Cautionary Statements

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1 INVESTOR PRESENTATION NYSE: ECR March 208

2 March 208 Cautionary Statements Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 933, as amended (the Securities Act ) and Section 2E of the Securities Exchange Act of 934, as amended (the Exchange Act ). All statements, other than statements of historical fact included in this press release, regarding Eclipse Resources strategy, future operations, financial position, estimated revenues and income/losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words plan, endeavor, will, would, could, believe, anticipate, intend, estimate, expect, project and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Eclipse Resources current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading Risk Factors in Eclipse Resources Annual Report on Form 0-K filed with the Securities Exchange Commission on March 3, 208 (the 207 Annual Report ), and in Item A. Risk Factors of Eclipse Resources Quarterly Reports on Form 0-Q. Forward-looking statements may include, but are not limited to, statements about Eclipse Resources business strategy; reserves; the expected benefits of the Flat Castle Acquisition and its impact on the Company s business, operations and assets; general economic conditions; financial strategy, liquidity and capital required for developing its properties and timing related thereto; realized natural gas, natural gas liquids and oil prices; timing and amount of future production of natural gas, NGLs and oil; its hedging strategy and results; future drilling plans; competition and government regulations, including those related to hydraulic fracturing; the anticipated benefits under its commercial agreements; marketing of natural gas, NGLs and oil; leasehold and business acquisitions; the costs, terms and availability of gathering, processing, fractionation and other midstream services; general economic conditions; credit markets; uncertainty regarding its future operating results, including initial production rates and liquid yields in its type curve areas; and plans, objectives, expectations and intentions contained in this presentation that are not historical. Eclipse Resources cautions you that the forward-look statements pertaining to the Flat Castle Acquisition described herein are subject to risks and uncertainties, including, without limitation, the Company s failure to realize the expected benefits of such transaction, the Company s ability to successfully integrate the acquired assets, negative effects of the consummation of such transaction on the market price of the Company s common stock, and significant transaction costs, unknown liabilities and/or unanticipated expenses such as litigation expenses. In addition, all forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility and the recent significant decline of the price of natural gas, NGLs, and oil, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading Risk Factors in the 206 Annual Report and in Item A. Risk Factors of Eclipse Resources Quarterly Reports on Form 0-Q. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Eclipse Resources or persons acting on the Company s behalf may issue. Except as otherwise required by applicable law, Eclipse Resources disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this presentation. 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 3, 207. 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, but not limited to, 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. Cautionary Note Regarding Non-GAAP Financial Measure This presentation includes financial measures that are not in accordance with generally accepted accounting principles ( GAAP ), including Adjusted EBITDAX. While management believes such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of Adjusted EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix of this presentation. 2

3 March 208 Eclipse Profile & Business Highlights Premier Utica and Marcellus Assets ~55,725 net effective acres in the core of the Utica Shale.5 Tcfe in proved reserves 2 6 years of core drilling inventory with expected well returns >50% 3 Innovative Operational Team Enhancing well economics via longer laterals: Increased annual plan average by ~80% since 206 to a 208e average of ~6,800 Expect to drill ~,650 per day ~9% increase YoY Continued focus on a leading cost structure: ~5% lower cost per foot than peers in the Utica 4 Growth Oriented Business Plan 208e annual production of MMcfe/d 42% YoY growth in oil production in Forecasted 3-year production CAGR of 20% to 25% Liquids Exposure 45% of 208e revenue is from liquids production 5 40% of acreage in liquids rich areas Low cost liquids producer with average well costs of $826/ft Every $5 increase in WTI increases oil revenue % and increases 3 overall IRRs 5% As of 2/3/7 and including the Flat Castle Project Area acquisition and Ohio Marcellus acreage. 2 Reserves as of year-end 207 from independent engineering firm. 3 Based on $3.00 / $55.00 pricing; type curves do not represent proved reserves. 4 Based on public type curve assumptions, peers include: AR, CNX, GPOR, and EQT. 5 Based on midpoint of guidance. 3

4 Net Undeveloped Risked Locations March 208 Premier Utica and Marcellus Assets Eclipse has 36 risked, extended-reach, future lateral locations with internal rates of returns of at least 50% based on type curve assumptions 2 Returns by 208 Type Curve Acreage by Type Curve Area 3 Dry Gas Accelerated Production Curve 00% Flat Castle Upside 80% 60% 40% 20% 6% 50% 84% 72% 73% 7% 52% 82% 80% 3% 95% 98% 89% 74% 40% Liquids Rich Exposure 55,725 net acres 60% Dry Gas Exposure 0% $3.00 / $55 $3.30 / $60 Utica Condensate Utica Rich Gas Utica Dry Gas Marcellus Condensate Flat Castle Base Case High-Graded Asset Base Flat Castle Upside Dry Gas Accelerated Production Curve 40% 50% 60% 70% 80% 90% 64 IRR at $3.00 / $55 Pricing 98 Undeveloped Risked Locations by Type Curve Area 94 6 Years of Drilling Inventory Years Inventory Condensate Rich Gas Dry Gas Marcellus Condensate Flat Castle Based on 6,000 lateral, other than Marcellus Condensate which is based on 2,000 lateral. Utica Dry Gas and Utica Rich Gas based on,000 well spacing, Utica Condensate and Marcellus Condensate based on 750 well spacing and Flat Castle based on,200 well spacing. 0% risk factor is utilized. Type curves do not represent proved reserves. 2 Based on $3.00 / $55.00 pricing. 3 As of 2/3/7 and including the Flat Castle Project Area acquisition. 4 Based on current 3-year, 2-rig drilling plan. 4

