Investor Presentation. June 2016

Transcription

1 Investor Presentation June 2016 NYSE ECR

2 Cautionary Statements Forward-Looking Statements This presentation contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Eclipse Resources Corporation and its subsidiaries (collectively, the Company or Eclipse ) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, may, expect, anticipate, plan, intend, estimate, project, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include estimates of the Company s reserves, expectations of plans, strategies and objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed in the Company s Annual Report on Form 10-K, filed on March 4, 2016 with the U.S. Securities and Exchange Commission (the SEC ). The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, production and processing equipment and services, legal and environmental risks, drilling and other operating risks, regulatory changes, counterparty credit risk, the uncertainty inherent in estimating natural gas, natural gas liquids ( NGLs ) and oil reserves and in projecting future rates of production, cash flow and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described under the heading Risk Factors in the Company s Annual Report on Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. This presentation has been prepared by Eclipse and includes market data and other statistical information from sources believed by Eclipse to be reliable, including independent industry publications, government publications, filings, press releases and presentations by other oil and gas companies, and other published independent sources. Some data is also based on the Company s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although the Company believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Cautionary Note Regarding Hydrocarbon Quantities The SEC permits oil and gas companies to disclose in their filings with the SEC only proved, probable and possible reserve estimates. Eclipse has provided proved reserve estimates that were independently engineered by Netherland Sewell & Associates, Inc. Unless otherwise noted, proved reserves are as of December 31, Actual quantities that may be ultimately recovered from Eclipse s interests may differ substantially from the estimates in this presentation. The Company may use the terms resource potential, EUR and upside potential to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are based on analogy to the Company s existing models applied to additional acres, additional zones and tighter spacing and are the Company s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or SEC rules. EUR estimates, resource potential and identified drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations, which have been attributed to these quantities. Factors affecting ultimate recovery include the scope of the Company s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Resource potential and EUR may change significantly as development of the Company s oil and natural gas assets provide additional data. The Company s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. The type curve areas included in this presentation are based upon our analysis of available Utica Shale well data, including information regarding initial production rates, Btu content, natural gas yields and condensate yields, all of which may change over time. As a result, the well data with respect to the type curve areas presented herein may not be indicative of the actual hydrocarbon composition for the type curve areas, and the performance, Btu content and natural gas and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in our area of operation. 2

3 Company Overview Eclipse Resources is engaged in the acquisition and development of oil and gas assets in the Appalachian Basin with over 100,000 acres in the Core of the Utica Shale Play Eclipse Utica Shale Core Asset Area Market Capitalization (1) Enterprise Value (1) Liquidity (2) Valuation $595 Million $969 Million $233 Million Average Daily Production (MMcfe/d) and % Liquids 4Q (3) 2015 exit rate (3) 1Q (25%) Proved Reserves (3) Total Resource Potential (4) Reserves and Potential 2016 Guidance Highlights Bcfe 6.5 Tcfe 2016 Production (MMcfe/d)* 200 (25% Liquids) 2016 Capital Expenditures $168 Million *2016 production is planned to be voluntarily curtailed until commodity prices recover Net Core Acreage (5) : Utica Liquids Rich: Utica Dry: Marcellus Liquids Rich: 115,000 (38% HBP d) 53,000 (47% HBP d) 49,000 (37% HBP d) 13,000 (24% HBP d) 1. As of May 31, 2016, includes all recent debt repurchases 2. As of March 31, As of December 31, 2015; proved reserves based on estimates provided by Eclipse's independent engineering firm 4. Resource potential is based on internal estimates and includes, but does not represent, total proved reserves 5. As of March 1, 2016; acreage in Marcellus also included in Utica Dry 3

4 Key Investment Highlights Eclipse is currently trading at a significant discount to peers (2) Premier Assets ~102,000 Core Utica Shale Acres ~13,000 Liquids Rich Marcellus Shale Acres Inventory of net undeveloped locations depending on lateral length (3) Firm Interstate Gas transportation portfolio of ~355 Mdth/d Unparalleled Operational Performance Leading edge operational team has made ECR the lowest cost driller in the Utica Longest Utica well w/ 18,544 ft lateral 1,043 lateral feet drilled per day Leading total cost per foot of $854 Drilled in less than 18 days Peer leading gas price realizations through diversified marketing plan Prudent Business Plan Focused on preserving liquidity and improving balance sheet $125 MM revolving credit facility undrawn (1) 2016 capital expenditures of ~$168 MM (45% YoY decline) Substantial portion of 2016 and 2017 production hedged at attractive prices 2017 EBITDAX Multiple (2) Net Undeveloped Acres by Type Curve Area 18.6x 16.3x 11.8x 8.6x 9.0x 9.1x 7.1x 5.5x ECR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Utica Rich Gas 18,240 Utica Dry Gas 44,110 Utica Condensate 27,740 Marcellus 12, Effective borrowing base of $97 MM ($125 MM borrowing base less $28MM for letters of credit outstanding) 2. Peers include AR, COG, EQT, GPOR, RICE, RRC, and SWN; 2017 EBITDAX per Wall Street and Factset estimates, ECR based on internal estimates, based on April 29, 2016 stock price net locations assuming 15,000 laterals, 437 net locations assuming 10,000 laterals; see Appendix for additional details 4

