NYSE|ECR

Corporate PresentationSeptember 2014

2

Cautionary StatementsThis presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this presentation, 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 “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’ final prospectus dated June 19, 2014 and filed with the Securities Exchange Commission pursuant to Rule 424(b) of the Securities Act on June 23, 2014 (the “IPO Prospectus”), and in “Item 1A. Risk Factors” of Eclipse Resources’ Quarterly Report on Form 10-Q.

Forward-looking statements may include statements about Eclipse Resources’ business strategy; reserves; general economic conditions; financial strategy, liquidity and capital required for developing its properties and timing related thereto; realized natural gas, NGLs 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; 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 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 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, 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 “Item 1A. Risk Factors” in Eclipse Resources’ Final Prospectus of Form S-1 and in “Item 1A. Risk Factors” of this the Company’s Quarterly Report on Form 10-Q.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in Eclipse Resources’ Quarterly Report on Form 10-Q occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements.

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, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation.

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Targeting a 3-year production CAGR of ~200% − Q2-14 exit rate production up 52%(58 MMcfe) from Q1-14

average− Q2-14 proved reserves up 70% (186.4 Bcfe) from Q1-14

Accelerating Drilling Pace− 4 operated rigs running; 6 by year end− 1-2 net non-operated rigs running− 36 gross (25.0 net) operated wells spud H1-14− 40 gross (31.5 net) operated wells to be spud H2-14− 62 gross (11.8 net) non-operated wells to be spud H2-14− Avg. drilling days reduced to 23 days from spud to rig release

Midstream Plan In Place− 455 MDth/d of long-term firm transportation− Firm gathering, processing and fractionation in place

Unparalleled Growth Potential

Investment HighlightsPremier Appalachian Acreage Position

Proven Management Team & Significant Liquidity

99,300 net acre position located in the core of the Utica play 26,400 net acre position located in the “Highly Liquids Rich” area

of the Marcellus Shale 956 net identified drilling locations

Proven executive management team with significant public company experience & industry leading Utica drilling experience

$568.4 million in liquidity at 2nd quarter 2014 end

Eclipse Resources Activity

4

Top Tier Return Potential

IRRs by Play – Wall Street Research (1)

Eclipse’s acreage position is located in the Utica Core and Highly Liquids Rich Marcellus Plays which have demonstrated top tier returns

(1) Run on futures strip price deck as of 2/6/14

According to Wall Street Research, Eclipse’s acreage is positioned in the top 2 returning plays and 4 of the top 10 returning plays in North America

5

Premier Southern Utica Position▪ Concentrated acreage position in the “Core of the

Core”▪ Operate ~85% of net acreage▪ Additional 131,070 net acres in the oil window (85%

HBP) may represent additional future upside

Type Curve Area Net Acres

% Utica Core Area Net Acres

Identified Net Drilling Locations

Type Well IRR

Dry Gas 34,300 35% 240 35%

Rich Gas 34,300 35% 250 58%

Condensate 25,500 26% 167 55%

Rich Condensate 5,200 4% 54 24%

Total Utica Core Area 99,300 100% 711 --

Marcellus Project Area 26,400 -- 245 53%

Total 125,700 -- 956 --

▪ Over 60% of Eclipse’s acreage within top 2 economic drilling areas in the country (3)

▪ 69% of net drilling locations within type curve areas with type well economics in excess of 50% (1)

(1) Projected IRRs. Assumes $4.00/Mcf gas and $90.00/Bbl oil pricing(2) Acreage in Marcellus Project Area also included in Total Utica Core Area acreage.(3) See IRRs by Play on page 4 of this presentation.

