INVESTOR PRESENTATION NYSE: ECR August 27
August 27 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 presentation, regarding Eclipse Resources Corporation s ( Eclipse Resources or the Company ) 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 -K filed with the Securities Exchange Commission on March 3, 27 (the 26 Annual Report ), and in Item A. Risk Factors of Eclipse Resources Quarterly Reports on Form -Q. Forward-looking statements may include statements about Eclipse Resources and peer group business strategies; reserves; our proposed drilling joint venture with Sequel; general economic conditions; our proposed drilling joint venture with Sequel; financial strategies, liquidity and capital required for developing properties and timing related thereto; realized natural gas, NGLs and oil prices; timing and amount of future production of natural gas, NGLs and oil; hedging strategies and results; future drilling plans; competition and government regulations, including those related to hydraulic fracturing; the anticipated benefits under its commercial agreements; pending legal matters relating to its leases; 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 future operating results, including initial production rates and liquidyields in type curve areas; and plans, objectives, expectations and intentions contained in this presentation that are not historical. Eclipse Resources 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 its 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; our inability to successfully negotiate or enter into definitive agreements and satisfy other conditions precedent for our proposed joint venture drilling transaction with Sequel, and to effectively implement that transaction; 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 26 Annual Report and in Item A. Risk Factors of Eclipse Resources Quarterly Reports on Form -Q. 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 Resources and includes market data and other statistical information from sources believed by Eclipse Resources to be reliable, including independent industry publications, government publications, filings, presentations 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 3, 26. 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
28 27 August 27 Eclipse Profile & Business Highlights Premier Utica and Marcellus Assets ~3,2 net effective acres in the core of the Utica Shale and the liquids rich Marcellus Shale;.2 Tcfe proved reserves 2, representing 8% YoY reserve growth at strip pricing Innovative Operational Team Enhancing well economics through increased lateral lengths in all type curve areas Growth Oriented Business Plan Generation 3 higher intensity completion design further enhancing returns Continued focus on peer leading cost structure Q2 27 Production of 288 MMcfe/d Forecasted 3-year production CAGR of ~25% 27 production growth of ~39% Prudent Financial Plan ~$742 Million Market Cap ~$.6 Billion Enterprise Value $288 million Q2 27 liquidity 3 Strong hedge portfolio: ~9% of Natural Gas; ~75% of Oil 97.5 MMBtu/d of Natural Gas; 4. MBbl/d of Oil As of 6/3/7; acreage includes leased acres pending title completion. 2 Reserves as of year-end 26 from independent engineering firm. 3 Liquidity is net of $34 million of outstanding letters of credit and is pro forma for the $5 million borrowing base increase closed subsequent to Q2 27. 3
August 27 st Half 27 Achievements During the st Half of 27, Revenues grew by 52% over the previous year to $79 million, driving st Half 27 EBITDAX of $9 million, 4% higher than the previous year st Half 27 Financials 289 MMcfe/d Average net production $3.6 per Mcfe Total realized price $.39 per Mcfe cash production costs H 27 EBITDAX of $9 million LTM of $53 million 2 2 Increased Utica Condensate, Rich Gas and Dry Gas type curves Added second operated rig Delivered on guidance for th consecutive quarter Set two new world record for longest lateral drilled 3 Turned to sale seven wells testing several new techniques beyond Gen 3 completions design Increased borrowing base capacity by $ million during 27 4 (up 8% from YE 26) Entered into Utica Shale Drilling JV with Sequel Energy 5 Added 4, Bbl/d of 28 oil hedges EBITDAX and Revenue, which is adjusted, are Non-GAAP measures, see slide 32 for reconciliation. 2 Includes firm transportation. 3 Expected to turn to sale during Q4 27. 4 Includes $5 million increase in Q 27 and $5 million subsequent to Q2 27. 5 Sequel Energy is an affiliate of GSO Capital Partners; proposed agreement entered into subsequent to Q2 27 and is subject to the completion of a definitive agreement. 4