5 Strong Operational Performance 20,000 18,000 16,000 14,000 12,000 Operated Lateral Length (Ft) Operated vs. Non-Op Drilling Days (1) 13,492 18,544 Last 20 Wells Drilled Eclipse Non-Op % Faster 10,000 8,000 6,000 4,000 2,000 6,239 6,836 8,693 All Wells Since Inception Eclipse Non-Op % Faster Q15 1Q 2016 $2,250 Total Cost per Lateral Foot 1,200 Lateral Feet Drilled per Day $2,000 $1,750 $1,500 $1,718 1, ,030 $1,250 $1,000 $1,165 (2) $750 $500 $250 $ $- 1Q Q/4Q Q Normalized to 15,600 TMD; as of December 31, Q Q/4Q Q

6 Production Outlook Modest D&C spending in 2H 2016/ 2017 on the completion of DUCs and the restart of a one-rig drilling program generates 40-6 year-over-year production growth in 2017 Highlights Production Mix (MMcfe/d) Eclipse is voluntarily curtailing its production to 200 MMcfe/d Minimal capital expenditures required to maintain flat production in % 8% 9% 9% 19% 17% 16% 16% 65% 75% 75% 75% Actual Production Q16 2Q16e 2016e Gas NGL Oil Average Daily Production (MMcfe/d) 2016 Guidance 2017 Illustrative 6 Restarting the completions of DUCs and a 1 rig drilling program in 2H16 can lead to 40-6 YoY production growth in Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e 3Q16e 4Q16e 1Q17e 2Q17e 3Q17e 4Q17e 6

7 Diversified Midstream Strategy Eclipse s acreage is centered across a confluence of major pipelines in the country providing significant in- and out-of-basin optionality Highlights 4Q 2015 Realized Gas Price (1) Firm gathering, processing and fractionation without volume commitments ~355,000 MMbtu/d in non-recallable long term firm interstate gas transportation contracts to price advantaged markets Firm NGL (propane and butane) contract in Mariner East II pipeline for transport and sale at East Asia Index Prices (4Q16) $2.32 $2.13 $2.09 $2.05 $1.89 $1.62 $1.52 $1.48 ET Rover Term: 15 years 100,000 Dth/d Gulf (Expected In-service 2Q17) 50,000 Dth/d Dawn (Expected In-service 4Q17) Rockies Express / ANR South In-service Term: 17 months 50,000 Dth/d ANR SE ET Rover 100,000 Dth/d Gulf 50,000 Dth/d - Dawn Mariner East II Expected In-service in 4Q16 Significant portion of expected propane and butane production ECR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer Sales Markets 2016 & 2017 Rockies Express/ANR South 50,000 Dth/d ANR SE Texas Eastern In-service Term: 9.5 years 75,000 Dth/d Gulf, M3, Lebanon Columbia Expected In-service in 4Q16 Columbia 205,000 Term: 15 years 205,000 Dth/d TCO Pool Dth/d Blue Racer Processing and Fractionation (Berne and Natrium) 1. Before the effects of hedges; peers include AR, COG, EQT, GPOR, RICE, RRC, and SWN E 2017E App Basin Gulf Coast Northeast (M3) Mid West Canada TCO 7

8 Declining Cost Structure Eclipse continues to reduce its costs structure in this challenging commodity environment Operating Costs per Mcfe $5.00 $4.00 Achieved 42% reduction to cash operating expenses / Mcfe from 2014 Reductions in 2016 mitigated by voluntarily curtailing production G&A and Interest per unit likely to decline materially in 2017 with resumption in drilling $3.00 $/Mcfe $2.00 $1.00 G&A reduced from 35% to 2 of total expenses G&A further reduced to 15% of total expenses Production (MMcfe/d) $ e LOE Production Taxes Transportation, Gathering & Processing Firm Transportation G&A Interest - 8

9 Liquidity & Debt Reduction Focused on preserving liquidity and improving the balance sheet in a low price environment Highlights Q ending liquidity of $233 million Conducted open market debt repurchases for $39.5 million of face amount at a cost of 59.3% of face value, resulting in annual interest payment reductions of $3.5 million Non-core asset sales resulting in cash proceeds of ~$5.5M in Q1 2016, expect an additional $8.5MM in Q Plan to end 2016 with cash on hand and no incremental debt $550 Senior Notes ($ MM) $510 Year to date, ECR has reduced outstanding debt by $40MM, resulting in annual interest savings of $3.5MM Liquidity ($ MM) 225 $125 $0 $0 $28 $ $ Cash Borrowing Base Borrowing Base Draws Outstanding Letters of Credit Liquidity