(1)

Stacked Pay AreaEclipse Acreage AreaDrilling Units

(2)

REXX Rich Gas (3) WellsAvg. IP Rate 5,103 Boe/d

56% Liquids

AR/ECR AMI Condensate (9) WellsAvg. IP Rate 4,767 Boe/d

67% Liquids

AR Rich Gas (6) WellsAvg. IP Rate 7,167 Boe/d

43% Liquids

ECR Tippens 6HSDry Gas Well

IP Rate 24 MMcf/d

GPOR Rich Gas (2) WellsAvg. IP Rate 5,298 Boe/d

44% Liquids

MHR/Eclipse Stalder 3UHDry Gas Well

IP Rate 32.5 MMcf/d

ECR Herrick Dry Gas (3) WellsAvg. 30 Day Rate 11.7

MMcf/d per well

ECR Shroyer Pad2 Dry Gas Wells

Avg. Rate 21.3 MMcf.d

ECR Mizer Pad (5) Condensate WellsAvg. Rate 695 Boe/d

51% Liquids

RICE Bigfoot 9HDry Gas Well

Avg. IP Rate 6,948 Boe/d

6

Identification of the Utica Core Area

C’

D’

A’B’

C

A

B

D

Our entire position across the Utica Core Area is characterized by excellent porosities within the Point Pleasant and a tight barrier in the Utica Shale above

A-A’ Cross Section B-B’ Cross Section

C-C’ Cross Section D-D’ Cross Section

Sanford

Miley

TippensHerrick

Stalder

Shroyer

Rector

Mizer

Eclipse Acreage Area

Eclipse Acreage Area

Eclipse Acreage Area

Utica poor porosity

Point Pleasant excellent porosity

Eclipse Acreage:- Consistent thickness- High porosities in the Point

Pleasant- Dense frac barrier in the Utica

Eclipse Acreage Area

Poor Excellent

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Utica Single-Well Economics (1)

(1) Assumes $4.00/Mcf natural gas, $90.00/Bbl oil and $43.20/Bbl NGLs; gas differential assumes ($1.00)/MMbtu(2) WTI oil price held constant at $90.00 /Bbl

Eclipse’s Utica Shale asset base generates top returns even in challenging gas price environments

Gas Price IRR Sensitivities (2)

Rich Class i fi cation CondensateIdenti fied Net Dri l l ing Locations 250 240 167 54Pre-Tax PV-10 ($MM) 6.9 5.0 6.4 3.1Pre-Tax IRR 58% 35% 55% 24%Undiscounted Payback (mos) 18 26 19 36D&C Capita l ($MM) 9.5 10.5 9.5 9.530-Day IP Rate (MMcf/d) 5,961 18,455 2,382 1,189Bcfe / 1,000' 1.3 2.3 0.9 0.6Latera l Length (ft.) 6,000 6,000 6,000 6,000

Rich Gas Dry Gas Condensate

Rich Gas Condensate Rich CondensateDry Gas

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Highly Liquids Rich Marcellus Shale Our 26,400 net acre Marcellus position is in a stacked pay

area that overlies a portion of our Dry Gas Utica acreage allowing Eclipse to share pad, facility and construction costs

Operate ~85% of net acreage Marcellus wells completed in and around our acreage area

have reported initial production rates of:− 3-5 MMcf/d of gas − Condensate yields of 70 to over 100 Bbl/MMcf− NGL yields in excess of 40 Bbl/MMcf− Btu values ranging from 1,250 – 1,450

Liquids rich Marcellus type well IRR of 59% across 195 net locations

Source: Public company releases, ODNR and Management

A’A

EastWest

Thic

knes

s (ft

)

MHR Ormet:3 wells, Avg. per well IP rate 3.9 MMcf/d, 596

Bbls/d Oil

Protégé II Eisenbarth:1 well, Avg IP rate 3.6

MMcf/d, 397 Bbls/d Oil

MHR Stalder: 1 well, Avg. IP rate 5.6

MMcfe/d

Stone Energy Mary Field:11 wells, Avg. IP rates 3-5

MMcf/d, 210 – 350 Bbls/d Oil, 70 – 100 Bbls/MMcf Cond. Yield

In Eclipse’s Marcellus Project Area, the Tully Limestone is absent resulting in the Geneseo

Shale (Upper Devonian) sitting directly on top of Marcellus Shale

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Marcellus Single-Well Economics (1)

Eclipse’s Marcellus Shale asset base provides exceptional rates of return regardless of gas price

Gas Price IRR Sensitivities (2)

Class i fi cation

Identified Net Dril l ing Locations 245Pre-Tax PV-10 ($MM) 8.8Pre-Tax IRR 53%Undiscounted Payback (yrs) 24D&C Capital ($MM) 6.630-Day IP Rate (MMcf/d) 1,387Bcfe / 1,000' 1.2Lateral Length (ft.) 6,000