Net Undeveloped Locations August 27 Premier Utica and Marcellus Assets Eclipse has a substantial core asset base with a 2 year extended reach drilling inventory with all type curve areas generating highly economic returns at modest commodity prices Returns by 27 Type Curve Acreage by Type Curve Area % 75% 8% 76% 82% 6% 48% 6% 3,2 net acres $3. / $55 $3.3 / $6 Utica Condensate Utica Rich Gas Utica Dry Gas Marcellus Condensate 5 High-Graded Asset Base Undeveloped Risked Locations by Type Curve Area 2 2 Years of Drilling Inventory 7 4 5 6 Years Inventory 23 73 % 25% 5% 75% % 25% IRR at $3.3 / $6 Pricing Condensate Rich Gas Dry Gas Marcellus As of 6/3/7. 2 Based on current 3-year, 2-rig drilling plan and 3, lateral, other than Marcellus Condensate which is based on, lateral. Utica Dry Gas and Utica Rich Gas based on, well spacing, Utica Condensate and Marcellus Condensate based on 75 well spacing. % risk factor is utilized. 5
August 27 Trading Metric Comparison Eclipse trades at a significant discount relative to Appalachian peers despite similar leverage metrics and the ability to generate economic returns comparable to other basins Trading at peer averages implies a stock price substantially higher than current levels Eclipse s projected leverage ratios align with peer averages Ability to grow organically by generating economic returns substantially in excess of internal cost of capital across our acreage position % of remaining drilling inventory >75% IRRs at $3.3 gas and $6. oil Returns consistent with other high returning plays with substantially lower implied cost of future growth TEV / 27 EBITDAX TEV / Production ($/Mcfe) 2 Average: $5,58 Average: 7.8x $7,82 $7,95 $6,627 $5,44 $4,594 $4,3 $3,735 $2,649.x 9.2x 8.8x 7.9x 7.9x 6.x 5.x 4.7x Peer 2 Peer 3 Peer Peer 4 Peer 5 Peer 6 Eclipse Peer 7 Net Debt / 27 EBITDAX Peer Peer 2 Peer 3 Peer 4 Peer 5 Eclipse Peer 6 Peer 7 Average: 2.x.9x.x.4x.8x 2.x 2.5x 3.x 3.3x Peer Peer 3 Peer 2 Eclipse Peer 6 Peer 7 Peer 4 Peer 5 Peers include AR, COG, EQT, GPOR, RRC, RICE, SWN; EBITDAX based on Consensus estimates; all data as of 7/3/7. 2 Peer production based on Q 27 average daily production, ECR production based on Q2 27 average daily production. 6
August 27 Key 27 Operational Catalysts Updates Eclipse is aggressively seeking ways of enhancing EUR and improving returns to generate value Completed in st Half 27 Utica Dry Gas Gen 3 well performance Evaluation is ongoing; Gen 3 Dry Gas wells are continuing to outperform 27 Type Curve Utica Dry Gas Type Curve implications Higher production and pressure responses of Gen 3 Completions supported increasing 27 Utica Dry Gas Type Curve EUR by 3% to 2.2 Bcfe per, Utica re-frac pilot program Utica Dry Gas Gen 4 testing Marcellus Condensate drilling results Completed in Q; stable but moderate production increase; assessing design and execution approach Completed pad with seven wells testing further optimized sand volumes, engineered perforations designs, diversion techniques, higher fluid volumes, and engineered flow back; pad turned to sale in Q2 and is currently producing at approximately MMcf per day 2 nd Half 27 Drilled two Marcellus wells with lateral lengths of, and 8,3 ; expect to complete during Q3 27 and begin producing in Q 28 Utica Dry Gas Super Lateral Pilot 27 plan includes drilling 2 Utica Dry Gas Super Laterals Accretive leasing and acquisition activity Leased approximately 6,2 acres year to date, replacing non-core acreage sold in Q4 26 7
$4 $3 $3 $2 $2 $ $ $- $4 $3 $3 $2 $2 $ $ $- August 27 27 Planned Activity Overview Continue to high-grade drilling program 27 drilling program to focus in dry gas and condensate areas Super Lateral wells (greater than 5, ) Eclipse continues its growth oriented strategy to increase cash flows with a continued focus on maintaining a sound balance sheet Drilled 2 Marcellus wells to further validate type curves Production Forecast (MMcfe/d) 229 37.5 Entered into a Utica Shale drilling joint venture with Sequel Energy Allows Sequel to participate in two 7 well programs with aggregate invested capital of up to $325 million over two programs with a mutual option to participate in a third A significant portion of Sequel s working interests will revert to Eclipse once a certain return is realized by Sequel in each program 26 27E Improving Operating Cash Margin ($/Mcfe) 3 27 Capital Allocation $2.67 Realized Price $(.48) Cash Opex 26 $(.4) G&A $.79 Operating Cash Margin $3.24 Realized Price $(.43) Cash Opex 27E $(.3) G&A $.5 Operating Cash Margin % Change 9% Increase D&C 87% $3MM Capital Budget 2 Land % Other 2% Proposed agreement entered into subsequent to Q2 27 and is subject to the completion of a definitive agreement. 2 27 capital expenditures excludes potential acquisitions and payments of approximately $7 million for land leased in 26 and paid in 27. 3 Excludes the impact of hedges. 27 calculated using forward Henry Hub and WTI prices as of 7/26/7 and assumes the midpoint of Eclipse s differentials, operating cost and G&A guidance. 8