10 Single Well Economics (1) Significant economic enhancement achieved through longer laterals Lowest cost per foot Fewer pads constructed Less midstream infrastructure The average lateral length of Eclipse s current operated drilling plan through year-end 2017 is ~13,000 by Type Curve Area (13,000 Lateral Length) (2) 58% 49% 45% 6% 9% 12% 13% 14% 3 96% 82% 75% 34% 35% 37% 36% 36% 67% 138% 118% 11 72% 68% 68% 64% 62% 115% $3.00 Gas, $50 Oil $3.50 Gas, $60 Oil $4.00 Gas, $70 Oil Dry Gas East Dry Gas Central Dry Gas West Rich Gas Condensate / Rich Gas Lean Condensate Rich Condensate Very Rich Condensate Marcellus East Net Undeveloped Acres (3) 12,080 15,320 16,710 6,510 11,730 17,600 3,390 6,750 12, See Appendix for detailed assumptions. Assumes ethane rejection with contractual 3 recovery 2. Marcellus East returns shown for 10,000 lateral 3. Includes undeveloped leasehold within HBP d units 10

11 Super-Lateral Program Eclipse aims to revolutionize the cost structure and returns profile of the Utica Shale through its Super-Lateral program Purple Hayes 1H Highlights ECR s Super-Lateral test well completed in Q Longest horizontal onshore lateral ever drilled in the country (1) Drilled 18,544 foot lateral in 17.6 days to TD Total measured depth of 27,048 feet 124 stages at 150 stage spacing completed at 5.3 stages per day Total D&C costs of ~$850/ft Enhancing Economics through Longer Laterals Reduces D&C cost per foot and improves well economic metrics F&D costs expected to drop ~2-3 in the condensate area, improving well returns by ~35-7 over shorter lateral type wells Ability to maximize lateral length on existing rich gas and dry gas locations 1,600 1,400 1,200 1,000 D&C / Ft ECR s Purple Hayes D&C cost/ft is significantly below peers, while targeting the same EUR of 1.0 Bcfe/ft in the condensate area $854 $1,111 $1, Based on discussions with global service providers Purple Hayes 18,544' Peer 1 TC 10,000' Peer 2 TC 9,000' 11

12 Hedging (1) Eclipse continues to actively hedge expected production to provide predictable cash flows and limit capital plan execution risk Natural Gas (Mmbtu/d) Oil (Bbl/d) 180,000 4, ,000 4,000 $46.00 $46.00 $ ,000 $3.11 $3.11 $3.11 $3.11 Current Production 3, , ,000 80,000 60,000 40,000 20,000 - $2.77 $2.77 $2.77 $ ,000 40,000 40,000 40,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 80,000 80,000 80,000 80,000 65,000 65,000 65,000 65,000 10,000 10,000 10,000 10,000 Q Q Q Q Q Q Q Q ,000 2,500 2,000 1,500 1, Current Production $ $53.52 $53.52 $ ,000 4,000 4,000 2,000 $ ,000 1,000 1,000 1, Q Q Q Q Q Q Q Q $ s indicate Avg. Floor Price 2016 Hedges Approximately 135,000 MMBtu/d of natural gas hedged at average price of $3.11/MMbtu ~9 of 2016 natural gas production at midpoint of guidance Approximately 2,040 Bbls/d of oil hedged at average floor price of $53.84/Bbl ~7 of 2016 oil production at midpoint of guidance Approximately 55,000 Gals/d of propane hedged at average price of $0.456/Gal in 2016 ~6 of 2016 propane production 2017 Hedges Approximately 120,000 MMBtu/d of natural gas hedged at average price of $2.77/Mmbtu Approximately 3,500 Bbls/d of oil hedged at average floor price of $46.00/Bbl 1. See Appendix for slide detailing hedges 2016 Pre-Hedged Revenues NGL 13% Oil 18% Natural Gas 69% 12

13 Eclipse Q2 & Full Year 2016 Guidance Q2 2016E FY 2016E Low High Low High Avg. Daily Production (MMcfe/d) % Natural Gas ~ ~ % NGL 15% 17% 14% 18% % Oil 8% 1 7% 11% Forecasted Realizations (1) Natural Gas ($/Mcf) Differential to NYMEX $ (0.20) $ (0.30) $ (0.15) $ (0.25) Firm Transportation $ (0.40) $ (0.50) $ (0.35) $ (0.45) Total Differential $ (0.60) $ (0.80) $ (0.50) $ (0.70) NGL Price as % of WTI 2 25% 2 3 Oil ($/Bbl) Differential to NYMEX $ (10.00) $ (12.00) $ (10.00) $ (13.00) 2016 Capital Expenditures Midstream 2% Land & Other 21% Non-Op D&C 6% Op D&C 71% Total 2016 Capex ($ MM) $127 Projected Operating Costs Operating Cost per Mcfe (2) $ 1.20 $ 1.30 $ 1.20 $ 1.30 Cash G&A (3) $ 8MM $ 9MM $ 30MM Capital Expenditures (4) $ 20MM $ 168MM $41 1H16 2H16 1. Excludes impact of hedges 2. Excludes firm transportation, DD&A, exploration, and general and administrative expenses 3. Excludes costs associated with rig terminations 4. Includes routine lease acquisition, land related expenses, and net of projected midstream reimbursements; excludes land and producing asset acquisitions 13

