Barclays CEO Power-Energy Conference James F. Pearson Executive Vice President and Chief Financial Officer New York, NY • September 10, 2015
2 Forward-Looking Statement 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" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward- looking statements, which may include the following: the speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in particular; the ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully implement our revised sales strategy for the Competitive Energy Services segment; the accomplishment of our regulatory and operational goals in connection with our transmission investment plan, including but not limited to, our pending transmission rate case, the proposed transmission asset transfer, and the effectiveness of our repositioning strategy to reflect a more regulated business profile; changes in assumptions regarding economic conditions within our territories, assessment of the reliability of our transmission system, or the availability of capital or other resources supporting identified transmission investment opportunities; the impact of the regulatory process on the pending matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the Electric Security Plan IV in Ohio; the impact of the federal regulatory process on the 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, and their availability and impact on margins and asset valuations; the continued ability of our regulated utilities to recover their costs; costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices; other legislative and regulatory changes, and revised environmental requirements, including, but not limited to, proposed water discharge regulations and the effects of the United States Environmental Protection Agency's Clean Power Plan, coal combustion residuals regulations, Cross-State Air Pollution Rule, Mercury and Air Toxics Standards, including our estimated costs of compliance, and Clean Water Act 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 certain older regulated and competitive fossil units, including the impact on vendor commitments, and the timing thereof as they relate to the reliability of the transmission grid; the impact of other future changes to the operational status or availability of our generating units and any capacity penalties associated with outages at a given unit; 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; 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 previously-implemented dividend reduction, our cash flow improvement plan and our 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 material accounting policies; the ability to access the public securities and other capital and credit markets in accordance with our announced financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries; actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, letters of credit and other financial guarantees; changes in national and regional economic conditions affecting us, our subsidiaries and/or our major industrial and commercial customers, and other counterparties with which we do business, including fuel suppliers; the impact of any changes in tax laws or regulations or adverse tax audit results or rulings; issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business; the risks associated with cyber-attacks on our electronic data centers that could compromise the information stored on our networks, including proprietary information and customer data; and the risks and other factors discussed from time to time in our United States Securities and Exchange Commission 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 review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. 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. September 10, 2015 Barclays CEO Power-Energy Conference