August 27 Utica Shale Drilling Joint Venture Transaction Summary Utica Shale Drilling Joint Venture with Sequel Energy increases Eclipse s return on capital and provides for significant flexibility to tailor 28 & 29 capital expenditures based on economic conditions Drilling Joint Venture Overview Eclipse has entered into an agreement with Sequel Energy ( Sequel, an affiliate of GSO Capital) on the Company s Utica Shale acreage Committed up to $325 million to fund its proportionate share of two drilling programs comprising 34 gross wells, including certain wells in process and wells to be spud through the end of 28 Eclipse has the right to adjust its pre-carry working interest in the first program up until the fourth quarter of 27 to between 3% to 5%, and its pre-carry working interest in the second program to between 3% to 7% until such program is commenced Eclipse to receive a 5% carried interest on drilling and completion capital expenditures incurred in each well program A significant portion of Sequel s working interest in each well program will revert to Eclipse once a certain return is realized by Sequel 6% Implied Acreage Valuation ($/acre) 2 $34,8 $22, $8, $2.75 / $45 Strip $3.25 / $55 Eclipse Type Well BTIRR 3 6% A mutual option exists for an additional third, similarly sized well program 4% 2% 5% 4% 2% % Sequel to earn a well-bore assignment in each well drilled equating to ~3,7 net acres 2 in aggregate for the two programs; equates to 2 net locations 4 (4.% of Eclipse s risked locations) % 8% 6% 82% % 8% 6% 8% 4% 4% Value creation from two separate cash flow streams: 5% capex carry and Reversionary cash flow Enhanced well IRR economics & Attractive implied acreage value 2% % No JVDry Gas JV No JV 2% % No Condensate JV JV JV with 5% / 5% WI election Proposed agreement entered into subsequent to Q2 27 and is subject to the completion of a definitive agreement. 2 Assuming 5% / 5% election of working interest in each program. 3 Economics run at $3.3 gas and $6 oil. 4 Based 3, lateral length and, well spacing. 9
$, $963 $95 $88 $785 $737 $,235 $,235 $,85 $,78 $,44 $976 $934 Concept August 27 Innovative Operational Team Super Laterals Eclipse has revolutionized the cost structure and returns profile of the Utica through its Super Lateral program Reduce cost per lateral foot to enhance returns Test ability to drill and complete in efficient manner Verify recoverability across lateral & ability to maintain EUR per, foot metrics Cost per lateral foot up to 3% less than average peer operated wells Drilled three wells to date with records set for the longest horizontal laterals at 9,54 9,35 and 8,544, all drilled in 7 days or less Verification of full lateral contribution through tracer data; first Super Lateral well (the Purple Hayes ) results to date exceeding the newly increased Condensate type curve EUR per foot Accomplishment Peer Leading Cost per Foot 2 Utica Condensate Utica Dry Gas 27E Average Six planned in 27 Two planned in 27 27E Average Three planned in 27 Peer 9,' Peer 2 8,' Peer 3 9,' Peer 4 8,' Eclipse 3,' Eclipse 5,' Eclipse 9,' In the U.S., based on discussions with global providers. 2 Sources include Antero s June 27 Investor Presentation, Consol Energy s First Quarter 27 Earnings Presentation, Gulfport s June 27 Investor Presentation, Rice Energy s May 27 Presentation. Peer 9,' Peer 3 8,' Peer 2 9,' Peer 4 9,' Eclipse 3,' Eclipse 5,'
$.7 6 $.7 4 $.7 2 $.7 $.6 8 $.6 6 $.6 4 $.6 2 $.6 $.72 $.74 $.7 $.65 $.69 $.7 $276 $294 $245 $233 $242 $22 August 27 Super Lateral Program With five super laterals drilled to date, Eclipse has outperformed drilled feet per day expectations by ~25%, driving drilling costs ~% below expectations Overview Super laterals drilled in 27 are outperforming drilling cost per foot expectations by ~% Down 2% from Purple Hayes (drilled in 26) Evaluating new steering technologies to further improve drilling performance in the lateral Yanosik A 2H well drilled to a total depth of 24,6 (completable lateral length of 5,62 ) in 2 days from spud to TD Outperformed 5, type curve daily drilling footage by 45% Currently completing two super laterals 84 of 242 stages have been placed to date 99% of planned proppant placed with ~57 million pounds of proppant placed to date,35 Type Cuve Lateral¹: 5,' Spud Date: Average Daily Footage The average daily footage of the five super laterals is outperforming the 5, type curve by 24%,537 Purple Hayes H 8,544' /8/26,62 Well 9,35' 4/2/27,64 Well 2 9,54' 4/24/27,66 Well 3 5,72' 6/2/27 Projected EUR (Bcfe) and F&D Costs ($/Mcfe) 2 Drilling Cost Per Completable Foot ($/ft) 3 6.5 2. 2.2 2.5 7.3 7.2 25. 2.,955 Well 4 5,62' 7//27 5.. 5. - (5.) (.) (5.) (2.) Type Curve 5,' Purple Hayes H Well Well 2 Well 3 Well 4 Type Curve 5,' Purple Hayes H Well Well 2 Well 3 Well 4 Indicates the completable lateral length. 2 Does not include any land capital. 3 Rig MOB costs are removed from the AFE and Projected costs for all wells.