14 Appendix

15 Firm Transportation and Sales Outlets $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 $- Firm Transportation Costs ($/MMBtu) $ $ $ Demand Variable Annual Average Firm Transportation MMBtu/d North East Texas Eastern - M3 37,500 37,500 37,500 37,500 Canada Dawn - Canada 0 8,333 50,000 50,000 Premium Basin Columbia - TCO Pool 34, , , ,000 Lebanon Hub 12,501 12,501 12,501 12,501 Gulf Rover - Trunkline Z1A 0 75, , ,000 Rex - ANR - SE 41, Texas Eastern - ELA/WLA 24,999 24,999 24,999 24,999 Total 150, , , , ,000 Firm Commitments per MMBtu per day 450, , , , , , , ,000 50,000 0 Firm Sales Texas Eastern - M3 Texas Eastern - ELA/WLA Texas Eastern - Lebanon Hub Rex - ANR - SE Columbia - TCO Pool Rover - Trunkline Z1A Rover - Dawn 15

16 NGL Infrastructure 1Q16 average realized price of $12.70 per barrel and represents 17% of total production for the quarter Mariner East II contract to begin in fourth quarter 2016 Contract to market propane and butane using East Asia Index benchmark Global propane prices have not weakened with the same magnitude as US prices NGL prices should firm with growing number of outlets for NGL demand, export capacity increasing through the second half of 2016, and with the migration through the shoulder season Mount Belvieu 12% 7% 37% 6% 38% 9% 12% Eclipse 8% 38% 33% 2015 Marketing by Region Edmonton Markets Ontario Markets Midwest Markets Northeast Markets Rail Transport Natrium Plant Stephen City, VA Mariner East I Mariner East II (4Q16) Marcus Hook Gulf Markets South Markets 16

17 Non-GAAP Reconciliations Adjusted EBITDAX March 31, March 31, ($ in thousands) Net Loss $ (40,687) $ (34,103) Depreciation, depletion & amortization 15,113 42,432 Exploration expense 15,656 13,453 Rig contract termination 2,663 7,057 Stock-based compensation 1, Impairment of oil and gas properties 17,665 - Accretion of asset retirement obligations Gain on deriative instruments (10,550) (11,371) Net cash receipts on derivative instruments 18,378 5,965 Interest expense 13,461 14,021 (Gain) loss of sale of assets (22) 80 Gain on debt extinguishment (8,664) For the Three Months Ended Other income (expense) 139 (402) Income tax expense 540 (17,579) Adjusted EBITDAX $ 25,251 $ 20,686 Adjusted Revenue Three Months Ended March 31, March 31, ($ in thousands) Total Revenues $ 49,606 $ 43,814 Net cash receipts (payments) on derivative instruments 18,378 5,965 Brokered natural gas and marketing (9,118) 2,636 Adjusted revenue $ 58,866 $ 52,415 PV-10 (1) ($ in thousands) Future Net Cash Flows $ 300,059 $ 792,091 Present Value of future net fash flows Year ended December 31, Before income tax (pre-tax PV-10) 212, ,389 Income Taxes - (178,732) After income tax (Standardized Measure) $ 212,866 $ 330, Proved reserves based on estimates provided by Eclipse's independent engineering firm. PV-10 based on SEC pricing 17