Marcellus

(1) Assumes $4.00/Mcf natural gas, $90.00/Bbl oil and $43.20/Bbl NGLs; gas differential assumes ($1.00)/MMbtu(2) WTI oil price held constant at $90.00 /Bbl

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First Half 2014 Activity

Operated Drilling Activity 4 Operated horizontal rigs Spud 24 gross (16 net) wells in 2nd quarter, drilled 11

gross ( 6 net) to TD− Averaged 23 days spud to rig release− Drilled our longest lateral at 9,096’− Set spud to rig release company record of 17 days

(TMD 14,881’)Operated Completions Activity 2 frac spreads working with 6 completed wells in 2nd

quarter− Average of 3.6 frac stages per pad per day

Deliberate frac design testing program in progressNon-Operated Activity As of July 31, 2014, interest in 62 gross (11.6 net) non-

operated wells− 9 gross (2.6 net) drilling− 40 gross (8.1 net) producing

Eclipse continues to meet or exceed its drilling and completion goals

Operated Spuds in First Half 2014

1H 2014

Spud 25.0Completed 4.2Turned to Sa les 2.5

Net Operated

1H 2014

Spud 3.7Completed 0.8Turned to Sa les 5.9

Net Non-

Operated

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Second Half 2014 Planned Activity

Adding 2 rigs in the 4th quarter; exit the year running 6 horizontal rigs Run 2 frac spreads

Non-operating program active with up to 10 rigs running in the play

Working acreage trades to consolidate positions

Eclipse will focus its drilling activity in the second half of the year primarily in the condensate and rich gas areas of the play

Non-OperatedOperated

2H 2014 FY 2014

Spud 31.5 56.5Completed 19.6 23.8Turned to Sa les 16.5 19.0

Net Operated

2H 2014 FY 2014

Spud 10.4 14.1Completed 11.2 12.0Turned to Sa les 5.8 11.7

Net Non-

Operated

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North East Supply/Demand Balance

Source: EIA, FERC and Asset Risk Management, LLC.

(10% annual growth)

(15% annual growth)

Excess Basin Production

There is significant excess out of basin transportation capacity to meet production growth expectations as we enter the winter of 2015

2012 2013 2014 2015 2016 2017

Annual NE Natural Gas Production 7.6 11.2 15.7 18.2 20.4 22.5

Annual NE Natural Gas Demand 14.1 14.9 15.3 15.1 15.5 15.8

Northeast Gas Surplus / (Deficit) (6.5) (3.7) 0.4 3.1 4.9 6.7

Annual Takeaway Additions - - 2.6 4.7 8.3 9.1

Cumulative Takeaway Additions (2014-2017) 2.6 7.3 15.7 24.8

Excess Out of Basin Capacity 2.3 4.2 10.8 18.1

Northeast Natural Gas

Market (Bcf/d)

Committed Capacity (Bcf/d)

Excess TakeawayCapacity

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Diversified Midstream StrategyOur acreage is centered across a confluence of major pipelines in the country providing significant in and out of basin optionality

▪ Eclipse’s strategy is focused on two primary objectives:1. Delivery of ample and on-time gathering,

processing and fractionation capacity to support our drilling plan

2. Creation of optionality to access in and out of basin markets across the hydrocarbon spectrum

▪ Firm gathering, processing and fractionation agreements in place with Blue Racer and Eureka Hunter through acreage dedications

▪ Agreements executed for 455 MDth/d of firm transportation with access to Appalachian, Mid-West, Gulf Coast and Canadian markets

▪ Non-operated volumes with Antero are processed by MarkWest providing additional diversity

▪ Agreements in place for advantaged ethane sales (Shell Cracker), propane and butane sales (Mariner East II) and condensate sales (Enlink/E2)

REXREX

TCO

TCO

0 mi 20 mi 40 mi

Cadiz

HoustonComplexLewis

BerneNatrium

MobleyHastings

Petersburg

Seneca

Eclipse Acreage AreaBlueRacer Processing PlantMarkWest Processing PlantDominion Processing PlantShell Chemical Ethane Cracker Dominion North/South Divide

BlueRacer

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Firm Sales & Firm TransportationFocused on developing a diversified transportation strategy to access Appalachian, Gulf Coast and Mid-West markets