3 Non-GAAP Financial Matters This presentation contains references to non-GAAP financial measures including, among others, Operating earnings, Adjusted EBITDA, Adjusted Debt, Adjusted Capitalization, Funds from Operations (FFO) 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”. Adjusted EBITDA also excludes the impact of special items and represents Operating earnings before interest expense, investment income, taxes, depreciation and amortization. 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, Adjusted EBITDA, FFO 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,” “Adjusted EBITDA,” “Free Cash Flow,” “Basic EPS” and “Basic EPS-Operating” provide consistent and comparable measures of performance of its businesses to help shareholders understand performance trends. Management uses Adjusted Equity, Adjusted Debt and Adjusted Capitalization to calculate and monitor its compliance with the debt to total capitalization financial covenant under the FirstEnergy credit facility and term loan. These financial measures, as calculated in accordance with the FirstEnergy credit facility and term loan, help shareholders understand FirstEnergy’s compliance with, and incremental debt capacity under, the debt to total capitalization financial covenant. The financial covenant requires FirstEnergy to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. 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 the presentation of the non- GAAP financial measures to the most directly comparable GAAP financial measures. September 10, 2015 Barclays CEO Power-Energy Conference
4 Today’s Agenda ■ Company Overview ■ Executing 2015 Key Initiatives – Ohio ESP IV – PJM Capacity Market Reforms – Cash Flow Improvement Project ■ Setting the Stage for the Future September 10, 2015 Barclays CEO Power-Energy Conference
5 FirstEnergy Overview Strength in Our Diversity and Scale OH VA WV PA MD NJ MI IN IL Utilities ■ Approximately 6M customers ■ One of the largest contiguous service territories in the U.S. covering 65,000 square miles Transmission ■ One of the largest transmission systems in PJM ■ 24,000+ transmission miles ■ Significant opportunity for growth Competitive Operations ■ One of the cleanest generation fleets in the U.S. ■ Long generation vs. sales strategy ■ Focused on reducing overall business risk Jointly Owned Plant Regulated Plants Competitive Generating Plants 230, 345 and 500 kV Transmission Lines Competitive retail footprint Utility footprint September 10, 2015 Barclays CEO Power-Energy Conference
6 Executing 2015 Key Initiatives ■ Continue Ohio ESP IV regulatory process Creating value for shareholders through customer-focused regulated growth and risk mitigation Executing 2nd year of Energizing the Future program Formed MAIT – Seeking approval to transfer transmission assets of JCP&L, Met-Ed, Penelec Comprehensive settlement* for ATSI forward-looking formula rate and ROE Utilities Transmission Competitive Energy Services ■ Advocate PJM market reforms Financial ■ Implement Cash Flow Improvement Plan Focus on maintaining investment grade credit metrics at each business unit Improving credit metrics at FE Corp over time Finalized rate cases: – WV: Rates effective February 2015 – PA: Rates effective May 2015 – NJ: Rates effective April 2015 *Subject to FERC approval September 10, 2015 Barclays CEO Power-Energy Conference Continue to restructure sales portfolio, reducing weather-sensitive loads Sell no more than we produce Retain 10-20M MWH of generation for spot wholesale sales
7 Ohio ESP IV Barclays CEO Power-Energy Conference September 10, 2015 Davis-Besse 908 MW 740 Employees WH Sammis 2,220 MW 396 Employees Market Revenues Wholesale Sell Capacity, Energy and Ancillary Services into the Wholesale Market Capacity, Energy and Ancillary Services OVEC 116 MW 467 OH Employees Cost-Based Payments 1 2 3 Plants Serving Ohio Customers Proposed PPA Filed: August 4, 2014 Term: June 1, 2016 – May 31, 2019 Hearings: Began August 31, 2015 Staff Testimony: Pending Briefs and Reply Briefs follow Final Order expected by first quarter of 2016 Powering Ohio’s Progress Continues to build upon the success of current and prior ESPs
8 PJM Capacity Market Reforms: Update on Recent Auctions ■ 16/17 Transitional Auction: – All available generation units cleared – 2016F CES Adjusted EBITDA increases to $950M to $1,050M ■ 17/18 Transitional Auction: – All available generation units cleared ■ 18/19 Base Residual Auction: – All major generation units cleared – 885 MW of uncleared capacity represents “slice” of the system to hedge performance risk Barclays CEO Power-Energy Conference September 10, 2015 2016-2019 Competitive Capacity Revenues improved by $1.1B Net Competitive Capacity Position (MW) 2016 / 2017 2017 / 2018 2018 / 2019 Legacy Obligation CP Obligation Legacy Obligation CP Obligation Base Generation Capacity Performance Uncommitted ATSI 2,390 4,210 375 6,245 – 6,245 525 RTO 1,250 3,675 960 3,565 240 3,930 325 All Other Zones 135 – 150 – 35 20 35 TOTAL 3,775 7,885 1,485 9,810 275 10,195 885 Results in line with expectations 2016 2017 2018 2019 (through 5/31) Capacity Revenues $810 $590 $620 $260