18 Financial and Operational Summary FY Q15 2Q15 3Q15 4Q15 FY Q16 2Q16 Guidance FY 2016 Guidance Production Natural Gas (Mcf/d) 54, , , , , , ,410 NGL (MBbls/d) 1,468 4,383 7,502 7,209 7,716 6,713 5,645 Oil (MBbls/d) 1,630 3,939 6,584 6,028 4,808 5,344 2,805 Total Daily Equivalent (MMcfe/d) Total Equivalent (MMcfe) 26,546 14,360 18,077 20,719 22,727 75,882 18,301 Natural Gas Realized Price ($/Mcf) Average NYMEX Henry Hub ($/MMBtu) $ 4.26 $ 2.90 $ 2.74 $ 2.76 $ 2.10 $ 2.57 $ 2.02 Differential to Henry Hub (0.75) (0.51) (0.03) $ (0.25) $ (0.20) Realized Price before Firm Transportation $ 3.51 $ 2.39 $ 2.71 $ 2.86 $ 2.32 $ 2.62 $ 2.05 Firm Transportation (0.07) (0.41) (0.30) (0.33) - (0.44) $ (0.45) $ (0.40) Realized Price after Firm Transportation $ 3.51 $ 2.32 $ 2.30 $ 2.56 $ 1.99 $ 2.29 $ 1.61 Impact of Cash Settled Derivatives Realized Price after Cash Settled Derivatives $ 3.52 $ 3.00 $ 3.46 $ 3.50 $ 2.98 $ 3.27 $ 2.93 Realized Price after Hedging and Firm Transportation $ 3.52 $ 2.92 $ 3.05 $ 3.20 $ 2.65 $ 2.95 $ 2.49 NGL Realized Price ($/Bbl) Average NYMEX WTI ($/Bbl) $ $ $ $ $ $ $ % of WTI 9% 35% 25% 38% 23% 25% Oil Realized Price ($/Bbl) Average NYMEX WTI ($/Bbl) $ $ $ $ $ $ $ Differential to WTI (13.37) (12.83) (12.19) (9.29) (9.75) (10.88) (10.46) $ (11.00) $ (11.50) Realized Price before Hedging $ $ $ $ $ $ $ Impact of Cash Settled Derivatives $ Realized Price after Cash Settled Derivatives $ $ $ $ $ $ $ Operating expenses per Mcfe ($/Mcfe) Lease operating $ 0.32 $ 0.23 $ 0.20 $ 0.16 $ 0.17 $ 0.18 $ 0.15 Transportation, gathering and compression $ 0.68 $ 0.87 $ 1.25 $ 1.10 $ 1.23 $ 1.13 $ 1.26 Production and ad valorem taxes $ 0.27 $ 0.15 $ 0.17 $ 0.15 $ 0.14 $ 0.15 $ (0.12) Unit Operating Costs $ 1.27 $ 1.25 $ 1.62 $ 1.41 $ 1.54 $ 1.46 $ 1.29 OpEx excluding Firm Transportation $ 1.27 $ 1.20 $ 1.38 $ 1.17 $ 1.31 $ 1.26 $ 0.95 $ 1.25 $ 1.25 Depreciation, depletion and amortization $ 3.36 $ 2.95 $ 3.35 $ 3.24 $ 3.28 $ 3.23 $ 0.83 General and administrative $ 1.71 $ 0.83 $ 0.70 $ 0.66 $ 0.35 $ 0.61 $ 0.62 Revenues ($ thousands) Natural gas sales $ 69,450 $ 23,609 $ 28,715 $ 38,360 $ 36,617 $ 129,561 $ 28,041 NGL sales $ 21,048 $ 7,564 $ 9,563 $ 2,757 $ 10,293 $ 30,177 $ 6,522 Oil sales $ 47,318 $ 12,641 $ 27,246 $ 20,811 $ 14,165 $ 74,863 $ 5,925 Oil and natural gas sales $ 137,816 $ 43,814 $ 64,984 $ 61,928 $ 61,075 $ 234,601 $ 40,488 Brokered natural gas and marketing revenue $ 9,469 $ 9,244 $ 4,807 $ 20,720 $ 9,118 Total revenues excluding Hedging $ 137,816 $ 43,814 $ 74,453 $ 71,172 $ 65,882 $ 255,321 $ 49,606 Net of Cash Settled Derivatives $ 179 $ 5,965 $ 8,457 $ 9,332 $ 13,320 $ 37,074 $ 18,378 Total revenues after Hedging $ 137,995 $ 49,779 $ 82,910 $ 80,504 $ 79,202 $ 292,395 $ 67,984 Expenses ($ thousands) Lease operating $ 8,518 $ 3,346 $ 3,589 $ 3,212 $ 3,757 $ 13,904 $ 2,677 Transportation, gathering and compression $ 18,114 $ 12,451 $ 22,634 $ 22,811 $ 27,950 $ 85,846 $ 23,137 Production and ad valorem taxes $ 7,084 $ 2,100 $ 3,078 $ 3,175 $ 3,268 $ 11,621 $ (2,284) Total Lifting Costs $ 33,716 $ 17,897 $ 29,301 $ 29,198 $ 34,975 $ 111,372 $ 23,530 Cash general and administrative $ 45,136 $ 11,197 $ 11,307 $ 12,473 $ 6,798 $ 41,774 $ 9,801 $ 8,500 $ 30,000 Brokered natural gas and marketing expense $ 10,795 $ 9,262 $ 6,116 $ 26,173 $ 9,402 Adjusted EBITDAX $ 62,426 $ 20,686 $ 31,507 $ 29,571 $ 31,313 $ 113,077 $ 25,251 Rig termination $ 3,283 $ 7,056 $ 366 $ 174 $ 2,075 $ 9,672 $ 2,663 Depreciation, depletion and amortization $ 89,218 $ 42,432 $ 60,641 $ 67,172 $ 74,505 $ 244,750 $ 15,113 Exploration $ 21,186 $ 13,453 $ 6,243 $ 3,244 $ 93,271 $ 116,211 $ 15,656 Impairment of oil and gas properties $ 34,855 $ - $ - $ - $ 691,334 $ 691,334 $ 17,665 Net Income (Loss) $ (183,176) $ (34,103) $ (41,970) $ (81,468) $ (813,869) $ (971,410) $ (40,687) Capital Expenditures ($ thousands) Drilling and Completion $ 644,486 $ 88,831 $ 106,188 $ 48,282 $ 40,280 $ 283,581 $ 12,721 Midstream $ 33,260 $ 12,393 $ (28,317) $ 199 $ (2,395) $ (18,119) $ 883 Land $ 127,513 $ 18,349 $ 11,454 $ 4,186 $ 7,165 $ 41,154 $ 3,845 Other $ 4,095 $ 2,119 $ 600 $ 43 $ 83 $ 2,845 $ 460 Total $ 809,356 $ 121,692 $ 89,924 $ 52,709 $ 45,133 $ 309,461 $ 17,909 $ 20,000 $ 168,000 18

