~$300M change in liability – No impact of actuarial changes, which are updated annually based on participant census data ■ Key assumptions: – Expected Return on Assets of 7.50% – Discount Rates at year-end: – 2015A – 4.50% – 2016F – 3.75% – 2017F – 4.00% – 2018F – 4.25% – 2019F – 4.50% – $500M Equity Contribution expected in 2016 November 2016EEI Financial Conference 59 2016F Funded Status Projected Funding Levels 61% Funded 66% Funded 67% Funded 74% Funded 80% Funded $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 2015A 2016F 2017F 2018F 2019F PBO Plan Assets $ Millions (900) 885 620(565) (3,366) (3,326) Financial $ Millions


 
EEI Financial Conference November 2016 1 Reference Materials OH VA WV PA MD NJ MI INIL Jointly Owned Plant Regulated Plants Competitive Generating Plants 230, 345 and 500 kV Transmission Lines Competitive retail footprint Utility footprint FirstEnergy Overview EEI Financial Conference November 2016 61 OUR MISSION We are a forward-thinking electric utility powered by a diverse team of employees committed to making customers’ lives brighter, the environment better and our communities stronger. ~24,200+ Miles Transmission Lines $52B 2015 Total Assets $15B 2015 Annual Revenues ~6 Million Total Customers ~17,000 MW Total Generation


 
EEI Financial Conference November 2016 2 Summary Organizational Structure November 2016EEI Financial Conference 62 FirstEnergy Corp.* (FE) FE Utilities FE Transmission Competitive Energy Services Monongahela Power Company* (MP) The Potomac Edison Company* (PE) West Penn Power Company* (WPP) Jersey Central Power & Light Company* (JCP&L) Metropolitan Edison Company** (ME) Pennsylvania Electric Company** (PN) FirstEnergy Nuclear Generation, LLC (NG) FirstEnergy Generation, LLC* (FG) The Waverly Electric Light and Power Company FirstEnergy Solutions Corp.* (FES) Allegheny Energy Supply Company, LLC* (AE Supply) Allegheny Generating Company (AGC) FirstEnergy Nuclear Operating Company (FENOC) FirstEnergy Transmission, LLC (FET) American Transmission Systems, Incorporated (ATSI) AET PATH Company, LLC * (PATH) Trans-Allegheny Interstate Line Company (TrAILCo) Ohio Edison Company* (OE) The Cleveland Electric Illuminating Company* (CEI) Pennsylvania Power Company (PP) The Toledo Edison Company* (TE) * Entity has subsidiaries that are not shown **Transmission assets to be transferred to MAIT effective December 31, 2016 Mid-Atlantic Interstate Transmission, LLC (MAIT) Springdale 1-5 638 West Lorain 1-6 545 Chambersburg 12 & 13 88 Gans 8 & 9 88 Forked River 86 Hunlock 45 Buchanan 43 Other 59 Total Gas/Oil 1,592 Bath County 1,200 Regulated: 487 Competitive: 713 Yards Creek (R) 210 Total Hydro 1,410 Blue Creek 100 High Trail 99 Allegheny Ridge 80 N. Allegheny Ridge 70 Highland 62 Casselman 35 Meyersdale 30 Total Wind 476 Maryland Solar 20 Total Solar 20 Mansfield 1-3 2,490 Harrison 1-3 (R) 1,984 Pleasants 1 & 2 1,300 Sammis 6 & 7 1,200 Fort Martin 1 & 2 (R) 1,098 Total Supercritical Coal 8,072 Sammis 1-4* 720 Sammis 5 290 Bay Shore 1* 136 OVEC 188 Regulated: 11 Competitive: 177 Total Subcritical Coal 1,334 Beaver Valley 1 & 2 1,872 Perry 1,268 Davis-Besse 908 Total Nuclear 4,048 Generation Portfolio November 2016EEI Financial Conference 63 55% Coal 24% Nuclear <1% Solar 3% Wind 9% Gas/Oil 9% Hydro MW Total 16,952 MW Competitive 13,162 MW Regulated 3,790 MW MW MW *Bay Shore 1 expected to be sold or deactivated by October 1, 2020. Sammis 1-4 expected to be deactivated by May 31, 2020.