% 9% 8% 7% 6% 5% 4% 3% 2% % % 2% % 8% 6% 4% 2% % 2% % 8% 6% 4% 2% % 4% 2% % 8% 6% 4% 2% % August 27 Increasing IRRs with Longer Laterals Eclipse is continuing to demonstrate the impact of longer laterals; significantly increasing rates of return across our acreage Utica Dry Gas 27 Type Curve IRR Utica Condensate 27 Type Curve IRR 82% 9% 8% 88% % 34% 33% 6,' LL 3,' LL 5,' LL 6,' LL 3,' LL 5,' LL 9,' LL Utica Rich Gas 27 Type Curve IRR Utica Marcellus 27 Type Curve IRR 76% 84% 96% % 22% 33% 58% 6,' LL 3,' LL 5,' LL 9,'LL 6,' LL,' LL 5,' LL Based on $3.3 / $6. pricing 2
Goal Innovative Operational Team Completions Design August 27 Eclipse pioneered the Generation 3 completion design, generating higher EURs and returns; currently testing completions techniques that may form the basis for future completions designs Increase proppant loading and decrease stage spacing to increase stimulated reservoir volume (SRV) Initial reservoir modeling supports stimulated reservoir volume and productivity enhancement Generation - 25 stage spacing - XLink gels Maintain completion cost structure Able to complete within 2% of prior Gen 2 well costs due to operational efficiencies of team Accomplishment Generation 2 - % slickwater - Fit for purpose friction reducers Generation 3 - % slickwater - Decreased stage spacing - Increased sand concentration - Engineered flowback Enhance type curve economics across Utica Condensate and Utica Dry Gas locations All Utica Shale Type Curves increased due to Gen 3 wells outperforming all previous type curve assumptions Generation 4 testing - Further optimized sand use - Chemical diversion - Engineered perforation designs - Higher fluid volumes 3
6,7 7,3 8,7,3 4,3 8,8,7 2,3 4 2,,8 4 6 6 8 2,8 8 2 2,9 2 23 23 245 245 August 27 Cost Focused Operating Activities Eclipse continues to push the boundaries on key well parameters Average Proppant Loading (lbs/ft) Average Stage Spacing (ft) 4, 3,5 3, Max: 2,95 24 26 H 27 Max: 3, Max: 3,35 24 26 H 27 2,5 Max: 2, 2,,5, 5 Wet Wet Dry Dry Wet Dry 25, 2, 5,, 23 Average Drilled Lateral Length (ft) 2 4 24 26 H 27 Max: 9,2 6 245 8 Max: 3, 2 Max: 4,6 27 Plan Over 3, average drilling lateral length.4 average drilling days per, 3 (.2 wet gas,.7 dry gas) 5 wet gas and 2 dry gas stage spacing 2,3 lbs/ft in wet gas and 2,8 lbs/ft in dry gas proppant loading 5, Continued application of % slickwater fracturing fluid Wet Wet Dry Dry Generation 4 completions design testing on select pads Well year classified by end of stimulation date. 2 Well year classified by TD date, drilled lateral length includes curve section to TD. 3 Drilling days per, of total drilling footage. 4
76% IRR Minimum August 27 Future Net Locations by Type Curve Eclipse has 37 risked future extended reach locations in type curve areas achieving an 75%+ IRR Dry Gas Rich Gas Condensate Marcellus Net Acres 47,2 8,9 42,522 4,67 Risked Net Acres 2 42,49 8,2 38,27 3,23 Inter-Lateral Spacing,, 75 75 Risked Net Locations 39 26 67 74 Net Producing Wells 3 35.2 2.8 6.4.6 Risked Net Remaining Locations 4 23 7 73 Assumed Lateral Length 3, 3, 3,, Risked Net Remaining Location IRR Concentration 7 4 73 23 6% 7% 8% 9% % % IRR Before tax; $3.3 gas, $6. oil, NGL 4% of WTI. 2 Using a % risk factor. 3 As of 6/3/7. 5
Cumulative Gas (Bcf) August 27 Utica Dry Gas Type Curve Gen 3 wells continue to outperform the 27 type curve at target pressure drawdown rates Completions Design 27 Type Curve 2 stage spacing % Slickwater 2,8 lbs proppant LL 3, Well Cost Gas IP Rate EUR $2.7 MM 22.9 MMcf/d 2.2 Bcf/, % Gas % Gas Rate (MMcf/Day) 4 35 3 25 2 5 5 Daily Gas Production 2 Avg. Gen 3 27 Dry Gas Type Curve (2.2 BCF/,') 6 2 8 24 Months on Production Utica Dry Gas Type Curve BTIRRs Cumulative Gas Production 2 82% 5 Avg. Gen 3 27 Dry Gas Type Curve (2.2 BCF/,') 6% 5 $3. / $55 $3.3 / $6 6 2 8 24 Months on Production Type curve economics assume the middle of the type curve area. 2 Production history based on Eclipse operated wells only, normalized to 3, as of 7/3/7. 6