19 Hedging Summary Natural Gas Hedges Natural Gas Swaps Natural Gas Call/Put Options Natural Gas Collars Natural Gas Three-Way Collars Oil Hedges Oil Swap Oil Three-Way Collar Oil Call/Put Options NGL Hedges Propane Swaps Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) 65,000 Current December 2016 $ ,000 January 2017 December 2017 $2.98 Floor sold 16,800 Current December 2016 $2.75 Ceiling Sold 40,000 January December 2018 $3.75 Floor Purchased (Put) 30,000 Current December 2017 $3.00 Ceiling Sold (Call) 30,000 Current December 2017 $3.50 Floor Purchased (Put) 20,000 January 2017 December 2017 $2.75 Ceiling Sold (Call) 20,000 January 2017 December 2017 $3.29 Floor Purchased (Put) 30,000 January 2017 December 2017 $2.50 Ceiling Sold (Call) 30,000 January 2017 December 2017 $3.03 Floor Purchased (Put) 40,000 Current December 2016 $2.90 Ceiling Sold (Call) 40,000 Current December 2016 $3.24 Floor Sold (Put) 40,000 Current December 2016 $2.35 Floor Purchased (Put) 30,000 January 2017 December 2017 $2.75 Ceiling Sold (Call) 30,000 January 2017 December 2017 $3.57 Floor Sold (Put) 30,000 January 2017 December 2017 $2.25 Volume (Bbl/d) Production Period Weighted Average Price ($/Bbl) 850 Current December 2016 $45.55 Floor purchased (put) 1,000 Current - December 2016 $60.00 Ceiling sold (call) 1,000 Current - December 2016 $70.10 Floor sold (put) 1,000 Current - December 2016 $45.00 Floor purchased (put) 2,000 January December 2017 $46.00 Ceiling sold (call) 2,000 January December 2017 $59.75 Floor sold (put) 2,000 January December 2017 $38.00 Floor purchased (put) 2,000 January September 2017 $46.00 Ceiling sold (call) 2,000 January September 2017 $59.50 Floor sold (put) 2,000 January September 2017 $38.00 Ceiling Sold 1,000 January December 2018 $50.00 Volume (Gal/d) Production Period Weighted Average Price ($/Gal) 42,000 Current - December 2016 $ ,000 Current - June 2016 $ ,500 July September 2016 $

20 Favorable Lease Expiration Schedule Eclipse is aggressively amending leases whose primary term is set to expire in 2017 and 2018 to replace the five year lump sum extension option to optional annual payments of 5-8 years. To date, Eclipse has executed amendments representing approximately 11,600 net acres 5 45% Utica Core Area Leasehold Expiration (1) 47.4% 35% 3 25% % 12.4% 14.7% 1 5% 5.6% 1. As of March 1, Fee/HBP 20

21 Proved Reserves Summary Eclipse has been able to achieve significant growth in proved reserves and proved developed reserves since the commencement of its active drilling program in late 2013 SEC Pricing Net Oil (MBbls) Net NGL (MBbls) Net Gas (MMcf) Net Total (MMcfe) Net PV-10 ($M) PDP 4,137 7, , , ,956 PNP/PBP ,008 2,244 1,941 PUD ,527 70,329 4,968 Total Proved 4,693 7, , , , Total Proved Reserves Reserves (Bcfe) Q4-13 Q4-14 Q4-15 PDP PNP/PBP PUD 21

22 Type Curve Areas with OGIPs Eclipse has continued to refine its Gas In Place estimates in the Utica & Marcellus Shale core areas Marcellus Type Curve Area 22