 
EEI Financial Conference November 2016 3 Regulated Distribution Operating Companies 10 Customers 6M States 6 Regulated Distribution – Segment Overview ■ 10 operating companies serving ~6 million customers across 6 states – One of the largest contiguous service territories in the U.S. – Balanced customer sales mix of approximately 1/3 residential, 1/3 commercial, 1/3 industrial – Includes 3,790 MW of regulated generation; primarily serving West Virginia ■ ~$9.6B of Total Revenues in 2015 ■ ~$12.5B in Rate Base at YE 2015 November 2016EEI Financial Conference As of December 31, 2014 State Operating Companies Ohio OE, CEI, TE Pennsylvania ME, PN*, PP, WPP New Jersey JCP&L West Virginia MP, PE-WV Maryland PE-MD Regulated Distribution Companies Plant MW Fuel Type Harrison 1-3 1,984 Supercritical Coal Fort Martin 1-2 1,098 Supercritical Coal Bath County 487 Hydro Yards Creek 210 Hydro OVEC 11 Subcritical Coal Total 3,790 Regulated Generating Plants 65 *Includes 4K customers in New York


 
EEI Financial Conference November 2016 4 Earned vs. Allowed Distribution ROEs EEI Financial Conference November 2016 66 10.8% 5.2% 6.1% 5.1% 7.0% 5.5% 8.1% 2.1% 9.4% 10.3% 8.1% 10.5% 10.5% 10.5% 9.8% 11.9% 0% 3% 6% 9% 12% 15% OE CEI TE PP ME PN WPP JC MP PE-WV PE-MD Earned ROE Allowed ROE Impact of a 50 basis point change in Earned Distribution ROE on Annual Earnings Per Share OE CEI TE PP ME PN WPP JC MP PE-WV PE-MD $0.01 <$0.01 <$0.01 <$0.01 $0.01 $0.01 <$0.01 $0.01 $0.01 <$0.01 <$0.01 OH: SEET Filings (YE 2015) PA: PA PUC Bureau of the Technical Utility Services Report (YE 2015) NJ: As filed on September 30, 2016, in base rate case update (ROE as of June 30, 2016) WV: Source –WV/MD Rates; Quarterly reports filed with WV Commission (Q2 2016) MD: Source –WV/MD Rates; Quarterly reports filed with MD Commission (Q2 2016) Settled Settled $87.24 $88.50 $89.34 $100.77 $106.78 $96.32 $91.93 $50 $75 $100 $125 $150 CEI OE TE AEP (CS) AEP (OP) DP&L Duke Average Customer Bills Rates Effective July 1, 2016 November 2016EEI Financial Conference Pennsylvania New Jersey Maryland Ohio West Virginia State Average FirstEnergy Other *Average residential monthly usage in OH and NJ 750 kWh, all other states 1,000 kWh $92.66 $127.74 $134.48 $50 $75 $100 $125 $150 JCP&L PSE&G RECO $117.30 $132.60 $118.11 $109.46 $149.99 $151.45 $139.22 $134.99 $117.02 $50 $75 $100 $125 $150 $175 ME PN PP WPP DUQ PECO Pike PPL UGI $103.96 $152.98 $160.75 $149.44 $50 $75 $100 $125 $150 $175 PE BG&E PEPCO (MC) PEPCO (PGC) $109.89 $109.89 $120.93 $120.93 $50 $75 $100 $125 MP PE AEP (WP) AEP (AP) 67