5 March Accomplishments Operational Achievements Grew production 36% year over year to 3 MMcfe/d: 77% natural gas, 4% NGLs, 9% oil Established Eclipse as the industry leader in drilling Super Lateral wells Drilled twelve Super Laterals (eleven condensate and one dry gas) Longest lateral of 20,803 drilled (spud to TD) in 3.4 days Eight wells drilled in excess of 9,000 feet Renegotiated Eureka gathering agreement resulting in a ~20% lower gathering rate Set new record for plugs drilled out with a single bit trip at 22 Innovation Developed reservoir predictive model designed to increase well returns across the Company s asset base Collaborated on development of the next generation rotary steerable tool Greaseless wireline system development allows for completion of laterals in excess of 20,000 Significantly reduced drill out times and bit trips with enhanced technologies Growth Drilling JV adds financial flexibility with attractive acreage valuations Closed on the acquisition of the Flat Castle Project Area, resulting in a new core area for the Company and increasing its Utica drilling inventory by over 40% at a low cost of entry Recently drilled and completed multi-stack development pad (Marcellus/Utica) Year-end proved reserves increased 2% to,459 Bcfe with a PV-0 increase of 254% to $730MM 207 drill bit only F&D costs of $0.26 per Mcfe and all sources F&D of $0.3 per Mcfe 2 Reserves as of year-end 207 from independent engineering firm, based on SEC pricing. 2 Includes reserve revisions. 5

6 March Reserves and 3-Year Average F&D Costs Eclipse continues to lower its 3-year average F&D costs and increase reserves through the drill-bit, generating substantial year over year increases in proved reserves PV-0 Reserves (Bcfe) SEC Pricing Reserves (Bcfe) Strip Pricing Year-end PV-0 ($MM) 2% Increase, % increase to liquid reserves,223 9% Increase,460 53% increase to liquid reserves 254% Increase 2% Increase $730 $738 $ NGLs Oil Natural Gas $ Average F&D Drilling ($/Mcfe) 2 3-year Average -year 3-year Average -year 73% Decrease 63% Decrease SEC Pricing Strip Pricing Average F&D All Sources ($/Mcfe) 2 3-year Average Recycle Ratio 3 74% Decrease 67% Decrease 357% Increase 3.2x $2.05 $2.35 $0.55 $0.70 $0.26 $0.62 $0.9 $ x Strip and SEC pricing as of 2/3/7; PV-0 is a non-gaap measure, a full reconciliation of pre-tax PV-0 to Standardized Measure is in the Appendix. 2 Includes reserve revisions. 3 Recycle Ratio is defined as profit per unit divided by cost per unit from all sources. 6

7 Super Laterals March 208 What we re up to in 208 Eclipse remains focused on increasing returns through innovation by the application of cutting-edge technologies in a new operating area Going Further in % of gross wells spud in 208 will exceed 5,000 Utica Condensate Utica Dry Gas 7 Flat Castle Lateral Length: < 0,000' <0,000 20,000+ to to 0,000 5,000 5,000 20, ,000 20,000 >20, Eclipse has found a low cost of entry asset where it can apply its Super Lateral advantage to generate outsized returns Initial Eclipse Flat Castle well to be drilled in Q 208 and completed in Q3 208 Base Case % IRR 52% IRR 7,000' Painter H 6,000' Eclipse Flat Castle Type Well Upside Case 7% IRR 208 Catalysts Utica Condensate Utica Dry Gas Flat Castle Marcellus Take advantage of large liquids rich inventory and grow oil production >40% in 208 Improving returns through Accelerated Production profile Drill, complete and commence production on first Flat Castle well; commence well permitting and construction of infrastructure Analyze Marcellus Condensate initial production results and finalize plan for gathering and processing IRRs based on $3.00 / $55.00 pricing; type curves do not represent proved reserves. 7

8 MMcfe/d $MM March Development Plan Eclipse s capital plan of ~$300-$320 million supports 8-4% year over year production growth on an Mcfe basis, with over 40% condensate growth Operational Highlights 208 Capital Budget 208 capital budget of approximately $300-$320 million 2 gross rigs running throughout the year ( net rig) Average lateral length increasing 24% year over year to 6,800 in 208 from 3,600 in 207 Initial Flat Castle development well expected to turn to sales in Q3 208 Maintain the flexibility to reduce capital expenditures in 2H8 by $50-75 million through a third drilling JV program with Sequel Energy and/or a reduction of drilling activities if commodity prices fall 27 gross (7 net) turn to sales 2 Marcellus, 3 Condensate, Utica Dry Gas, Flat Castle 84% 8% ~$300MM to $320MM 6% 2% Midstream Land Other D&C Daily Production Net Revenue Before Hedging NGLs Oil ~6% YoY Revenue Growth 350 Natural Gas e e All 208 metrics based on the midpoint of guidance and current strip pricing. All net metrics incorporate Utica Shale Drilling JV, with Program at 50% pre-carry and Program 2 at 30% pre-carry interests to Eclipse. 208 capital expenditures exclude potential acquisitions. 8

9 March Revenue: More Liquids Focused With a recently turned to sales Utica Condensate pad and another 3 gross condensate wells turning to sales in 208, Eclipse s shift in commodity mix supports an increase in revenue per unit despite the declining gas strip Revenue Mix 208e Year over Year Production Growth e Mcfe % 7% 6% Oil NGL 8% 42% 20% Significant increase in Oil as a % of total revenue 29% Natural Gas 8% Revenue per Mcfe Before Hedges 63% NGLs Oil Natural Gas 55% Estimated to increase 4%, despite an 8% decrease in Henry Hub at strip pricing Sales Sales e All 208 metrics based on the midpoint of guidance and current strip pricing. All net metrics incorporate Utica Shale Drilling JV, with Program at 50% pre-carry and Program 2 at 30% pre-carry interests to Eclipse. 9

10 2,5 00 2,0 00,5 00, % 70% 60% 50% 40% 30% 20% 0% 0% March 208 Ohio Oil Production Based on recent Ohio statewide data, Eclipse has drilled eight of the top ten oil producing Utica Shale wells Q4 207 Top 0 Oil Producing Wells in Ohio 66% 2,35 65%,897 58% 65% 66% 67% 62% 50% 55% 50% OUTLAW C H GREAT FINERAN SCOTT 3H 2H YOST A H SCOTT H SCOTT 5H YOST B 5H Company Well PURPLE Company HAYES H 2 Well OIL (Bbls/d) % Liquids Based on fourth quarter 207 Ohio state data; Ohio Division of Natural Resources (ODNR). 0

11 March 208 Management s Focus on Full Cycle Returns Eclipse management interests are aligned with shareholders with compensation tied to achieving full-cycle corporate returns in excess of the Company s WACC Corporate Compensation Return Methodology Eclipse management is focused on delivering full-cycle corporate returns in excess of the Company s cost of capital Full-cycle corporate returns reflect the internal rate of return for a well including the following: Well level costs (type curve) Land capital Midstream capital General & administrative expenses Realized gain (loss) on hedges Actual/Planned cycle times Eclipse management continuously calculates the full-cycle corporate returns for the 208 drill schedule Calculated drilling plan IRR used as benchmark for setting 208 key performance metrics 208 full-cycle corporate returns expected to exceed Eclipse s weighted average cost of capital at current strip pricing Land Undeveloped acreage balance sheet value assigned to individual wells drilled Acreage value multiplied by drainage acres for each well G&A Calculated on $/Mcfe basis Rate based on Eclipse internal forecasts Full-Cycle Corporate Cost Assumptions Midstream Calculated on $/Mcfe basis Includes rate based on internal analysis of Eclipse midstream capital costs Hedges Impact calculated based on expected settlements at strip pricing Cost of capital calculated using CAPM.