23 Type Curve Summary 15,000' Lateral Very Rich Condensate / Dry Gas Dry Gas Marcellus Rich Condensate Lean Condensate Rich Gas Dry Gas East Condensate Rich Gas West Central East Gas IP Rate (Mcf/d) 2,250 3,600 4,950 10,500 16,500 21,000 22,500 25,200 8,250 Initial Cond. Yield (Bbl/Mmcf) N/A N/A N/A 100 EUR (w/ processing) (Bcfe) (1) ($3.50 Gas, $60.00 Oil, NGL 35% of WTI) 42% 42% 43% 41% 84% 91% 106% 92% Well Cost ($MM) $11.25 $11.25 $11.25 $11.25 $11.25 $12.64 $12.64 $12.64 $9.68 Breakeven Gas Price at $60.00 Oil ($/Dth) (2) $0.00 $0.65 $1.35 $2.40 $2.80 $2.21 $2.17 $2.10 $0.60 Breakeven Oil Price at $3.50 Gas ($/Bbl) (2) $43.50 $42.80 $42.35 $38.00 $32.50 N/A N/A N/A $30.00 EUR, Bcfe/1000' ,000' Lateral Gas IP Rate (Mcf/d) 1,950 3,120 4,290 9,100 14,300 18,200 19,500 21,840 7,150 Initial Cond. Yield (Bbl/Mmcf) N/A N/A N/A 100 EUR (w/ processing) (Bcfe) (1) ($3.50 Gas, $60.00 Oil, NGL 35% of WTI) 36% 36% 37% 35% 34% 75% 82% 96% 82% Well Cost ($MM) $10.39 $10.39 $10.39 $10.39 $10.39 $11.53 $11.53 $11.53 $8.86 Breakeven Gas Price at $60.00 Oil ($/Dth) (2) $0.30 $1.00 $1.60 $2.55 $2.90 $2.27 $2.23 $2.15 $0.75 Breakeven Oil Price at $3.50 Gas ($/Bbl) (2) $45.50 $44.80 $44.50 $40.50 $36.00 N/A N/A N/A $31.10 EUR, Bcfe/1000' ,000' Lateral Gas IP Rate (Mcf/d) 1,500 2,400 3,300 7,000 11,000 14,000 15,000 16,800 5,500 Initial Cond. Yield (Bbl/Mmcf) N/A N/A N/A 100 EUR (w/ processing) (Bcfe) (1) ($3.50 Gas, $60.00 Oil, NGL 35% of WTI) 27% 26% 27% 25% 25% 57% 62% 73% 67% Well Cost ($MM) $8.93 $8.93 $8.93 $8.93 $8.93 $10.12 $10.12 $10.12 $7.44 Breakeven Gas Price at $60.00 Oil ($/Dth) (2) $1.15 $1.60 $2.10 $2.80 $3.05 $2.45 $2.40 $2.30 $1.00 Breakeven Oil Price at $3.50 Gas ($/Bbl) (2) $49.25 $48.70 $49.00 $46.00 $42.50 N/A N/A N/A $33.60 EUR, Bcfe/1000' Assumes ethane rejection with contractual 3 recovery 2. Breakeven is defined as PV(10) > $

24 Net Undeveloped Locations Risked Net Undeveloped Locations are calculated by taking Eclipse s total net undeveloped acreage and multiplying such amount by a risk factor (to account for inefficient unitization and the inability to force pool in Ohio) which is then divided by Eclipse s expected well spacing Dry Gas East Dry Gas Central Dry Gas West Rich Gas Condensate / Rich Gas Lean Condensate Rich Condensate Very Rich Condensate Marcellus East TOTAL Net Undeveloped Acres (1) 12,080 15,320 16,710 6,510 11,730 17,600 3,390 6,750 12, ,900 Inter-Lateral Spacing Risk Factor ,000' Lateral Length Risked Net Undeveloped Locations ,000' Lateral Length ,000' Lateral Length Includes undeveloped leasehold within HBP d units 24

25 Dry Gas East (1) Type Curve Assumptions Well Characteristics Bcfe / 1000' 2.1 Inter-Lateral Spacing (ft.) 850 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 27,771 PPT R f 92% PPT + Utica R f 63% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 21.8 Initial Decline (%) Months 8 Hyperbolic Phase Initial Decline (%) 63% B Factor 1.20 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) N/A NGL Yield (Bbl/Mmcf) N/A Drilling And Completion D&C Cost ($'000/well) 11,533 Eclipse Acreage Area Map IRR 6 Lateral Length IRR Sensitivity 2 6,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) 16 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity 1 12 $ Gas Price ($/Dth) $3.50 $3.00 $2.50 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 25

26 Dry Gas Central (1) Type Curve Assumptions Well Characteristics Bcfe / 1000' 1.9 Inter-Lateral Spacing (ft.) 850 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 25,293 PPT R f 98% PPT + Utica R f 64% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 19.5 Initial Decline (%) Months 9 Hyperbolic Phase Initial Decline (%) 63% B Factor 1.20 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) N/A NGL Yield (Bbl/Mmcf) N/A Drilling And Completion D&C Cost ($'000/well) 11,533 Eclipse Acreage Area Map 10 Lateral Length IRR Sensitivity ,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) 1 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity Gas Price ($/Dth) $4.00 $3.50 $3.00 $2.50 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 26

27 Dry Gas West (1) Type Curve Assumptions Well Characteristics Bcfe / 1000' 1.8 Inter-Lateral Spacing (ft.) 850 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 23,568 PPT R f 107% PPT + Utica R f 65% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 18.2 Initial Decline (%) Months 9 Hyperbolic Phase Initial Decline (%) 63% B Factor 1.20 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) N/A NGL Yield (Bbl/Mmcf) N/A Drilling And Completion D&C Cost ($'000/well) 11,533 Eclipse Acreage Area Map Lateral Length IRR Sensitivity ,000 8,000 10,000 12,000 14,000 16,000 Laterla Length (ft.) 1 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity Gas Price ($/Dth) $4.00 $3.50 $3.00 $2.50 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 27

28 Rich Gas (1) Type Curve Assumptions Well Characteristics Bcfe / 1000' 1.8 Inter-Lateral Spacing (ft.) 850 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 23,566 PPT R f 113% PPT + Utica R f 68% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 14.3 Initial Decline (%) Months 9 Hyperbolic Phase Initial Decline (%) 63% B Factor 1.20 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) 15 NGL Yield (Bbl/Mmcf) 60.0 Drilling And Completion D&C Cost ($'000/well) 10,389 Eclipse Acreage Area Map Lateral Length IRR Sensitivity 45% 35% 3 25% 2 15% 1 5% 6,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) 7 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity $ Gas Price ($/Dth) $4.00 $3.50 $3.00 $2.50 $75 $65 $55 $45 Oil Price ($/Bbl) 1 $2.00 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 28