 
EEI Financial Conference November 2016 5 Ohio Overview November 2016EEI Financial Conference 68 Rate Base and ROE Information Company Rates Effective 11/30/15 Rate Base Allowed Debt / Equity Allowed ROE OE January 2009 $1,408M 51% / 49% 10.5% CEI May 2009 $1,192M 51% / 49% 10.5% TE January 2009 $427M 51% / 49% 10.5% Recovery Mechanisms Purchased Power / Fuel Rider Storm Cost Recovery Incremental Capital Recovery Energy Efficiency Smart Meter / Smart Grid Alternative Energy Annually Base Rates Quarterly Semi Annually Quarterly Quarterly Governor Current Term John Kasich (R) Expires in 2019 Political Overview Public Utilities Commission (PUCO) Current Term Asim Z. Haque, Chairman (I) Expires in 2021 M. Beth Trombold, Vice Chair (I) Expires in 2018 Lynn Slaby (R) Expires in 2017 Thomas W. Johnson (R) Expires in 2019 M. Howard Petricoff (D) Expires in 2020 (000s) Year-End 2015 OE 1,038 CEI 746 TE 308 2,092 Number of Customers Principal Industries Served Primary and Fabricated Metals, Automotive, Chemical, Plastic & Rubber, Petroleum 75 100 125 150 CEI OE TE CAIDI 0.0 0.5 1.0 1.5 CEI OE TE SAIFI 2015 Actuals Minimum Targets 2015 Reliability Information MinutesAvg. Customer Interruptions Pennsylvania Overview EEI Financial Conference November 2016 69 Governor Current Term Thomas W. Wolf (D) Expires in 2019 Political Overview PA Public Utility Commission (PAPUC) Current Term Gladys M. Brown, Chairman (D) Expires in 2018 Andrew G. Place, Vice Chairman (D) Expires in 2020 David W. Sweet (D) Expires in 2021 John F. Coleman, Jr. (R) Expires in 2017 Robert F. Powelson (R) Expires in 2019 (000s) Year-End 2015 PN 588 ME 561 PP 164 WPP 723 2,036 Number of Customers Principal Industries Served Primary and Fabricated Metals, Coal Mining, Chemical, Plastic & Rubber, Non-Metallic Minerals Rate Base and ROE Information Company Rates Effective YE 2015 Rate Base Allowed Debt / Equity Allowed ROE PN May 2015 $1,433M 52.3% / 47.7% Settled ME May 2015 $1,363M 51.6% / 48.4% Settled PP May 2015 $360M 41.8% / 58.2% Settled WPP May 2015 $1,146M 50.5% / 49.5% Settled Recovery Mechanisms Purchased Power / Fuel Rider Storm Cost Recovery Incremental Capital Recovery Energy Efficiency Smart Meter / Smart Grid Alternative Energy Quarterly Base Rates Quarterly Annually Annually Annually 50 100 150 200 250 ME PN PP WPP CAIDI 0.0 0.5 1.0 1.5 2.0 ME PN PP WPP SAIFI 2015 Reliability Information 2015 Actuals Minimum Targets MinutesAvg. Customer Interruptions


 
EEI Financial Conference November 2016 6 New Jersey Overview As of December 31, 2014 EEI Financial Conference November 2016 70 Governor Current Term Christopher J. Christie (R) Expires in 2018 Political Overview NJ Board of Public Utilities (BPU) Current Term President Richard S. Mroz (R) Expires in 2021 Dianne Solomon (R) Expires in 2018 Joseph L. Fiordaliso (D) Expires in 2019 Upendra Chivukula (D) Expires in 2020 Mary-Anna Holden (R) Expires in 2017 (000s) Year-End 2015 JCP&L 1,109 Number of Customers Principal Industries Served Chemical, Primary and Fabricated Metals, Plastic & Rubber 0 50 100 150 200 Central NJ Northern NJ CAIDI 0.0 0.5 1.0 1.5 Central NJ Northern NJ SAIFI 2015 Actuals Minimum Targets 2015 Reliability Information Recovery Mechanisms Purchased Power / Fuel Rider Storm Cost Recovery Energy Efficiency Alternative Energy Annually Base Rates / SRC Rider Annually Annually Rate Base and ROE Information Company Rates Effective YE 2015 Rate Base Allowed Debt / Equity Allowed ROE JCP&L April 2015 $2,089M 50% / 50% 9.75% MinutesAvg. Customer Interruptions West Virginia/Maryland Overview EEI Financial Conference November 2016 71 Rate Base and ROE Information Company Rates Effective YE 2015 Rate Base Allowed Debt / Equity Allowed ROE MP February 2015 $2,259M 52% / 48% Settled PE-WV February 2015 $340M 48% / 52% Settled PE-MD February 1993 $436M 48% / 52% 11.9% Recovery Mechanisms State Purchased Power / Fuel Rider Storm Cost Recovery Vegetation Management Energy Efficiency WV Annually Base Rates Biennially Annually MD Various Base Rates N/A Annually Governor –West Virginia Current Term Earl Ray Tomblin (D) Expires in 2017 Political Overview Public Service Commission of WV (WV PSC) Current Term Michael A. Albert, Chairman (R) Expires in 2019 Brooks F. McCabe (D) Expires in 2021 Kara Cunningham Williams (D) Expires in 2017 Governor – Maryland Current Term Lawrence J. Hogan (R) Expires in 2019 MD Public Service Commission (PSC) Current Term W. Kevin Hughes, Chairman (D) Expires in 2018 Harold D. Williams (D) Expires in 2017 Michael T. Richard (R) Expires in 2020 Jeanette M. Mills (R) Expires in 2019 Anthony J. O’Donnell (R) Expires in 2021 (000s) Year-End 2015 MP 390 PE 401 791 Number of Customers Principal Industries Served Chemical, Coal Mining, Non-Metallic Minerals, Primary and Fabricated Metals, Oil and Gas Extractions 0 50 100 150 200 MP PE-WV CAIDI 0.0 0.5 1.0 1.5 2.0 MP PE-WV PE-MD SAIFI 2015 Actuals Minimum Targets 2015 Reliability Information Minutes Avg. Customer Interruptions