12 March 208 Enhancing Long-Term Shareholder Value Eclipse s increasing economies of scale, coupled with Super Lateral development and innovative completion techniques, will continue to enhance full-cycle corporate returns, generating long-term shareholder value Fixed & Variable Costs per Foot of Lateral Drilled Scale + Innovation = Returns Full-Cycle Corporate IRRs 00% 90% 80% 70% 60% 50% 40% 30% 20% 0% 0% 00% 90% 80% 70% 60% 50% 40% 30% 20% 0% 208 Condensate Development Plan IRR 6% 6,000' Type Curve 2% Cost of Capital 2 8% Corporate 208 Dry Gas Development Plan IRR 84% 2% Cost of Capital 2 22% 0% 6,000' Type Curve Corporate Based on $3.00 / $55.00 pricing; type curves do not represent proved reserves. Full-cycle corporate returns include land, midstream, G&A and hedges. 2 Cost of capital calculated using CAPM. 2

13 Peer Peer 2 Peer 3 Peer 4 ECR 207 ECR planned in 208 IRR Avg. CAPEX per foot ($/ft) EUR per,000 (MBOE) March 208 Incremental Economic Impact of Super Laterals Extending well length from 3,000 to 20,000 creates $975 $,520 PV0 per foot with an incremental IRR of 30% 25% Well Level Capital Cost per Lateral Length Condensate Area EUR Per,000 $2,000 $,500 $,000 Eclipse Dry Gas Area Eclipse Condensate Area $500 5,000 0,000 5,000 20,000 Lateral Length 0 5,000 0,000 5,000 20,000 Lateral Length Well Level IRR Increases Incremental Economics of Extending the Lateral 20% 00% 80% 60% ECR Dry Gas Area ECR Condensate Area ECR Advantage Incremental Cost/Benefit per Foot Utica Dry Gas Utica Condensate Capital Cost ($MM) of 3,000 Lateral $4.0 $.3 Variable Drilling & Completion ($/ft) - 3K' to 20K' $668 $589 Reserves (Bcfe/,000 ) 2.2. Reserves (Mboe/,000 ) 77 40% 20% 0% 5,000 0,000 5,000 20,000 Lateral Length 3,000' Lateral to 20,000 Lateral 2 Incremental IRR % 3 25% 30% Incremental PV-0 ($/ft) $,520 $975 MOIC 5.5x 4.4x Based on $3.00 / $55.00 pricing; type curves do not represent proved reserves. Indicative of the average Utica lateral lengths for the following peers: AR, GPOR, CNX, EQT. 2 Represents the economic benefit of developing the incremental 7,000 of lateral. 3 Incremental IRR based on costs associated with extending the lateral. 3

14 Acreage Value at 30% IRR 208 Type Curve and Development Plan Average 5 wells planned in 208 March 208 Acreage Value Enhanced by Super Laterals Eclipse s Super Lateral development creates significant value where other Appalachian peers are not; extending the average developed lateral from 0,000 to 6,000 increases Eclipse s Utica acreage value by ~$675MM $25,000 $20,000 ECR Dry Gas Area ECR Condensate Area Flat Castle Base ECLIPSE ADVANTAGE Eclipse has ~0,000 risked undeveloped acres in the Utica Assuming full development in this area with 6,000 average lateral length vs 0,000 average lateral length increases Eclipse s Utica value by ~$675MM, a ~70% improvement $5,000 $0,000 Appalachian Peers Average Utica Lateral Lengths 2 ECR acreage value = (2.39 share price /25 close * 300MM shares + 50MM net debt 448MM PV0 PDP + PNP) / 37,000 net unrisked undeveloped = $5,700 Risked Net Undeveloped Acres Ohio Liquids Rich Ohio Dry Gas Flat Castle Utica Total 33,000 37,000 40,000 0,000 $/Acre with 0,000 laterals $8,300 $4,600 $3,500 Utica Value ($MM) $275 $540 $40 $955 $5,000 Eclipse Implied Acreage Market Value 3 $/Acre with 6,000 laterals $4,500 $2,00 $9,300 Utica Value ($MM) $475 $780 $375 $,630 Increasing from 0,000 to 6,000 LL development improves Utica valuation by ~$675MM $0 5,000 0,000 5,000 20,000 Lateral Length IRR based on $3.00 / $55.00 pricing; type curves do not represent proved reserves. Risked Net Undeveloped Acres include a 0% risk factor. 2 Indicative of the 208 development plan or current type curve average Utica lateral lengths for the following peers: AR, GPOR, CNX, EQT. 3 Based on enterprise value as of February 6, 208 less proved developed PV-0. 4

15 5,53 9,827 8,376 9,333 9,22 0,000 9,63 8,329 3,595 9,843 0,5 4,443 5,720,37 5,620 9,330 5,349 9,626 4,029 9,769 3,752 2,82 5,278 9,588 9,393 7,79 9,584 8,793 9,282 7,628 8,955 9,38 9,38 3,705 3,357,980 20,77 5,358 9,225 4,890 20,887 2,30 9,564 3,434 9,50 2,789 5,909 8,853 7,556 8,358 7,24 8,454 7,24 7,24 7,25 7,983 20,45 7,55 20,370 9,899 8,52 20,283 March 208 Super Lateral Evolution Eclipse plans to increase average lateral length by 24% in and 208 Spuds 207 : ~3,600 Average 208 : ~6,800 Average Super Lateral Standard Lateral 208 Annual Average 207 Annual Average 5