Midwest

50,000 Dth/dApr. 2015

To Gulf Coast, Midwest

Canada

Gulf Coast

Markets

Regional Markets

Marcellus & Utica Acreage

TCO Pool205,000 Dth/d

Nov. 2016

▪ Firm transportation agreements executed for 455 MDth/d with access to Appalachian, Mid-West and Gulf Coast Markets

▪ Targeting 40-50% of forecasted gross operated production committed to firm capacity or firm sales agreements− 58% covered in 4th

quarter 2014− Over 50% covered in

2015

▪ Based on current market conditions, differential for operated natural gas production is expected to average approximately $0.90 to $1.00 per MMBtubelow NYMEX during 2015

Additional Short Term Firm Sales

TypeStartDate Tenor

Volume (Dth/d) Market

Floating Basis Nov. 2014 5 months 80,000 Dominion South

Fixed Basis Apr. 2015 7 months 50,000 HH less $1.328

Fixed Basis Nov. 2015 5 months 20,000 HH less $0.900

Long Term Firm Transportation In Place

M350,000 Dth/d

Apr. 2015

15

Detailed drilling plan established and being executed Realistic staged rig ramp over a 3-year period 455 MDth/d of long-term firm transportation Midstream agreements in place to accommodate projected production Targeting a production CAGR of ~200% over the next three years

Realistic and Prudent Business

Plan

Conclusion

One of the Best Acreage Positions

in the Country

Proven Management

Team

“Core of the Core” Utica position with stacked pay Highly Liquids Rich Marcellus upside

Largely contiguous and concentrated acreage position ~85% operated 956 identified net well locations

Proven public company experience at senior level Proven technical and operational team with significant Utica and Appalachian

Basin experience Fully staffed to accommodate planned drilling program Fully aligned with shareholders with equity incentives in place that do not dilute

the public shareholder

Current liquidity of $568.4 million (2)

IPO proceeds along with prudent use of debt sized to fully fund 3-year drilling program

Strong Balance Sheet

(1) Calculated by dividing gross remaining identified drilling locations by gross wells expected to be spud in the 2014 drilling plan(2) Based on June 30, 2014 cash and cash equivalents of $493.4mm and effective borrowing base of $75mm

Appendix

17

GuidanceThird Quarter 2014 Full Year 2014

Average Daily Production 70 - 85 Mmcfe/d 73 - 79 Mmcfe/d

% Natural Gas 80 - 85% 72 - 77%% NGL 7 - 10% 8 - 11%% Oil 8 - 10% 12 - 14%

% Operated 65 - 75% 65 - 75%

Operated Natural Gas Basis Differential $ (1.65 - 1.75) / MMbtu $ (1.15 - 1.25) / Mmbtu

Lease Operating $ 0.40 - 0.50 / Mcfe $ 0.40 - 0.50 / McfeGathering, Transportation, Compression & Processing $ 0.75 - 0.95 / Mcfe $ 0.75 - 0.95 / McfeProduction Taxes 3.5% of revenue 3.5% of revenueCash General and Administrative $ 11 - 12 million $ 39 - 42 million

Capital Expenditures $ 690 - 735 million

OperatingExpenses

andCapital

Expenditures

Productionand

BasisDifferential

18

Rich Class i fi cation Condensate

Gas IP Rate (MMcf/d) 6.0 18.6 2.4 1.2 1.4Ini tia l Condensate Yield (Bbl/MMcf) 50 - 180 325 165Terminal Condensate Yield (Bbl/MMcf) 20 - 72 150 75Condensate Trans i tion Time (Months) 18 - 24 24 18EUR (Bcfe) 8.0 14.1 5.5 3.8 7.4NGL Yield (Bbl/MMcf) 71 - 90 93 118Gas Shrink 87.5% - 85.2% 84.4% 80.5%

Latera l Length (ft.) 6,000 6,000 6,000 6,000 6,000Frac Stage Length 250' 300' 250' 250' 250'Wel l Cost ($MM) $9.5 $10.5 $9.5 $9.5 $6.6Bcfe / 1,000' 1.3 2.3 0.9 0.6 1.2