 
EEI Financial Conference November 2016 7 Regulated Generation Overview November 2016EEI Financial Conference 72 *Represents MP’s approximate 41% shareholder interest in AGC, which owns a 40% interest in Bath County, a pumped-storage hydroelectric station, operated by 60% owner Virginia Electric and Power Company (non-FE affiliated) **Represents MP’s 0.49% entitlement based on its participation in OVEC Plant PJM Zone State Utility Fuel Type Units Net Maximum Capacity (MW) Year Plant Commissioned 2015 Output M MWH Bath County Rest of RTO VA MP Hydro 6 487* 1985 0.6 Fort Martin Rest of RTO WV MP Coal 2 1,098 1967 7.3 Harrison Rest of RTO WV MP Coal 3 1,984 1972 11.4 OVEC Rest of RTO Multiple MP Coal Multiple 11** 0.1 Rest of RTO Total 3,580 Yards Creek EMAAC NJ JC Hydro 3 210 1965 0.2 EMAAC Total 210 Regulated Generation Total 3,790 19.5 ■ Regulated Distribution segment includes: – 3,580 MW of generation serving West Virginia customers owned and controlled by Mon Power – 210 MW of generation, which represents JCP&L’s 50% ownership interest in Yards Creek Environmental Controls & MATS Spend Regulated Generation November 2016EEI Financial Conference 73 Historical MATS Spend Total compliance cost estimate of $177M; $150M spent through 9/30/2016 Fort Martin 1-2 GORE Mercury Control System, Duct Repairs, CEMS Harrison 1-3 Precip Changes, FGD changes, SCR Catalyst, Duct Repairs, CEMS Environmental Controls NDC NOx Controls SO2 Controls Particulate Cooling Towers Coal Sources SCR SNCR LNB OFA Scrubbers Lo-S Fuel Electro/Other Harrison 1-3 1,984      NAPP Fort Martin 1 & 2 1,098        NAPP, Western, ILB Sub-total 3,082 $0 $20 $40 $60 2012 2013 2014 2015 YTD Sep 2016 Q4 2016F 2017F Harrison Ft Martin MATS Spend per Year ($ in Millions)


 
EEI Financial Conference November 2016 8 Smart Meter Overview November 2016EEI Financial Conference 74 Pennsylvania 2013 – 2016F 2017F 2018F 2019F Meter Installations Approximately 2.1M 800k 500k 500k 300k Costs $1.3B by 2032 Capital: $275M Capital: $150M Capital: $145M Capital: $80M O&M: $150M O&M: $45M O&M: $35M O&M: $35M Customer Benefits $410M by 2032 $4.0 $9.0M $15.5M • Costs were initially recovered through an adjustable rider and are now collected in base rates with the option to reinstate the rider if costs exceed amounts recovered in distribution base rates • The program successfully achieved automated billing for Penn Power in August 2016. This functionality is scheduled to be available for the remaining PA Operating Companies starting in Q1 2017 Other States OH: FE filed a proposed Grid Modernization business plan with the Public Utility Commission of Ohio in February 2016. To date, no action has been taken by the Ohio Commission on the proposed plan MD: Maryland Public Service Commission initiated a proceeding in September 2016 to consider transforming Maryland’s electric distribution system including maximizing benefits from Advanced Meter Infrastructure. No other activity has been undertaken NJ: No current smart meter activity WV: No current smart meter activity Ohio Grid Modernization: Incremental Opportunity ■ Business plan filed with PUCO includes three scenarios that provide the opportunity for significant investments over time: – Full AMI deployment – Different levels of DA/VVC deployment – Net benefits to customers ■ Business plan is subject to PUCO review and approval November 2016EEI Financial Conference 75 Estimates Included in Business Plan Length Total Estimated Costs AMI Deployment 5 to 8 years Capital: $2.2B - $3.5B DA/VVC 8 to 15 years O&M: $1.5B - $1.9B Total: $3.7B - $5.4B* * Not included in current finance plan In ESP IV, the Ohio companies agreed to empower customers through grid modernization initiatives, e.g., AMI, Distribution Automation Circuit Reconfiguration, and VOLT/VAR Control