16 IRR Payout (Years) Gas EUR/,000 (BCF) 207 TC 208 TC 208 TC 207 TC Gas Rate (MMcf/Day) Cumulative Gas (Bcf) 208 Utica Dry Gas Type Curve Accelerates Returns Gen 3 Utica Dry Gas wells were produced above 207 Type Curve and showed no reduction in EURs due to higher rates 208 Utica Dry Gas wells will target initial production rates up to 40% above 207 Type Curve with unchanged estimated EURs Accelerated Production Curve is expected to significantly improve well IRRs by twelve percentage points from 72% to 84% due to more immediate cash flow 2 Detailed engineering analysis supports moving to a more accelerated dry gas production profile, increasing type curve returns while maintaining EUR New Production Profile in 208 Cumulative Gas Production Backwardated strip intensifies this impact Assessing viability of concept in Condensate areas wells 208 Dry Gas Type Curve (2.2 BCF/,000') 207 Dry Gas Type Curve (2.2 BCF/,000') March Months on Production Accelerated Dry Gas Type Curve 2 Acceleration Effect on EUR Daily Gas Production 0% 00% 90% 80% 70% 60% 50% IRR Payout % Plateau Rate at 6,000' Lateral Length (MMcf/d) Gas IP Rate Normalized to 6,000 Lateral (MMcf/d) Accelerated Dry Gas Type Curve 207 Dry Gas Type Curve Months on Production Production normalized to 6, Based on $3.00 gas pricing; type curves do not represent proved reserves. 6

17 March 208 Marcellus Wells Commence Production Based upon the performance of the two Marcellus wells that were turned to sales in January 208, the Company is updating its Marcellus Condensate Type Curve, increasing EUR by ~3% Two Marcellus wells in Ohio turned wells to sales on January 8, 208 with an average LL of 9,9 Initial Production results indicate Eclipse s Marcellus acreage is highly economic Avg. Gas IP Rate of 6.7 Mmcf/d Avg. Initial Condensate Yield of 68 Bbl/Mmcf Developed on existing Utica pad taking advantage of existing pad and road infrastructure Multiple, nearby gathering and processing options Initial Marcellus Evaluation New 208 Marcellus Condensate Type Curve 2 Marcellus Initial Development LL 2,000 Gas IP Rate Initial Cond. Yield NGL Yield 8.6 MMcf/d 60 Bbl/MMcf 06 Bbls/MMcf 20% 00% 80% BTIRR 2 60% 40% 73% 98% EUR.8 Bcfe/,000 20% Well Cost $9.9 MM 0% $3.00 / $55 $3.30 / $60 Initial Marcellus evaluation shows the average of the two new operated wells; gas rate is unshrunk as the wells are currently being blended into the gas stream. 2 Type curves do not represent proved reserves. 7

18 23% % 6% 3% 48% 52% 66% 59% 7% 77% 6,700 7,50 3,300 ~ 8,000 March 208 Eclipse Advantage in Flat Castle Eclipse s Super Lateral technologies generate outsized returns in a depressed natural gas market Untapped Potential in Flat Castle Super Lateral Length Progression ~44,500 highly contiguous net acres in Tioga County, Pennsylvania Eclipse will be able to utilize Super Lateral development, increasing average lateral length by over 50% in this area from the historical ~6,700 laterals as a result of favorable leasing terms, few unit size limitations and available bolt-on acreage Development of Flat Castle with 8,000 average Super Laterals creates outsized returns, increasing IRRs from % to 59% New interstate pipelines improved pricing in local markets Average Lateral Length Peer Wells 205 Painter H 208 Eclipse st Well 209 Eclipse Full Development Super Lateral Impact on IRR 2 Unlocking Flat Castle IRR 2 Eclipse Super Lateral program unlocks significant upside vs the shorter wells in the project area 7,000' Painter H 7,000' 4,000' 6,000' 8,000' Flat Castle Base Case Flat Castle Upside Case Based on base case type curve. 2 Based on $3.00 pricing; type curves do not represent proved reserves. 8

19 March 208 Flat Castle Gas In Place and Recovery Factors Large gas-in-place volumes in Flat Castle Project Area support the potential for reserve growth per well and further IRR gains Gas in Place Characteristics Flat Castle Project Area contains 27% more gas in place than in Ohio s Utica Dry Gas area where recovery is 2.2 Bcf/,000 The Utica Dry Gas Type Curve has a recovery factor of 48% whereas the current Utica Flat Castle Type Curve has a recovery factor of 29% indicating the potential for EUR growth per well Strong Regional Gas in Place Flat Castle Project Area The best Flat Castle area wells to date have recovery up to 2.8 BCF/,000 which have a recovery factor of 40% indicating further potential gains in EUR per well Future development will target improving recovery and optimizing IRR Utica Dry Gas, OH Utica Flat Castle, PA OGIP BCF/Section Interval Thickness 0 28 Type Curve BCF/, Type Curve Recovery Factor 48% 29% Upside Case BCF/, Upside Case Recovery Factor 33% Eclipse set a conservative recovery factor of 29-33% and still achieves an EUR at or above that of the Ohio Utica Dry Gas Type Curve Southeast Ohio Dry Gas Core 9

20 March 208 Delineation of Flat Castle Project Area by Key Industry Wells Eclipse has initially laid out 00 gross (8 net) wells with an average lateral length of ~8,000 centered on the highest gas in place in the sub-basin which has been substantially delineated by strong surrounding well results drilled in lower gas in place areas Travis Peak Painter H EUR /,000 : 2.0 Bcf Shell Synnestvedt H EUR /,000 : 2.7 Bcf Shell Stanley 06 23H EUR /,000 : 2.8 Bcf Shell Neal D 85 V EUR /,000 : 2.2 Bcf Shell Sharretts H EUR /,000 : 2.0 Bcf Shell Cruttenden 846S 22H EUR /,000 : 2.3 Bcf JKLM Energy Sweden Valley 0 2HU EUR /,000 : 2. Bcf Seneca Resources DCNR H EUR /,000 : 2.4 Bcf 20