9 Cash Flow Improvement Plan ■ Background – In May, announced targets of $50M in cash savings in 2015, $150M in 2016 and reaching a run-rate of $200M by 2017 – Over twelve-week timeframe, a team of senior executives led by Donny Schneider, President of FES, committed to identify projects leading to sustainable cash savings Barclays CEO Power-Energy Conference September 10, 2015 Driving financial performance across the company to improve cash-flow and credit metrics Cash Flow Improvement Project 2015 2016 2017 Competitive $54.5 $121.3 $199.6 Non-Competitive 3.5 33.7 40.4 Total Free Cash Flow Improvement $58 $155 $240 Total After Tax Earnings Impact* $0.05 $0.15 $0.24 * Assumes an effective tax rate of approximately 37% to 38% for each year ■ Results ($ Millions)
10 Setting the Stage for the Future ■ Strong focus on customer-service driven regulated growth ■ Operational excellence across FirstEnergy – Utilities, transmission operations and generation fleet ■ Implement cash flow improvements – Expenses and capital expenditures ■ Solid financial performance – Earnings and cash ■ Committed to maintaining investment grade credit metrics at Business Units, improving metrics at FE Corp. over time Barclays CEO Power-Energy Conference September 10, 2015
Appendix Barclays CEO Power-Energy Conference New York, NY • September 10, 2015
12 2016F CES Adjusted EBITDA Closed Open Total M MWH Rate $M M MWH Rate $M M MWH Rate $M Sales: LCI/MCI/MM 14.6 $57 $830 14.6 $57 $830 GA & POLR 21.2 $63 $1,325 21.2 $63 $1,325 Structured & Muni 7.9 $44 $345 7.9 $44 $345 Wholesale 14.0 $37 $515 22.5 $36.70 $825 36.5 $36.75 $1,340 Other 2.6 2.6 Capacity Revenue $810 $810 Total Revenues 60.3 $3,825 22.5 $36.70 $825 82.8 $4,650 Expenses: Capacity & Delivery Expenses ($780) ($60) ($840) Purchased Power 4.9 ($45) ($220) 4.9 ($45) ($220) Nuclear Fuel 32.3 ($7.15) ($230) 32.3 ($7.15) ($230) Fossil Fuel 23.1 ($26.25) ($605) 22.5 ($26.25) ($590) 45.6 ($26.25) ($1,195) Total Expenses 60.3 ($1,835) 22.5 ($650) 82.8 ($2,485) Commodity Margin $1,990 $175 $2,165 Commodity Margin (excl. Capacity Revenue) ~$20 $1,180 ~$8 $175 ~$16 $1,355 Please see slide 13 for additional notes describing “Sales” and “Expenses” 1 Total CES 2016F Adjusted EBITDA, a non-GAAP financial measure, is reconciled to 2016F CES Net Income on slide 14, and is based on market prices as of August 31, 2015. The “Closed Contribution” to Adjusted EBITDA is based on committed sales whereas the “Open Contribution” to Adjusted EBITDA is based on currently uncommitted sales that are assumed to be sold in the wholesale market assuming market prices as of August 31, 2015. The purpose of the table above is to summarize the impact on Adjusted EBITDA of changes in market prices on currently uncommitted sales. Closed Adjusted EBITDA Contribution Open Adjusted EBITDA Contribution CES Adjusted EBITDA1 – 2016F $775-$875 $175 $950 -$1,050 + = September 10, 2015 Barclays CEO Power-Energy Conference
13 2016 CES Adjusted EBITDA Notes ■ Sales: – Volume in all channels, with the exception of wholesale, is subject to fluctuations due to weather and customer behavior. – Portions of “Closed” GA revenues are not fixed as they are indexed to the utility price-to-compare (PTC). – When wholesale volumes are committed they are categorized as “Closed” and moved to the appropriate channel. Additional retail channel sales could include an operating margin of ~$2 to $3 per MWH. – Wholesale “Open” rate is the weighted average of generation length based on forward market prices at AD Hub as of August 31, 2015. The “Closed” position represents physical and financial transactions executed to reduce market price risk. – “Other” sales include distribution losses and pumping for Hydro units. – Capacity Revenue includes revenues from the legacy BRA, incremental/transitional capacity auctions, bilateral transactions and Capacity Transmission Rights (CTRs). ■ Expenses: – Capacity expense is the cost associated with serving load. – Delivery