 
EEI Financial Conference November 2016 9 Rate Strategy November 2016EEI Financial Conference 76 State Last Base Rate Change Examples of Riders Future Activity Ohio 2009 Distribution Capital Recovery: annual cap increases of • $30M June 1, 2016 to May 31, 2019 • $20M June 1, 2019 to May 31, 2022 • $15M June 1, 2022 to May 31, 2024 Demand Side Management and Energy Efficiency Rider: Recovers all program costs, including lost distribution revenues Distribution Modernization Rider: Recovers $204M annually for three years beginning in 2017, with an opportunity to extend for two additional years • April 3, 2017: File a plan to consider transition to proposed straight fixed variable cost recovery mechanism for residential customers to be phased in over three year period beginning January 1, 2019 • 2020-2021: Potential extension of DMR • June 2024: Base rate freeze ends and Companies are required to file a base rate case Pennsylvania 2015 Distribution System Improvement Charge Rider: Rider will be set to zero when new rates are implemented on January 27, 2017. If costs exceed the amount recovered in base rates the rider will restart. Smart Technologies Charge Rider: Rider will be set to zero when new rates are implemented on January 27, 2017. If costs exceed the amount recovered in base rates the rider will restart. • January 27, 2017 base rate increase effective pending PAPUC approval • January 27, 2019: Earliest date for base rate filing • PAPUC soliciting comments from March 2016 hearing on revenue decoupling New Jersey 2015 • Settlement-in-principle, which provides for an annual $80M distribution revenue increase effective January 1, 2017, subject to finalization, execution and NJBPU approval of a Stipulation of Settlement • State Senate investigating revenue decoupling West Virginia / Maryland WV 2015 / MD 1994 WV Vegetation Management Surcharge: Recovers costs associated with right-of-way tree trimming programs • WV - 2H 2017: RFP for generation shortfall • MD – No plans for future rate case Recovery mechanisms provide revenue between base rate cases


 
EEI Financial Conference November 2016 10 Regulated Transmission Line Miles 24,200+ Average annual capital expenditures through 2021 $0.8B-$1.2B Formula Companies’ Rate Base Growth 2016-2021 ~9% Regulated Transmission – Segment Overview ■ One of the largest transmission systems in PJM with 24,200+ miles – Includes FERC-regulated transmission assets recovered through formula rates owned by ATSI, TrAIL, MAIT*, and JCP&L* – Includes FERC-regulated transmission assets recovered through stated rates owned by MP, PE, and WPP ■ ~$1B of Total Revenues in 2015 November 2016EEI Financial Conference 78 Federal Energy Regulatory Commission (FERC) Current Term Norman C. Bay (D) – Chairman Expires in 2018 Colette D. Honorable (D) Expires in 2017 Cheryl A. LaFleur (D) Expires in 2019 Transmission Operating Companies Company Rate Structure ATSI Forward-Looking TrAIL Forward-Looking MAIT* Forward-Looking JCP&L* Forward-Looking Utility (WPP, MP, PE) Stated Rate Qualifications: Composed of up to five commissioners who are appointed by the President of the United States with the advice and consent of the Senate. Commissioners serve five- year terms, and have an equal vote on regulatory matters. * Filed for Formula Rates with FERC on October 28, 2016


 
EEI Financial Conference November 2016 11 ATSI Overview November 2016EEI Financial Conference 79 69 kV 138 kV 345 kV Ohio Edison Penn Power The Illuminating Company Toledo Edison Jurisdiction FERC Test Year Forward-Looking Term January – December Filing Month October Allowed ROE 10.38% Rate Base $2.4B* Cap Structure 40% Debt / 60% Equity Location OE, PP, CEI, and TE True-Up Mechanism Yes * Represents projected average rate base from its 2017 Projected Transmission Revenue Requirement filing for the period January 1, 2017, through December 31, 2017 * Represents projected average rate base from its 2016 Formula Rate Annual Update filing for the period June 1, 2016, through May 31, 2017 TrAILCo Overview November 2016EEI Financial Conference 80 FirstEnergy Utility Service Area FirstEnergy VA Transmission Zone TrAIL 500 kV Line Substation FE TrAIL 50% Joint Ownership with Dominion Resources Dominion Resources Owned PAOH VA WV MD Jurisdiction FERC Test Year Forward-Looking Term June – Following May Filing Month May Allowed ROE 12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects) Rate Base $1.5B* Cap Structure 40% Debt / 60% Equity Location WPP, MP, and PE as well as some portions of ME and PN True-Up Mechanism Yes