21 March 208 Eclipse Flat Castle Project Area Type Curves Eclipse has developed two type curves for the Flat Castle Project Area (i) a base case and (ii) an upside case that is increased by 2% to reflect higher gas in place on Eclipse acreage versus analog wells Mcf/d 60,000 50,000 40,000 30,000 Analogue Well Average Eclipse 208 Base Case Type Curve Eclipse 208 Upside Case Type Curve Lateral Length: 6,700 6,000 6,000 Proppant per ft:,59 2,600 2,600 EUR (Bcfe/000 ) Max EUR (Bcfe/,000 ) 2.8 Upside potential by applying Eclipse s state of the art practices and lessons learned in the Ohio Utica Shale 20,000 0,000 Cumulative Gas Bcf Months Months Eclipse has analyzed 22 producing industry wells within the project area to develop initial Type Well expectations The wells used to establish a type curve: Landed in Eclipse s target interval Have sufficient production histories Exist within a reasonable control radius Analog Wells Base Case Upside Case Gas rate and cumulative production normalized to 6,000 lateral length. 2

22 $.84 $.88 $.92 $.99 $.96 $ % 52% 59% 66% 7% 77% March 208 Attractive Flat Castle Project Area Type Curves Well costs and returns assume higher completion costs of a modern completion without an assumed increase in EUR as compared to offset wells Base Case Upside Case IRR Sensitivity to Lateral Length ($3.00 gas) Base Case Upside Case Lateral Length 6,000 6,000 Royalty Burden 7.7% 7.7% Plateau Gas Rate (Mcf/d) 2 36,89 40,532 Plateau (months) Initial Decline (%) 67% 67% B Factor.. Terminal Decline (%) 6% 6% Shrink 99% 99% Residue BTU,020,020 4,000' 6,000' 8,000' Henry Hub Breakeven Gas Price 4 Gross EUR (Bcf/,000 ) 2.0 Bcf 2.3 Bcf Gross EUR 32.4 Bcf 36.3 Bcf Well Cost ($ MM) $6.4 $6.4 Fixed Expense ($/Well/Month) $4,250 $4,250 Variable Expense ($/Mcf) 3 $0.22 $0.22 Ad Valorem (% Revenue).5%.5% Gas Differential ($/Mcf) ($0.65) ($0.65) 4,000' 6,000' 8,000' Base Case Upside Case Type curves do not represent proved reserves. 2 Represents well-head gas production after 4 weeks of build up. 3 Includes $0.09/mcf gathering rate of midstream capital infrastructure. 4 Breakeven is defined as PV-0 > $

23 March 208 Development Strategy Eclipse has a fully planned development program covering the Flat Castle Project Area Development Metrics 00 gross (87 net) locations with,200 inter-lateral well spacing to allow for higher intensity completions testing and lower overall field development costs Continuous rig program supported by three water sources to ensure completions efficiency Structure midstream gathering and takeaway for up to 750 MMcf/day at full development Beginning with one test well over 3,000 in 208; the average Flat Castle lateral length will then be ~8,000 in Flat Castle in the full development scenario Current test well turn to sales estimated for Q38 Operations, Engineering, Regulatory and Land preparing readiness for rig arrival for an efficient operation Development Timeline Q 208 Q2 208 Q3 208 Q 209 Drill initial Eclipse well in Flat Castle Project Area Gathering agreement option period Monitor and evaluate initial Flat Castle Eclipse well Begin full scale development operations Operations, Engineering, Regulatory and Land preparing readiness for rig arrival 23

24 March 208 Marketing Strategy Diversified Diversified marketing marketing strategy strategy provides provides flexibility flexibility and and enhanced enhanced pricing pricing dynamics dynamics Flow Assurance Diversification Optionality Risk Management Enhance Price Ensure continuous sale of produced products Current and future production to multiple regions and indices, domestically and internationally Negotiate contractual terms to create innovative and flexible solutions and to enhance market access Manage commodity price exposure with physical and financial hedges in order to meet financial goals Maximize prices across all commodity sales and reduce rates/fees for services 207 Average Realized Gas Price ET Rover Phase 2 In-service in 2Q8 Term: 5 years 00,000 Dth/d Gulf 50,000 Dth/d Dawn Mariner East II In-service in 2Q8 Significant portion of expected propane and butane production $3. $2.99 $2.82 $2.76 $2.75 $2.42 $2.30 $2.23 NYMEX Peer Peer 2 Eclipse Peer 3 Peer 4 Peer 5 Peer 6 Shell Ethane Cracker Est. In-service 202 Term: 20 years Must recover volumes/ 30% of ethane production Columbia In-service Term: 5 years 205,000 Dth/d TCO Pool Blue Racer Processing and Fractionation (Berne and Natrium) Shell Ethane Cracker Based on average of 207 average realized price before the effects of hedges; peers include AR, COG, EQT, GPOR, RICE, RRC, SWN. 24

25 March 208 Substantial Market Availability in Central PA Eclipse has developed a gas marketing plan for Flat Castle Project Area that provides reliable sales outlets and favorable market access Favorable Market Access Currently selling into Dominion North Point market and achieving price levels close to Dominion South Point Flat Castle Project Area Ample capacity into Dominion to support near and mid term production growth Alternative options include deliveries into Tennessee and National Fuel for mid to long term sales With pipeline expansion projects coming online in the area, long term trends are favorable and likely further enhance flexibility Dom North to Dom South Differentials Historical Averages: 205: $(0.4) 206: $(0.02) 207: $(0.02) $0.00 $0.050 $- $(0.050) $(0.00) As of 2/3/7. 25

26 March 208 Demand Drivers Northeast Takeaway Appalachian basis differentials narrow as projects come online and transportation capacity exceeds production and projects come online Northeast Production vs Pipeline Takeaway Bcf/d Base Takeaway Capacity NFG Northern Access TGP SW LA Supply NEXUS TCO Leach Rover - Phase 2 TGP Broad Run Transco Atlantic Sunrise Constitution PennEast Millennium Eastern System Upgrade Mountain Valley Pipeline TCO Mountaineer XPress TCO WB XPress Atlantic Coast Pipeline Northeast Production Northeast Basis vs Pipeline Takeaway,2 Appalachian and Mid-Atlantic production is filling new takeaway projects transporting gas to the Gulf Coast, lowering supply in the region Northeast cold snaps providing record-high demand and storage withdrawals in Q of 208, creating volatility and upward pressure on pricing Source: EIA, FERC, Platts Bentek. 2 Based on current strip pricing. 26