August 27 Utica Condensate Type Curve Performance of Gen 3 Completions continue to meet or exceed 27 Utica Condensate type curve EURs Cum. Gas Equivalent (Bcfe) Completions Design 27 Type Curve 5 stage spacing % Slickwater 2,3 lbs proppant LL 3, Well Cost Gas IP Rate Initial GOR EUR $.6 MM 5.2 MMcf/d 7,74 Scf/Bbl. Bcfe/, % Liquids 53% Gas Production (MMcf/Day) 5 Daily Gas Production 2 Avg. Gen 3 27 Utica Condensate (. BCFE/,') 6 2 8 24 3 36 Months on Production Utica Condensate Type Curve BTIRRs 6% 8% 5 Cumulative Gas Equivalent Production 2 Avg. Gen 3 27 Utica Condensate (. BCFE/,') $3. / $55 $3.3 / $6 6 2 8 24 3 36 Months on Production Type curve economics assume the middle of the type curve area, with GOR increasing moving east to west. 2 Production history based on Eclipse operated wells only, normalized to 3, as of 7/3/7. 7
Cum. Gas Equivlanet (Bcfe) August 27 Utica Rich Gas Type Curve While Gen 3 wells have not yet been drilled, Gen 2 results are consistent with the 27 Utica Rich Gas type curve Completions Design Utica Rich Gas 27 Type Curve BTIRRs 48% 27 Type Curve 5 stage spacing % Slickwater 2,3 lbs proppant LL 3, Well Cost Gas IP Rate Initial GOR EUR $.6 MM 22. MMcf/d Scf/Bbl 2.2 Bcfe/, % Liquids 2% 76% $3. / $55 $3.3 / $6 Gas Rate (MMcf/Day) 3 25 2 5 5 25 2 5 5 Daily Gas Production 2 Avg Gen 2 27 Utica Rich Gas Type Curve (2.2 BCFE/,') 6 2 8 24 3 36 Months on Production Cumulative Gas Equivalent Production 2 Avg Gen 2 27 Utica Rich Gas Type Curve (2.2 BCFE/,') 6 2 8 24 3 36 Months on Production Type curve economics assume the middle of the type curve area. 2 Production normalized to 3, as of 7/3/7. 8
August 27 26 Marcellus Condensate Type Curve Cum. Gas Equivalent (Bcfe) Results from peer operated Marcellus Condensate wells show strong performance relative to type curve; finished drilling the second of two planned Marcellus Condensate wells in 27 to be completed using Gen 3 completions techniques Completions Design Type Curve 5 stage spacing % Slickwater 2,3 lbs proppant LL, Well Cost 2 Gas IP Rate EUR $7.7 MM 5.5 MMcf/d.6 Bcfe/, % Liquids 54% Marcellus Condensate Type Curve BTIRRs Gas Production (MMcf/Day) 2 8 4 Daily Gas Production 3 Avg Gen 27 Marcellus Condensate Type Curve (.6 BCFE/,') 6 2 8 24 3 36 Months on Production Cumulative Gas Equivalent Production 3 75% % 5 Avg Gen 27 Marcellus Condensate Type Curve (.6 BCFE/,') $3. / $55 $3.3 / $6 6 2 8 24 3 36 Months on Production Type curve economics assume the middle of the type curve area. 2 Well costs assumes Gen 3 completions costs. 3 Production history based on Eclipse non-operated well, normalized to, as of 7/3/7. 9
Five Pillars of the Eclipse Marketing Strategy August 27 Marketing Strategy Diversified marketing strategy provides flexibility and enhanced pricing dynamics. Flow Assurance Ensure continuous sale of produced products ET Rover In-service in 4Q7 Term: 5 years, Dth/d Gulf 5, Dth/d Dawn Mariner East II In-service in 4Q7 Significant portion of expected propane and butane production 2. Diversification Direct current and future production to varied regions and indices, domestically and internationally 3. Optionality Negotiate contractual terms to create innovative and flexible solutions and to enhance market access 4. Risk Management Manage commodity price exposure with physical and financial hedges in order to meet financial goals Shell Ethane Cracker Est. In-service 22 Term: 2 years Must recover volumes/ 3% of ethane production Columbia In-service Term: 5 years 25, Dth/d TCO Pool Blue Racer Processing and Fractionation (Berne and Natrium) Shell Ethane Cracker Trailing 2 Month Average Realized Gas Price 5. Enhance Price Maximize prices across all commodity sales and reduce rates/fees for services $2.95 $2.8 $2.47 $2.42 $2.33 $2.3 $2.4 $.99 $.93 Nymex Peer Eclipse Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Based on average of Q2 26, Q3 26 & Q4 26, and Q 27 average realized price before the effects of hedges; peers include AR, COG, EQT, GPOR, RICE, RRC, SWN. 2
$/MMBtu August 27 Appalachian Marketing Overview Appalachian basis differentials narrow as transportation capacity exceeds production and projects come online Bcf/d 4. 3. 2. Northeast Production vs Pipeline Takeaway Base Takeaway Capacity TGP Susquehanna West Rover - Phase NFG Northern Access TETCO Adair/Access/Leb Ext 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 Production. $- Appalachian Basis Differential $(.2) $(.4) $(.6) $(.8) $(.) $(.2) $(.4) $(.22) $(.) $(.77) $(.49) $(.5) 25 26 27 28 29 Dominion South/ TETCO M2 Average Forwards 2 25-26: $(.6) 27-29: $(.59) Source: EIA, FERC, Bentek Energy, LLC. 2 Strip pricing as of 7/24/27. 2