 
EEI Financial Conference November 2016 12 MAIT Overview November 2016EEI Financial Conference 81 Penelec Met-Ed 138 kV 230 kV 345 kV 500 kV 34.5 kV 46 kV 69 kV 115 kV Jurisdiction FERC Test Year Forward-Looking Term January – December Filing Month October Requested ROE 11% Rate Base $538M* Hypothetical Cap Structure 50% Debt / 50% Equity Location ME, PN True-Up Mechanism Yes Filed for formula rates with FERC on October 28, 2016, asset transfer expected December 31, 2016 * Represents projected average rate base from its 2017 Projected Transmission Revenue Requirement filing for the period January 1, 2017, through December 31, 2017 JCP&L Transmission Overview November 2016EEI Financial Conference 82 34.5kV 115 kV 230 kV 345 kV Jersey Central Power & Light Jurisdiction FERC Test Year Forward-Looking Term January - December Filing Month October Requested ROE 11% Rate Base* $748M* Cap Structure 60% Debt / 40% Equity Location JCP&L True-Up Mechanism Yes * Represents projected average rate base from its 2017 Projected Transmission Revenue Requirement filing for the period January 1, 2017, through December 31, 2017 Filed for formula rates with FERC on October 28, 2016


 
EEI Financial Conference November 2016 13 Utility Transmission Overview ■ Capital spend is supported by the revenues received from the stated rates ■ FERC regulations require utilities to provide open access transmission service at FERC-approved rates, terms and conditions ■ Transmission facilities are subject to functional control by PJM November 2016EEI Financial Conference 83 115 kV 138 kV 230 kV 345 kV 500 kV West Penn Power Mon Power Potomac Edison Jurisdiction FERC Test Year Stated Rate Location WPP, MP, PE


 
EEI Financial Conference November 2016 14 Competitive Energy Services (CES) MWs of Competitive Generation ~13,000 Positive Annual Free Cash Flow Through 2018F FCF+ Retail Customers 1.4M OH VA WV PA MD NJ MI INIL Jointly Owned Plant Competitive Generating Plants Competitive retail footprint CES Segment Overview ■ Segment primarily comprised of three legal entities: FirstEnergy Solutions, Allegheny Energy Supply and FENOC – FES buys all output of AE Supply at market prices ■ Diverse portfolio of 13,162 MW – 100% of power generated from low- or non-emitting sources ■ 2015 revenues of $5.4B ■ 2015 generation output of 68M MWH November 2016EEI Financial Conference 85 • Treat as standalone business, focusing on predictable cash flows and minimizing overall business risk • Effectively hedge generation with long generation vs. sales strategy • Strong focus on cost management to maintain positive Free Cash Flow Fuel Type MW % Supercritical Coal 4,990 38% Nuclear 4,048 31% Gas / Oil 1,592 12% Subcritical Coal 1,323 10% Hydro 713 5% Wind / Solar 496 4% Total 13,162 Generation Portfolio Business Strategy