27 Gross Marketed Production / Takeaway (MMBtu/d) March 208 Eclipse Firm Transportation Update Diverse firm gas transportation portfolio provides optionality to various markets, with right-sized positions to maximize revenue,200,000,000, , , ,000 Eclipse is currently selling excess production above firm capacity in basin As Rover enters service, gross marketed production will be approximately equal to capacity By year-end, additional production growth will move back into the basin improving net cash flows Evaluate daily market economics and utilize asset management optimization Constant research on expansion projects, power plant and LNG supply deals, and access capacity release market Rover - Trunkline 200,000 Rover - Dawn Columbia - TCO Pool - Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan-20 Apr-20 Jul-20 Oct-20 Rover timing based on Eclipse estimates. 2 Includes Flat Castle production. 27

28 March 208 Corporate Strategy Efficient Capital Deployment Capital expenditures to focus on highest returning areas while providing corporate level returns above cost of capital Investor Aligned Compensation Structure Executive compensation heavily weighted towards performance Culture of Innovation Ability to deploy cutting-edge techniques and leverage our best-in-class operational team Path Forward Measured growth profile with flexibility on capital spending and optionality to adjust based upon commodity prices Delivering Value to Shareholders Eclipse presents a compelling valuation with exceptional assets, significant near-term catalysts and substantial longterm growth prospects 28

29 APPENDIX

30 March 208 Utica Shale Drilling Joint Venture Transaction Summary Utica Shale Drilling Joint Venture with Sequel Energy increases Eclipse s return on capital at an attractive implied per acre valuation and improves well economics Drilling Joint Venture Overview Eclipse has closed on a drilling joint venture agreement with Sequel Energy ( Sequel, an affiliate of GSO Capital) on the Company s Utica Shale acreage Sequel has committed up to $290 million to fund its proportionate share of two drilling programs comprising of 33 gross wells Eclipse has elected its pre-carry working interest to be 50% and 30% in Programs and 2, respectively Eclipse will receive a 5% carried interest on drilling and completion capital expenditures incurred in each well program A significant portion of Sequel s working interest in each well program will revert to Eclipse once a certain return is realized by Sequel A mutual option exists for an additional third, similarly sized well program Sequel to earn a well-bore assignment in each well drilled equating to ~4,800 net acres 2 in aggregate for the two programs; equates to 5 net locations 3 (4.0% of Eclipse s risked locations) Implied Acreage Valuation ($/acre) 2 $30,274 $20,709 $5,00 $2.75/$50 Strip $3.25/$55 Eclipse Type Well BTIRR 4 60% 8% Value creation from two separate cash flow streams: 5% capex carry and reversionary cash flow Enhanced well IRR economics & attractive implied acreage value 84% 6% Type Curve Joint Venture Condensate Dry Gas Sequel Energy is an affiliate of GSO Capital Partners; agreement closed Q Assuming 50% / 30% election of working interest in each program. 3 Based 6,000 lateral length and,000 well spacing. 4 Economics run at $3.00 gas and $55 oil based on 6,000 lateral length; type curves do not represent proved reserves. 30

31 March 208 Q and 208 Guidance Q 208E FY 208E Low High Low High Avg. Daily Production (MMcfe/d) % Natural Gas 74% 76% 73% 77% % NGL 3% 5% 2% 6% % Oil 0% 2% 0% 2% Forecasted Realizations Natural Gas ($/Mcf),2 Differential to NYMEX $(0.0) $(0.20) $(0.25) $(0.35) NGL Price as % of WTI 45% 48% 35% 40% Oil ($/Bbl) Differential to NYMEX $(6.25) $(6.75) $(6.25) $(7.25) Projected Operating Costs Cash Production Costs per Mcfe 3 $.50 $.55 $.55 $.60 Cash G&A 4 $9.5MM $0.0MM $38MM $40MM Capital Expenditures 5 ~$300MM - $320MM Excludes impact of hedges. 2 Excludes the cost of firm transportation. 3 Includes lease operating, transportation, gathering, and compression, production and ad valorem taxes. 4 Non-GAAP measure which excludes non-cash compensation. 5 Excludes potential acquisitions. 3

32 March 208 Premier Utica and Marcellus Assets Eclipse has 36 risked future extended reach lateral locations, equating to ~6 years of drilling inventory based on 3-year development plan outlook Condensate Rich Gas Dry Gas Marcellus Flat Castle Total Net Acres 39,672 8,046 48,05 5,456 44,500 55,725 Net Undeveloped Acres 29,252 7,63 40,849 5,25 44,26 37,355 Risked Net Undeveloped Acres 26,327 6,852 36,764 3,63 39,835 23,620 Inter-Lateral Spacing 750,000, ,200 Risked Net Remaining Locations Assumed Lateral Length 6,000 6,000 6,000 2,000 6,000 Based on 6,000 lateral, other than Marcellus Condensate which is based on 2,000 lateral. Utica Dry Gas and Utica Rich Gas based on,000 well spacing, Utica Condensate and Marcellus Condensate based on 750 well spacing and Flat Castle based on,200 well spacing. 0% risk factor is utilized. Acreage as of 2/3/7. 32