expenses, net of delivery revenues, include congestion, losses, ancillaries, Network Integration Transmission Service and the cost of Financial Transmission Rights. Can vary based on delivery location, channel and market conditions. – A delivery expense of ~$2 – $4/MWH is incurred to serve wholesale load – A delivery expense of ~$3 – $6/MWH is incurred to serve retail load – Generation volume is committed in the following order: (1) Purchased Power, which includes Renewables/OVEC of ~2M MWH and additional Bilateral/Spot Purchases, (2) Nuclear, and (3) Fossil. – Fossil Fuel expense includes Coal, Gas, and Hydro expenses and CFIP savings. – Nuclear Fuel expense reflects the suspension of the DOE nuclear fuel disposal fee. – Total CES 2016F Adjusted EBITDA guidance, a non-GAAP financial measure, is reconciled to 2016F CES Net Income on slide 14, and is based on market prices as of August 31, 2015. The +/- $50 million range is applied to account for potential variation in generation fleet performance, load fluctuations and other variable/fixed costs. September 10, 2015 Barclays CEO Power-Energy Conference
14 Competitive Operations Net Income (Loss) to Adjusted EBITDA* Reconciliation Barclays CEO Power-Energy Conference September 10, 2015 * Adjusted EBITDA represents GAAP net income adjusted for the special items listed on slide 15 and the addition of Income Taxes; Interest Expense, net; Depreciation, Amortization and Investment Income. ($ Millions) 2014A 2015F 2016F Net Income (Loss) – GAAP $(337) $105 – $145 $160 – $270 Special Items (after tax)* 436 85 40 – 30 Operating Earnings $99 $190 - $230 $200 - $300 Income Taxes** 47 100 – 145 120 – 175 Interest Expense, Net 152 160 – 155 165 – 150 Depreciation 387 410 – 405 430 – 415 Amortization*** 66 65 70 – 65 Investment Income (98) (50) (35) – (55) Adjusted EBITDA* $653 $875 – $950 $950 – $1,050 ** Includes income taxes on continued operations and discontinued operations. *** 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 Note 7 - Intangible Assets, 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 $220M, $215M and $230M, in 2014, 2015, and 2016, respectively.
15 Competitive Operations – Special Items Barclays CEO Power-Energy Conference September 10, 2015 As of July 25, 2014 ($ Millions) 2014A 2015F 2016F Pre-tax items Trust Securities Impairment $33 $22 $ – Merger Accounting – Commodity Contracts 42 40 – 45 40 – 45 Non-Core Asset Sales/Impairments (122) 28 10 – 20 Plant Closing Costs 206 20 – Loss on Debt Redemptions 8 – – Regulatory Charges 4 1 – Mark-to-Market Adjustments Pension/OPEB actuarial assumption 327 – – Other 74 (7) – Retail Repositioning Charges 70 30 – Subtotal $642 $134 – $139 $50 - $65 Income Taxes (206) (49) – (54) (20) – (25) After Tax Effect – Special Items $436 $85 $30 – $40
16 PJM Capacity Position ■ Legacy Obligation: – The MW reflect net commitments from the PJM Base Residual Auction, incremental auctions and bilateral transactions related to the previous PJM capacity construct – Units that were sold/transferred are excluded ■ CP Obligation: – The MW reflect results from the PJM Capacity Performance Transitional Auctions ■ Base Generation: – The MW reflect results from the PJM Base Residual Auction with a Base Generation obligation under the new PJM capacity construct ■ Capacity Performance: – The MW reflect results from the PJM Base Residual Auction with a Capacity Performance obligation ■ Uncommitted: – Includes MW that have no capacity obligation and can be offered into future incremental auctions or used to mitigate potential non-performance charges ■ Capacity Revenue: – Includes revenues from the results of incremental/transitional capacity auctions, bilateral transactions and Capacity Transmission Rights (CTRs) Barclays CEO Power-Energy Conference September 10, 2015 Net Competitive Capacity Position (MW) 2015/2016* 2016 / 2017 2017 / 2018 2018 / 2019 Legacy Obligation Legacy Obligation CP Obligation Legacy Obligation CP Obligation Base Generation Capacity Performance Uncommitted ATSI 7,070 2,390 4,210 375 6,245 - 6,245 525 RTO 5,040 1,250 3,675 960 3,565 240 3,930 325 All Other Zones 135 135 – 150 – 35 20 35 TOTAL 12,245 3,775 7,885 1,485 9,810 275 10,195 885 *2015/2016 legacy obligations are BRA only 2016 2017 2018 2019 (through 5/31) Capacity Revenues $810 $590 $620 $260