 
EEI Financial Conference November 2016 15 CES Segment Structure November 2016EEI Financial Conference 86 ■ Cross-guarantees on debt exist between FES, FG and NG ■ Incremental secured debt capacity of ~$2.8B under the FES/AE Supply revolving credit facility ■ No cross guarantees on debt in place between FES and AE Supply ■ FES, AE Supply and FENOC primarily comprise the Competitive Energy Services segment, however, the segment also includes other FirstEnergy subsidiaries FE Corp. FES Consolidated Debt* in $ Millions FES (Parent) FG NG FES Cons. Short-Term Debt $101 - - $101 Long-Term - Unsecured $696 $835 $842 $2,373 Long-Term – Secured (FMB) - $328 $284 $612 Long-Term – Secured (BV2 Sale-Leaseback) $9 $9 Total Long-Term Debt $696 $1,163 $1,135 $2,994 Undrawn Revolver Capacity $900 Sale-Leaseback** ~$1.1B Net PP&E ~$4.0B ~$5.3B ~$9.3B Capacity 10,180 MW AE Supply Consolidated Debt* in $ Millions AE Supply AGC AE Supply Cons. Short-Term Debt $52 $30 $82 Long-Term - Unsecured $306 $100 $406 Long-Term - Secured $215 - $215 Total Long-Term Debt $521 $100 $621 Undrawn Revolver Capacity $600 Sale-Leaseback - Net PP&E ~$2.0B ~$0.4B ~$2.4B Capacity 2,982 MW * Long-Term debt numbers represent principle amount outstanding. Discounts/premiums, unamortized issuance costs, purchase accounting and capital leases are excluded. ** Represents net present value of future lease payments for the Bruce Mansfield Unit 1 sale-leaseback arrangement CES Competitive Generation Portfolio Plant Name PJM Zone FE Entity State Fuel Type Units Net Maximum Capacity (MW) Year Plant Commissioned 2015 Output M MWH Bay Shore* ATSI FES (FG) OH Coal, Oil 2 153 1955 1.1 Davis-Besse ATSI FES (NG) OH Nuclear 1 908 1977 7.9 Eastlake ATSI FES (FG) OH Oil 1 29 1972 <0.1 Mansfield ATSI FES (NG) PA Coal 3 2,490 1976 13.6 Perry ATSI FES (NG) OH Nuclear 1 1,268 1987 9.5 Sammis* ATSI FES (FG) OH Coal, Oil 8 2,223 1959 8.8 West Lorain ATSI FES (FG) OH Natural Gas, Oil 2 545 1973 <0.1 Total ATSI Zone Generation 7,616 Forked River** EMAAC FES NJ Natural Gas 1 86 <0.1 Total EMAAC Zone Generation 86 Hunlock MAAC AES PA Natural Gas 1 45 2000 <0.1 Wind Farms** MAAC FES Multiple Wind Multiple 277 0.9 Total MAAC Zone Generation 322 Bath County Rest of RTO AES VA Hydro 6 713*** 1985 0.8 Beaver Valley Rest of RTO FES (NG) PA Nuclear 2 1,872 1976 14.5 Buchanan Rest of RTO AES VA Natural Gas 1 43 2002 0.1 Chambersburg Rest of RTO AES PA Natural Gas 1 88 2001 0.1 Gans Rest of RTO AES PA Natural Gas 1 88 2000 <0.1 Maryland Solar** Rest of RTO FES MD Solar Multiple 20 <0.1 OVEC* Rest of RTO FES/AES Multiple Coal Multiple 177**** 0.7 Pleasants Rest of RTO AES WV Coal 2 1,300 1979 7.0 Springdale Rest of RTO AES PA Natural Gas 5 638 1999 3.9 Wind Farms** Rest of RTO FES Multiple Wind Multiple 199 0.3 Total Rest of RTO Generation 5,138 Total Competitive Generation 13,162 69.2 EEI Financial Conference November 2016 87 *Bay Shore 1 expected to be sold or deactivated by October 1, 2020. Sammis 1-4 expected to be deactivated by May 31, 2020 ** Long-term PPA ***Represents AE Supply entitlement **** Represents FES’ 4.85% and AE Supply’s 3.01% entitlement