33 208 Ohio Type Curves and Flat Castle Type Curves March 208 Type curves do not represent proved reserves Utica Condensate Utica Rich Gas Utica Dry Gas Marcellus Condensate Flat Castle Base Case Flat Castle Upside Case Type Curve Assumptions Inter-Lateral Spacing (ft.) 750,000, ,200,200 Lateral Length (ft) 6,000 6,000 6,000 2,000 6,000 6,000 Initial Gas Production Period (Mcf/d) 6,400 27,200 39,420 8,640 36,89 40,532 Flat Period (months) Initial Decline (%) 60% 67% 73% 55% 67% 67% B Factor Terminal Decline (%) 6% 6% 6% 6% 6% 6% Initial Sales Cond. Production (Bbl/d) 83 N/A N/A 58 N/A N/A Initial GOR (Scf/Bbl) 7,704 N/A N/A 6,679 N/A N/A Initial Cond. Yield (sales) (Bbl/MMcf) 30 N/A N/A 60 N/A N/A Secondry Cond. Yield (Bbl/MMcf) N/A N/A N/A N/A N/A N/A Cond. Yield Transition Time (Mth) N/A N/A N/A N/A N/A N/A Terminal Cond. Yield (Bbl/MMcf) 60 N/A N/A 20 N/A N/A Cond. Yield Transition Time (Mth) 24 N/A N/A 20 N/A N/A Shrink 85.2% 92.0% N/A 83.0% 99.0% 99.0% NGL Yield (Bbls/MMcf) N/A 06 N/A N/A Residue BTU,0,065,025,0,020,020 Target Pressure Drawdown (Psi/Week) Post-Processed EUR (Bcfe/,000') Post-Processed EUR (Bcfe) Oil (MBbl) NGL (MBbl) 830,238 -, Residue Gas (MMcf) 7,943 28,478 35,070 0,884 32,384 36,270 Post-Processed % Gas 47% 79% 00% 5% 00% 00% GOR (Scf/Bbl),546 N/A N/A 32,685 N/A N/A Differentials 3 Gas ($/MMBtu off NYMEX) ($0.60) ($0.60) ($0.60) ($0.60) ($0.65) ($0.65) Condensate ($/Bbl off WTI) ($6.25) ($6.25) N/A ($8.00) N/A N/A NGL (% WTI) 40% 40% N/A 40% N/A N/A Operating Expenses Operating Expenses ($/well per month) $4,877 $4,877 $5,364 $8,44 $4,250 $4,250 Gathering, Compression & Dehy ($/Mcf) $0.54 $0.54 $0.23 $0.38 $0.22 $0.22 Processing & Plant Fees ($/Mcf) $.02 $0.65 $0.00 $.02 $0.00 $0.00 Liquid Transportation & Stabilization ($/Bbl) $2.09 $0.00 $0.00 $0.00 $0.00 $0.00 Production Tax 3.6% 4.% 4.5% 3.6%.5%.5% Well Cost Assumptions Well Cost ($ MM) $3.2 $3.2 $6. $9.9 $6.4 $6.4 Well Cost per foot ($/ft) $826 $826 $,009 $822 $,023 $,023 Represents 24-hour rate well-head gas production. 2 Assumes ethane rejection with contractual 30% recovery. 3 Includes transportation costs and basis differentials. 33

34 2,000' Lateral 4,000' Lateral 6,000' Lateral 8,000' Lateral March Type Curve Summary Utica Condensate Utica Rich Gas Utica Dry Gas Marcellus Condensate Flat Castle Base Case Flat Castle Upside Case Gas IP Rate (Mcf/d) 7,200 30,600 44,350 2,960 40,72 45,598 Initial Cond. Yield (Bbl/MMcf) 30 N/A N/A 60 N/A N/A EUR (w/ processing) (Bcfe) BT IRR ($3.00 Gas, $55.00 Oil, NGL 40% of WTI) 67% 56% 92% 93% 59% 77% PV0 ($M) 3,368,72 2,6 9,670 7,258 2,466 Well Cost ($MM) $4.3 $4.3 $7.5 $3.3 $7.8 $7.8 Breakeven Gas Price at $55.00 Oil ($/Dth) 2 $0.00 $2.27 $.88 $0.37 $.96 $.84 Breakeven Oil Price at $3.00 Gas ($/Bbl) 2 $3.00 $0.00 N/A $2.30 N/A N/A EUR, Bcfe/000' Gas IP Rate (Mcf/d) 6,400 27,200 39,420,520 36,89 40,532 Initial Cond. Yield (Bbl/MMcf) 30 N/A N/A 60 N/A N/A EUR (w/ processing) (Bcfe) BT IRR ($3.00 Gas, $55.00 Oil, NGL 40% of WTI) 6% 50% 84% 87% 52% 7% PV0 ($M),329 9,823 8,094 7,007 4,745 8,485 Well Cost ($MM) $3.2 $3.2 $6. $2.3 $6.4 $6.4 Breakeven Gas Price at $55.00 Oil ($/Dth) 2 $0.20 $2.3 $.92 $0.44 $.99 $.88 Breakeven Oil Price at $3.00 Gas ($/Bbl) 2 $32.00 $0.00 N/A $22.30 N/A N/A EUR, Bcfe/000' Gas IP Rate (Mcf/d) 5,600 23,800 34,500 0,080 3,665 35,465 Initial Cond. Yield (Bbl/MMcf) 30 N/A N/A 60 N/A N/A EUR (w/ processing) (Bcfe) BT IRR ($3.00 Gas, $55.00 Oil, NGL 40% of WTI) 55% 45% 75% 8% 48% 66% PV0 ($M) 9,389 8,005 5,04 4,473 2,326 5,599 Well Cost ($MM) $2.0 $2.0 $4.8 $. $4.8 $4.8 Breakeven Gas Price at $55.00 Oil ($/Dth) 2 $0.35 $2.36 $.98 $0.52 $2.05 $.92 Breakeven Oil Price at $3.00 Gas ($/Bbl) 2 $33.00 $0.00 N/A $23.20 N/A N/A EUR, Bcfe/000' Gas IP Rate (Mcf/d) 8,640 Initial Cond. Yield (Bbl/MMcf) 60 EUR (w/ processing) (Bcfe) 2.2 BT IRR ($3.00 Gas, $55.00 Oil, NGL 40% of WTI) 73% PV0 ($M),944 Well Cost ($MM) $9.9 Breakeven Gas Price at $55.00 Oil ($/Dth) 2 $0.6 Breakeven Oil Price at $3.00 Gas ($/Bbl) 2 $24.50 EUR, Bcfe/000'.8 Type curves do not represent proved reserves Assumes ethane rejection with contractual 30% recovery. 2 Breakeven is defined as PV-0 > $