Gross Marketed Production / Takeaway (MMBtu/d) August 27 Firm Transport Portfolio Eclipse s diverse firm gas transportation portfolio provides optionality to various end markets, with right-sized positions to maximize revenue Further Opportunities for Economic Takeaway Out of Basin,, April 27 December 28 Firm sales and seasonal basis hedging to manage Dom South and M2 pricing 2 Supply deals to premium markets Tap capacity release market Mid 8 & Beyond New expansion projects Access unutilized capacity Supply deals with power plants and LNG facilities 9, 8, 8 7, 6, 5, 4, 3, 2, Columbia - TCO Pool, Rover - Trunkline Rover - Dawn Jul-7 Oct-7 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Rover timing based on Eclipse estimates. 2 Eclipse has 8, MMBtu/d of Dominion South exposure hedged from August November 27. 22
August 27 Hedging Update Eclipse continues to actively hedge expected production to provide predictable cash flows and limit capital plan funding risk Summary of Current Hedges 27 Commodity Hedges ~9% of natural gas production hedged Average floor price of $2.89/MMBtu Average ceiling price of $3.33/MMBtu ~75% of oil production hedged Average floor price of $46./Bbl Average ceiling price of $59.79/Bbl ~75% of propane production hedged Average floor price of $.6/Gal 28 Commodity Hedges 97.5 MMBtu/d of natural gas production hedged Average floor price of $2.9/MMBtu Average ceiling price of $3.37/MMBtu 4. MBbl/d of oil production hedged Average floor price of $45./Bbl Average ceiling price of $52.26/Bbl Basis Hedges Dom South exposure hedges 4, MMbtu/d of May7 Nov7 at ($.4) 4, MMbtu/d of Jun7 Nov7 at ($.) 2, MMbtu/d of 27 TCO capacity hedged at ($.85) 3, 25, 2, 5,, 5, - 5, 4,5 4, 3,5 3, 2,5 2,,5, 5 - Natural Gas (MMBtu/d) $s indicate Avg. Floor Price $2.94 $2.88 $2.88 $2.96 $2.85 $2.88 $2.88 $2.88 3, 56,667 23, 2, 9, 5, 9, 9, 9, 53,333 $3. 5, 3,333 2, 2, - 3, 3, - - - - Q 27 Q2 27 Q3 27 Q4 27 Q 28 Q2 28 Q3 28 Q4 28 Q 29 Oil (Bbl/d) $s indicate Avg. Floor Price $46. $46. $46. $45. $45. $45. $45. $46. 4, 4, 4, 4, 4, 4, 4, 2, - Q 27 Q2 27 Q3 27 Q4 27 Q 28 Q2 28 Q3 28 Q4 28 Q 29 As of 7/3/7. 23
August 27 27 Guidance Eclipse has consistently provided reliable guidance and worked to deliver results that met or exceeded production and operating expense guidance every period since IPO Current Guidance History of Delivering on Guidance Q3 27E FY 27E Low High Low High Production Gas Differential Operating Expense Avg. Daily Production (MMcfe/d) 35 355 35 32 % Natural Gas 8% 85% 77% 8% % NGL % 2% % 5% % Oil 5% 7% 7% 9% Forecasted Realizations Natural Gas ($/Mcf),2 NGL Differential to NYMEX $(.6) $(.7) $(.25) $(.35) Price as % of WTI 3% 35% 35% 4% Oil ($/Bbl) Differential to NYMEX $(6.5) $(7.) $(6.) $(7.) Projected Operating Costs Cash Production Costs per Mcfe 3 $.2 $.25 $.4 $.45 Cash G&A 4 $9.MM $.MM $35MM $37MM Capital Expenditures 5 ~$3MM 27 Annual Guidance Updates Increased 27 NGL pricing guidance from 33% 38% to 35% 4% of WTI Decreased 27 oil differential from $(6.5) $(7.5) to $(6.) $(7.) per Bbl Decreased 27 Cash Production Costs from $.4 $.5 to $.4 $.45 per Mcfe Q2 27 Q 27 YE 26 Q4 26 Q3 26 Q2 26 Q 26 YE 25 Q4 25 Q3 25 Q2 25 Q 25 YE 24 Q4 24 Q3 24 Guidance Not Provided Beat guidance Met guidance Missed guidance 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 and payments of approximately $7 million for land leased in 26 and expected to be paid in 27. 24
APPENDIX
5 45 4 35 3 25 2 5 5 2.5 2.5.5 4 2 8 6 4 2 3.5 3 2.5 2.5.5 7 6 5 4 3 2 2.8.6.4.2.8.6.4.2 August 27 26 Reserves and Finding & Development Costs Eclipse continues to lower F&D costs, increase reserves through the drill-bit and increase PV- Reserves (Bcfe) SEC Pricing Reserves (Bcfe) Strip Pricing Year-end 26 PV- ($MM) 469,223 $68 349 589 $26 25 26 25 26 SEC Pricing Strip Pricing F&D ($ / Mcfe) Drilling Costs 2 F&D ($ / Mcfe) All Sources 2 Recycle Ratio All Sources 2 $2.28 $2.86.8x.4x $.7 $.9 24 26 24 26 24 26 Strip pricing as of 2/3/6; PV is a non-gaap measure, a full reconciliation of pre-tax PV to Standardized Measure is provided in Form -K for the year ended December 3, 26. 2 Includes reserve revisions; Recycle Ratio is defined as profit per barrel divided by cost per barrel. 26
August 27 NGL Market Outlook Eclipse markets its NGLs via numerous outlets in order to maximize price and optionality In 26, Eclipse continued to diversify market outlets and enhance pricing with the addition of access to Mariner East I (ethane), TEPPCO pipeline (propane), and barge (natural gasoline) For 27, Eclipse is forecasting an average realized price for an all-in NGL barrel of 35% to 4% of WTI Upon completion of Mariner East II, Eclipse will have the ability to export propane & butane to attractive international markets Based on current strip and international shipping rates, Eclipse s NGL barrel would see an ~5% increase in value relative to current domestic pricing Eclipse is an anchor shipper on Shell s ethane cracker project; when online, this will create a highly competitive pricing structure that results in an ~5% increase to Eclipse s current NGL pricing Marketing by Region Edmonton Markets Ontario Markets Midwest Markets Northeast Markets Rail Transport Shell Cracker Natrium Plant Mariner East I Mariner East II (4Q7) Marcus Hook Gulf Markets South Markets NGLs include ethane. 27