 
EEI Financial Conference November 2016 16 CES – Repositioning to a Cleaner Fleet Over Time November 2016EEI Financial Conference 88 2012 CURRENT 13,162 MW Resources: 80-85M MWH* Eastlake 4-5 Bay Shore 2-4 Armstrong R. Paul Smith 3-4 Hatfield 1-3 Mitchell 2-3 Net uprates – 96 MW Wind & Solar PPAs – 120 MW Deactivations: Mad River – 60 MW Burger Electromotive Diesel – 7 MW 12,306 MW Eastlake 1-3 Lake Shore 18 Ashtabula 5 19,785MW Coal 63% Nuke 20% Gas/Oil 9% Renewable 8% Coal 48% Nuke 31% Gas/Oil 12% Renewable 9% Coal 44% Nuke 33% Gas/Oil 13% Renewable 10% April 2015 FOSSIL DEACTIVATIONS (885 MW) October 2013 HARRISON and PLEASANTS ASSET TRANSFERS (1,476 MW) 2012-2013 FOSSIL DEACTIVATIONS (3,884 MW) February 2014 HYDRO ASSET SALES (527 MW) OTHER 149 MW By 2020 BAY SHORE 1 and SAMMIS 1-4 SALE OR DEACTIVATIONS (856 MW) Resources: 94M MWH * Includes expected annual generation production of 70-75M MWH and up to an additional 5M MWH available from purchased power agreements for wind, solar, and entitlements in OVEC Fossil Environmental Controls and MATS Spend Historical MATS Spend Total compliance cost estimate of $168M; $117M spent through 9/30/2016 Mansfield 1-3 WFGD Changes, SCR Changes, CEMS Pleasants 1-2 Precip Changes, FGD Changes, SCR Catalyst, Duct Repairs, CEMS Bay Shore 1 Baghouse Fabric Filter changes, Mini ACI system, CEMS Sammis 1-7 Precip Controls, CEMS Environmental Controls NDC NOx Controls SO2 Controls Particulate Cooling Towers Coal Sources SCR SNCR COS LNB OFA Scrubbers Baghouse Electro/Other Mansfield 1-3 2,490        NAPP Pleasants 1-2 1,300      NAPP Sammis 6 & 7 1,200        NAPP, Western Sub-total 4,990 Sammis 1 - 4 720       NAPP, Western Sammis 5 290       NAPP, Western Bay Shore 1 136 CFB CFB  Petcoke Sub-total 1,146 S u b c ri tic a l S u p e rc ri tic a l $0 $20 $40 $60 2012 2013 2014 2015 YTD Sep 2016 Q4 2016F 2017F Sammis Pleasants Mansfield Bay Shore EEI Financial Conference November 2016 89 MATS Spend per Year ($ in Millions)


 
EEI Financial Conference November 2016 17 Nuclear Timeline November 2016EEI Financial Conference 90 2016 2017 2018 2019 2020 Planned refueling outage; enter period of extended operation License Expiration 2036 Planned refueling outage Planned refueling outage 2047 Implement dry fuel storage; enter period of extended operation 2037 Planned refueling outage 2026 Beaver Valley 2 (933 MW) Davis-Besse (908 MW) Perry (1,268 MW) Beaver Valley 1 (939 MW) Planned refueling outage Planned refueling outage Planned refueling outage Planned refueling outage Planned refueling outage Planned refueling outage Planned refueling outage Planned submittal of license renewal application Acronyms and Definitions ABO Accumulated Benefit Obligation ACI Activated Carbon Injection AMI Advanced Metering Infrastructure BRA Base Residual Auction CAIDI Customer Average Interruption Duration Index CEMS Continuous Emissions Monitoring System COS Combustion Optimization System CFB Circulating Fluidized Bed Boiler is inherently low emitting for NOx and SO2 DA Distribution Automation EMAAC EMAAC Locational Deliverability Area in PJM ILB Illinois Basin kV Kilovolt kWh Kilowatt-hour LNB Low NOx Burners Lo-S Low Sulfur Coal MAAC MAAC Locational Deliverability Area in PJM MATS Mercury and Air Toxics Standards MMBTU M British Thermal Unit MW Megawatt MWH Megawatt-hour NAPP Northern Appalachian Coal NDC Net Demonstrated Capacity NOX Nitrogen Oxide OFA Separated Overfire Air OVEC Ohio Valley Electric Corporation PJM PJM Interconnection, L.L.C. PPA Purchase Power Agreement Precip Electrostatic Precipitator ROE Return on Equity RPM Reliability Pricing Model RTO Regional Transmission Organization SAIFI System Average Interruption Frequency Index SCR Selective Catalytic Reduction SNCR Selective Non-Catalytic Reduction SO2 Sulfur Dioxide SVC Static VAR Compensator WFGD Wet Flue Gas Desulfurization VVC Volt/Var Control November 2016EEI Financial Conference 91


 
EEI Financial Conference November 2016 18 FirstEnergy Investor Relations Contacts November 2016EEI Financial Conference 92 For our e-mail distribution list, please contact: Linda M. Nemeth, Executive Assistant to Vice President nemethl@FirstEnergyCorp.com 330-384-2509 Shareholder Inquiries: Irene M. Prezelj, Vice President prezelji@FirstEnergyCorp.com 330-384-3859 Shareholder Services (American Stock Transfer and Trust Company, LLC) firstenergy@amstock.com 1-800-736-3402 Meghan G. Beringer, Director mberinger@FirstEnergyCorp.com 330-384-5832 Gina E. Caskey, Manager caskeyg@FirstEnergyCorp.com 330-384-3841


 
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