35 March 208 Hedging Update Eclipse is ~80% hedged for natural gas and ~70% hedged for condensate production in 208 and has recently added incremental hedges in 209 to further limit cash flow uncertainty Summary of Current Hedges 208 Commodity Hedges Approximately 82% of natural gas production hedged Average floor price of $2.93/MMBtu Average ceiling price of $3.26/MMBtu Approximately 7% of oil production hedged Average floor price of $46.78/Bbl Average ceiling price of $54.22/Bbl 209 Commodity Hedges 42,500 MMBtu/d of natural gas production hedged Average floor price of $2.83/MMBtu Average ceiling price of $2.94/MMBtu 2,250 Bbl/d of oil production hedged Average floor price of $5.22/Bbl Average ceiling price of $60.6/Bbl Basis Hedges Dom South exposure hedges 60,000 MMbtu/d of Jan 8 Mar 8 at ($0.44) 2,500 MMbtu/d of Apr 9 Oct 9 at ($0.52) 2,500 MMbtu/d of Apr 20 Oct 20 at ($0.52) 350, , , ,000 50,000 00,000 50,000-7,000 6,000 5,000 4,000 3,000 2,000,000 - Natural Gas (MMBtu/d) $s indicate Avg. Floor Price $2.88 $3.00 $2.9 $2.92 $ ,000 67,500 $2.8 $2.8 $2.8 90,000 30,000 30,000 37,500 37,500 37,500 20,000 30,000 50,000 70,000 90,000 90,000 90,000 90,000 Q 208 Q2 208 Q3 208 Q4 208 Q 209 Q2 209 Q3 209 Q4 209 Oil (Bbl/d) $s indicate Avg. Floor Price $48.20 $48.20 $45.00 $45.00 $ ,000 4,000 $50.00 $50.00 $ ,000 4,000 2,000 2,000 2,000 2,000,000,000, Q 208 Q2 208 Q3 208 Q4 208 Q 209 Q2 209 Q3 209 Q4 209 Hedge % based on guidance midpoint. 35

36 March 208 Hedging Summary Natural Gas Hedges Natural Gas Swaps Natural Gas Call/Put Options Natural Gas Three-Way Collars Oil Hedges Oil Swaps Oil Three-Way Collar Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) 30,000 January March 208 $ ,000 April March 209 $ ,000 April December 208 $ ,000 July September 208 $2.8 40,000 October December 209 $ ,000 January December 209 $2.87 Ceiling sold (call) 40,000 January December 208 $3.75 Ceiling sold (call) 30,000 January March 209 $3.50 Ceiling sold (call) 30,000 April December 209 $3.00 Ceiling sold (call) 0,000 January December 209 $4.75 Floor purchase (put) 30,000 January 208 March 209 $3.00 Ceiling sold (call) 30,000 January 208 March 209 $3.40 Floor sold (put) 30,000 January March 209 $2.50 Floor purchase (put) 40,000 January 208 March 208 $2.90 Floor purchase (put) 40,000 April 208 December 208 $3. Ceiling sold (call) 40,000 January 208 December 208 $3.38 Floor sold (put) 40,000 January 208 December 208 $2.50 Floor purchase (put) 60,000 January 208 March 208 $2.90 Ceiling sold (call) 60,000 January 208 March 208 $3.75 Floor sold (put) 60,000 January 208 March 208 $2.50 Floor purchase (put) 7,500 January 209 December 209 $2.75 Ceiling sold (call) 7,500 January 209 December 209 $3.05 Floor sold (put) 7,500 January 209 December 209 $2.30 Floor purchase (put) 30,000 October 208 December 209 $2.75 Ceiling sold (call) 30,000 October 208 December 209 $3.08 Floor sold (put) 30,000 October 208 December 209 $2.30 Floor purchase (put) 60,000 January 208 December 208 $2.80 Ceiling sold (call) 60,000 January 208 December 208 $3.35 Floor sold (put) 60,000 January 208 December 208 $2.50 Volume (Bbl/d) Production Period Weighted Average Price ($/Bbl),000 July March 209 $6.00 Floor purchased (put) 4,000 January December 208 $45.00 Ceiling sold (call) 4,000 January December 208 $53.37 Floor sold (put) 4,000 January December 208 $35.00 Floor purchased (put) 2,000 January December 209 $50.00 Ceiling sold (call) 2,000 January December 209 $60.56 Floor sold (put) 2,000 January December 209 $40.00 Basis Hedges Swaps Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) IFERC -Appalachia Dominion 60,000 January March 208 ($0.44) IFERC -Appalachia Dominion 2,500 April October 209 ($0.52) IFERC -Appalachia Dominion 2,500 April October 2020 ($0.52) As of 3/2/

37 March 208 Non-GAAP Reconciliations Adjusted EBITDAX Three Months Ended December 3, $ thousands Net income (loss) $ (3,22) $ (62,089) $ 8,525 $ (206,735) Depreciation, depletion and amortization 3,889 28,66 8,88 92,948 Exploration expense 20,695 7,592 50,208 52,775 Rig termination and standby 3 3,846 Stock-based compensation 2, ,30 6,26 Impairment of proved oil and gas properties 7,665 Accretion of asset retirement obligations (Gain) loss on sale of assets (67) 7,880 (79) 6,936 (Gain) loss on derivative instruments (3,980) 43,93 (45,365) 52,338 Net cash receipts (payments) on settled derivatives 2,824 2,826 (2,224) 38,696 Interest expense, net 2,727 2,496 49,490 50,789 (Gain) loss on early extinguishment of debt (4,489) Other (income) expense Income tax benefit (expense) Adjusted EBITDAX $ 53,459 $ 42,86 $ 89,38 $ 02,07 Adjusted Revenue For the Three Months Ended December 3, Year Ended December 3, $ thousands Total revenues $ 04,056 $ 83,883 $ 383,659 $ 235,034 Net cash receipts (payments) on derivative instruments 2,824 2,826 (2,224) 38,696 Brokered natural gas and marketing revenue (,052) (,608) (3,48) (2,09) Adjusted revenue $ 05,828 $ 85,0 $ 377,954 $ 26,7 Cash G&A PV-0 For the Year Ended December 3, For the Three Months Ended December 3, 207 For the Year Ended December 3, 207 Guidance For the Three Months Ending March 3, 208 For the Year Ending December 3, 208 $ thousands General and administrative expenses, estimated to be reported $ 2,344 $ 44,553 $0,500-$3,000 $46,500-$50,000 Stock-based compensation expense (2,444) (9,30) (,000-3,000) (8,500-0,500) Cash general and administrative expenses $ 9,900 $ 35,252 $9,500-$0,000 $38,000-$40,000 Year Ended December 3, $ thousands Future net cash flows $,538,529 $ 300,430 $ 300,059 Present value of future net cash flows: Before income tax (PV-0) $ 729,686 $ 205,98 $ 22,865 Income taxes After income tax (standardized measure) $ 729,686 $ 205,98 $ 22,865 Proved reserves based on estimates provided by Eclipse's independent engineering firm. PV-0 based on SEC pricing. 37

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