$/BBL $/BBL August 27 Condensate Market Outlook Eclipse has seen condensate markets tighten substantially during the recent downturn, while local demand has strengthened due to local projects coming online Primary markets are refineries in the region and along the Gulf Coast New splitter projects and reduced drilling has generated increased demand for Eclipse s condensate Supply demand shift has caused WTI differentials to tighten by over 2% year over year Recently negotiated a new condensate marketing contract that fixes the discount to West Texas Intermediate price for the period beginning in April of this year through the end of 28 Expected to improve sales and transportation economics by approximately $4 million in 27 $(2.) $(4.) $(6.) $(8.) $(.) $(2.) Average Operated Differential to WTI Average WTI & Eclipse Realized Price 2 $7. $6. Forecast $5. $4. $3. Forecast $2. $. $(4.) Q 25 Q2 25 Q3 25 Q4 25 Q 26 Q2 26 Q3 26 WTI Operated Diff Q4 26 Q 27 Q2 27 Q3 27 Q4 27 $- Q 25 Q2 25 Q3 25 Q4 25 Q 26 Q2 26 Q3 26 Q4 26 Q 27 Q2 27 Q3 27 Q4 27 WTI WTI Forecast Realized Price Realized Price Forecast Period from Q2 26 to Q2 27. 2 Realized price excludes impact of hedges. 28
August 27 27 Type Curve and Cost Assumption Details Utica Dry Gas Utica Rich Gas Utica Condensate Marcellus Condensate Type Curve Assumptions Inter-Lateral Spacing (ft.),, 75 75 Lateral Length (ft) 3, 3, 3,, Initial Gas Production Period (Mcf/d) 22,88 22, 5,2 5,5 Flat Period (months) 9 8 4 Initial Decline (%) 65% 67% 6% 54% B Factor.2.2.25.4 Terminal Decline (%) 6% 6% 6% 6% Initial Sales Cond. Production (Bbl/d) N/A N/A 675 55 Initial GOR (Scf/Bbl) N/A N/A 7,74, Initial Cond. Yield (sales) (Bbl/MMcf) N/A N/A 3 Secondry Cond. Yield (Bbl/MMcf) N/A N/A N/A N/A Cond. Yield Transition Time (Mth) N/A N/A N/A N/A Terminal Cond. Yield (Bbl/MMcf) N/A N/A 6 25 Cond. Yield Transition Time (Mth) N/A N/A 24 24 Shrink N/A 92.% 85.2% 8.% NGL Yield (Bbls/MMcf) N/A 4 89 25 Residue BTU,25,65,, Target Pressure Drawdown (Psi/Week) 25-35 8-2 5-75 - Post-Processed EUR (Bcfe/,') 2 2.2 2.2..6 Post-Processed EUR (Bcfe) 2 28.5 29.2 3.9 5.6 Oil (MBbl) - - 559 33 NGL (MBbl) -,6 674 3 Residue Gas (MMcf) 28,494 23,38 6,454 7,48 Post-Processed % Gas % 79% 47% 46% GOR (Scf/Bbl) N/A N/A,546 22,837 Differentials 3 Gas ($/MMBtu off NYMEX) ($.7) ($.7) ($.7) ($.7) Condensate ($/Bbl off WTI) ($7.) ($7.) ($7.) ($9.25) NGL (% WTI) 4% 4% 4% 4% Operating Expenses Operating Expenses ($/well per month) $5,376 $5,376 $5,376 $5,376 Gathering, Compression & Dehy ($/Mcf) $.32 $.56 $.56 $.35 Processing & Plant Fees ($/Mcf) $. $.65 $.2 $.2 Liquid Transportation & Stabilization ($/Bbl) $. $. $2.9 $3.5 Production Tax 4.5% 4.% 3.6% 3.6% Well Cost Assumptions Well Cost ($ MM) $2.7 $.6 $.6 $7.7 Well Cost per foot ($/ft) $976. $88. $88. $77. Represents 24-hour rate well-head gas production. 2 Assumes ethane rejection with contractual 3% recovery. 3 Includes transportation costs and basis differentials. 29
August 27 27 Type Curve Summary at K, 3K and 5K Utica Dry Gas Utica Rich Gas Utica Condensate Marcellus Condensate 5,' Lateral Gas IP Rate (Mcf/d) 26,4 25,5 6, 8,25 Initial Cond. Yield (Bbl/MMcf) N/A N/A 3 EUR (w / processing) (Bcfe) 32.88 33.66 5.96 23.46 BT IRR ($3.3 Gas, $6. Oil, NGL 4% of WTI) 9% 84% 88% 22% PV ($M) 9,233 4,624 4,35 9,98 Well Cost ($MM) $4. $.78 $.78 $.65 Breakeven Gas Price at $6. Oil ($/Dth) 2 $2.6 $2.2 $. $. Breakeven Oil Price at $3.3 Gas ($/Bbl) 2 N/A $. $29. $22. EUR, Bcfe/' 2.2 2.2..6 3,' Lateral Gas IP Rate (Mcf/d) 22,88 22, 5,2 7,5 Initial Cond. Yield (Bbl/MMcf) N/A N/A 3 EUR (w / processing) (Bcfe) 28.49 29.7 3.83 2.33 BT IRR ($3.3 Gas, $6. Oil, NGL 4% of WTI) 82% 76% 8% 4% PV ($M) 6,57 2,68,95 6,5 Well Cost ($MM) $2.68 $.64 $.64 $9.55 Breakeven Gas Price at $6. Oil ($/Dth) 2 $2. $2.25 $. $. Breakeven Oil Price at $3.3 Gas ($/Bbl) 2 N/A $. $3. $23. EUR, Bcfe/' 2.2 2.2..6,' Lateral Gas IP Rate (Mcf/d) 7,6 7, 4, 5,5 Initial Cond. Yield (Bbl/MMcf) N/A N/A 3 EUR (w / processing) (Bcfe) 2.92 22.44.64 5.64 BT IRR ($3.3 Gas, $6. Oil, NGL 4% of WTI) 68% 65% 67% % PV ($M),27 8,557 8,375,932 Well Cost ($MM) $.7 $8.86 $8.86 $7.7 Breakeven Gas Price at $6. Oil ($/Dth) 2 $2.2 $2.35 $. $. Breakeven Oil Price at $3.3 Gas ($/Bbl) 2 N/A $2. $33. $24. EUR, Bcfe/' 2.2 2.2..6 Assumes ethane rejection with contractual 3% recovery. 2 Breakeven is defined as PV- > $.. 3