29 Condensate/Rich Gas (1) Type Curve Assumptions Map Lateral Length IRR Sensitivity Well Characteristics Bcfe / 1000' 1.4 Inter-Lateral Spacing (ft.) 750 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 18,683 PPT R f 113% PPT + Utica R f 65% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 9.1 Initial Decline (%) Months 9 Hyperbolic Phase Initial Decline (%) 6 B Factor 1.25 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) 60 NGL Yield (Bbl/Mmcf) 80.4 Drilling And Completion D&C Cost ($'000/well) 10,389 Eclipse Acreage Area 45% 35% 3 25% 2 15% 1 5% 6,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) 7 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity $ $4.00 $ Gas Price ($/Dth) $3.50 $3.00 $2.50 $65.00 $55.00 $ $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change $ Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 29

30 Lean Condensate (1) Well Characteristics Bcfe / 1000' 0.9 Inter-Lateral Spacing (ft.) 750 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 11,958 PPT R f 84% PPT + Utica R f 45% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 4.3 Initial Decline (%) Months 12 Hyperbolic Phase Initial Decline (%) 6 B Factor 1.25 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) 150 NGL Yield (Bbl/Mmcf) 87.7 Drilling And Completion D&C Cost ($'000/well) 10,389 7 Type Curve Assumptions Map Lateral Length IRR Sensitivity Capex IRR Sensitivity Eclipse Acreage Area $ % 35% 3 25% 2 15% 1 5% 6,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) Commodity Price IRR Sensitivity $ Gas Price ($/Dth) $4.00 $3.50 $3.00 $2.50 $75 $65 $55 $45 Oil Price ($/Bbl) 1 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change $ Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 30

31 Rich Condensate (1) Type Curve Assumptions Map Lateral Length IRR Sensitivity Well Characteristics Bcfe / 1000' 0.9 Inter-Lateral Spacing (ft.) 750 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 11,343 PPT R f 10 PPT + Utica R f 48% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 3.1 Initial Decline (%) Months 8 Hyperbolic Phase Initial Decline (%) 5 B Factor 1.25 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) 200 NGL Yield (Bbl/Mmcf) 91.5 Drilling And Completion D&C Cost ($'000/well) 10,389 Eclipse Acreage Area 45% 35% 3 25% 2 15% 1 5% 6,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) 7 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity $85 6 $4.00 $ Gas Price ($/Dth) $3.50 $3.00 $2.50 $65 $55 $45 Oil Price ($/Bbl) 1 $2.00 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 31

32 Very Rich Condensate (1) Well Characteristics Bcfe / 1000' 0.7 Inter-Lateral Spacing (ft.) 750 Lateral Length (ft.) 13,000 Gross EUR (Mmcfe, Post-Processing) 9,279 PPt R f 81% PPt + Utica Rf 39% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 2.0 Initial Decline (%) Months 24 Hyperbolic Phase Initial Decline (%) 55% B Factor 1.25 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) 300 NGL Yield (Bbl/Mmcf) 93.0 Drilling And Completion D&C Cost ($'000/well) 10,389 7 Type Curve Assumptions Map Lateral Length IRR Sensitivity Capex IRR Sensitivity Eclipse Acreage Area $ % 35% 3 25% 2 15% 1 5% 6,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) Commodity Price IRR Sensitivity $ Gas Price ($/Dth) $4.00 $3.50 $3.00 $2.50 $75 $65 $55 $45 Oil Price ($/Bbl) 1 $ % -2-15% -1-5% 5% 1 15% 2 25% Capex Change $ Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas 1. Assumes 13,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 32

33 Marcellus East (1) Type Curve Assumptions Map Lateral Length IRR Sensitivity Well Characteristics Bcfe / 1000' 1.6 Inter-Lateral Spacing (ft.) 750 Lateral Length (ft.) 10,000 Gross EUR (Mmcfe, Post-Processing) 15,765 Marcellus and Geneseo Rf 62% Type Curve Exponential Phase Gas IP Rate (MMcf/d) 5.5 Initial Decline (%) Months 4 Hyperbolic Phase Initial Decline (%) 54% B Factor 1.40 Terminal Decline (%) 6% Liquids Initial Cond. Yield (Bbl/Mmcf) 100 NGL Yield (Bbl/Mmcf) Drilling And Completion D&C Cost ($'000/well) 7,443 Eclipse Acreage Area ,000 8,000 10,000 12,000 14,000 16,000 Lateral Length (ft.) 12 Capex IRR Sensitivity $4.50 Commodity Price IRR Sensitivity $85 10 $4.00 $ Gas Price ($/Dth) $3.50 $3.00 $2.50 $65 $55 $45 Oil Price ($/Bbl) 2 $2.00 $ Capex Change -25% -2-15% -1-5% 5% 1 15% 2 25% Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas 1. Assumes 10,000 lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing 33