August 27 Hedging Summary Natural Gas Hedges Natural Gas Swaps Natural Gas Call/Put Options Natural Gas Three-Way Collars Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu), July 27 December 27 $2.98, July 27 December 27 $3.2 3, October 27 - March 28 $3.46 Ceiling Sold 4, January 28 - December 28 $3.75 Ceiling Sold, January 29 - December 29 $4.75 Floor purchase price (put) 6, July 27 December 27 $2.83 Ceiling sold price (call) 6, July 27 December 27 $3.37 Floor sold price (put) 6, July 27 December 27 $2.3 Floor purchase price (put) 3, July 27 March 29 $3. Ceiling sold price (call) 3, July 27 March 29 $3.4 Floor sold price (put) 2, July 27 March 29 $2.4 Floor sold price (put), July 27 March 29 $2.2 Floor purchase price (put) 2, October 27 December 28 $2.9 Ceiling sold price (call) 2, October 27 December 28 $3.5 Floor sold price (put) 2, October 27 December 28 $2.2 Floor purchase price (put) 6, January 28 March 28 $2.9 Ceiling sold price (call) 6, January 28 March 28 $3.75 Floor sold price (put) 6, January 28 March 28 $2.4 Floor purchase price (put) 6, April 28 December 28 $2.9 Ceiling sold price (call) 6, April 28 December 28 $3.25 Floor sold price (put) 6, April 28 December 28 $2.4 Floor purchase price (put) 6, January 28 December 28 $2.8 Ceiling sold price (call) 6, January 28 December 28 $3.35 Floor sold price (put) 6, January 28 December 28 $2.33 Floor purchase price (put) 2, July 27 December 28 $2.9 Ceiling sold price (call) 2, July 27 December 28 $3.25 Floor sold price (put) 2, July 27 December 28 $2.4 Oil Hedges Volume (Bbl/d) Production Period Weighted Average Price ($/Bbl) Oil Three-Way Collar Floor purchased (put) 2, July 27 - September 27 $46. NGL Hedges Swaps Basis Hedges Swaps Ceiling sold (call) 2, July 27 - September 27 $59.5 Floor sold (put) 2, July 27 - September 27 $38. Floor purchased (put) 2, July 27 - December 27 $46. Ceiling sold (call) 2, July 27 - December 27 $6. Floor sold (put) 2, July 27 - December 27 $38. Floor purchased (put) 4, January 28 - December 28 $45. Ceiling sold (call) 4, January 28 - December 28 $52.26 Floor sold (put) 4, January 28 - December 28 $35. Volume (Gal/d) Production Period Weighted Average Price ($/Gal) Propane 84, July 27 - December 27 $.6 Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) IFERC -Columbia TCO 2, July 27 - December 27 ($.9) IFERC -Appalachia Dominion 4, July 27 - November 27 ($.) IFERC -Appalachia Dominion 4, July 27 - November 27 ($.4) As of 7/3/7. 3
August 27 Non-GAAP Reconciliations Adjusted EBITDAX $ thousands 27 26 27 26 Net income (loss) $,494 $ (73,63) $ 38,34 $ (8,697) Depreciation, depletion and amortization 25,52 2,949 5,34 36,62 Exploration expense 8,997 7,444 2,577 33, Rig termination and standby,292 3,955 Impairment of proved oil and gas properties 7,665 Stock-based compensation 2,348 2,226 4,429 3,7 Accretion of asset retirement obligations 28 89 252 75 (Gain) loss on derivative instruments (8,77) 29,596 (43,274) 9,46 Net cash receipts (payments) on settled derivatives (2,644) 2,88 (6,633) 3,258 Interest expense, net 2,285 2,439 24,747 25,9 (Gain) loss on sale of assets 6 (,24) (,46) (Gain) loss on early extinguishment of debt (5,825) (4,489) Other (income) expense 2 9 4 Income tax (benefit) expense 54 Adjusted EBITDAX $ 39,589 $ 6,95 $ 89,8 $ 37,3 Adjusted Revenue For the Three Months Ended June 3, For the Six Months Ended June 3, $ thousands 27 26 27 26 Total revenues $ 86,9 $ 47,66 $ 88,53 $ 96,672 Net cash receipts (payments) on derivative instruments (2,644) 2,88 (6,633) 3,258 Brokered natural gas and marketing revenue 3 (,65) (2,428) (,283) Adjusted revenue $ 83,55 $ 58,78 $ 78,992 $ 7,647 Cash G&A For the Three Months Ended June 3, 27 For the Three Months Ending September 3, 27 Guidance For the Year Ending December 3, 27 $ thousands General and administrative expenses, estimated to be reported $,73 $,-$3, $44,5-$47,5 Stock-based compensation expense (2,348) (2,-3,) (9,5-,5) Cash general and administrative expenses $ 8,382 $9,-$, $35,-$37, Three Months Ended June 3, Six Months Ended June 3, PV- 2 Year Ended December 3, $ (In thousands) 26 25 24 Future net cash flows $ 3,43 $ 3,59 $ 792,9 Present value of future net cash flows: Before income tax (PV-) $ 25,98 $ 22,865 $ 59,389 Income taxes (78,732) After income tax (standardized measure) $ 25,98 $ 22,865 $ 33,657 All values in thousands of dollars. 2 Proved reserves based on estimates provided by Eclipse's independent engineering firm. PV- based on SEC pricing. 32