Di fferentia lsGas ($/MMBtu) ($1.00) ($1.00) ($1.00) ($1.00) ($1.00)Condensate ($/Bbl ) (10.00) (10.00) (10.00) (10.00) (10.00)NGL (% of WTI) 48.0% 48.0% 48.0% 48.0% 48.0%

Pre-Tax NPV10 ($MM) $6.9 $5.0 $6.4 $3.1 $8.8Pre-Tax ROR 57.8% 35.3% 54.5% 23.8% 53.4%

Rich Gas Dry Gas Condensate Marcellus

Type Curve Summary

Type Curve Area Detail (2)

Type Curve Approach Well Economics and Acreage (1)

▪ Eclipse type curves assume a “managed choke” in order to minimize the reservoir pressure drawdown and maximize condensate and total hydrocarbon recovery and IRR‒ In many cases the IP rate is 50% lower than

unmanaged choke production▪ We have observed that the use of a managed choke

has resulted in increased condensate yield through a limited reservoir pressure drawdown

We have developed our type curves based on wells we have participated in as of April 2014

(1) Assumes $4.00/Mcf natural gas, $90.00/Bbl oil and $43.20/Bbl NGLs(2) Does not represent proved reserves

(3)

(3) Assumes 30% ethane recovery(4) Gas differential includes basis differential or cost of marketing, interstate pipeline transportation, and applicable fuel

(4)

19

Type Curve and Cost Assumptions

(1) 24-hour rate(2) Assumes 30% ethane recovery

(3) Type curve outputs generated assuming a 100% working interest and an 80% net revenue interest for Dry Gas and Marcellus areas. All other areas assumed to be an 83% net revenue interest

(4) Gas differential includes basis differential or cost of marketing, interstate pipeline transportation, and applicable fuel

Rich Gas Dry Gas Condensate Rich Condensate MarcellusIdentified Net Drilling Locations 250 240 167 54 245Well Characteristics

Initial Production (MMcf/d) (1) 6.0 18.6 2.4 1.2 1.4Gas Shrink 87.5% - 85.2% 84.4% 80.5%Initial Cond. Yield (Bbl/MMcf) 50 - 180 325 165Terminal Cond. Yield (Bbl/MMcf) 20 - 72 150 75Cond. Yield Transition Time (Mth) 18 - 24 24 18

NGL Yield (Bbl/MMcf) 71 - 90 93 118EUR (MMcfe) (2) 7,971 14,073 5,542 3,821 7,439

Oil (MBbl) 149 n/a 275 282 315NGL (MBbl) 389 n/a 252 142 434Residue Gas (MMcf) 4,743 14,073 2,380 1,277 2,945% Liquids 59.5% n/a 56.4% 66.6% 60.4%

BTU 1,240 1,035 1,300 1,297 1,385Residue BTU 1,090 1,035 1,100 1,099 1,120Lateral Length (ft.) 6,000 6,000 6,000 6,000 6,000

Weighted Avg Net Revenue Interest (3) 84.8% 80.6% 83.3% 81.0% 80.2%Differentials

Gas ($/MMBtu) (4) ($1.00) ($1.00) ($1.00) ($1.00) ($1.00)Condensate ($/Bbl) (10.00) (10.00) (10.00) (10.00) (10.00)NGL (% of WTI) 48.0% 48.0% 48.0% 48.0% 48.0%

Operating Costs ($MM)Fixed OPEX ($/well/mo) $10,000 $10,000 $10,000 $10,000 $10,000Gathering & Compression ($/Mcf) $0.48 $0.43 $0.48 $0.48 $0.45Processing ($/Dth) $0.69 $0.00 $0.69 $0.69 $0.69Ad Valorem & Severance Tax (%) 6.0% 6.0% 6.0% 6.0% 6.0%

Capital Cost ($MM)Pad $0.5 $0.5 $0.5 $0.5 $0.1Drilling 3.6 4.3 3.6 3.6 2.2Completions 4.8 5.1 4.8 4.8 3.7Facilities 0.6 0.6 0.6 0.6 0.6

Type Curve AssumptionsExponential Phase

Initial Decline (%) 15% 20% 17% 20% 20%Months 6 3 6 1 3

Hyperbolic PhaseInitial Decline (%) 65% 70% 55% 55% 30%B Factor 1.0 1.0 1.0 1.2 1.4Terminal Decline (%) 6.0% 6.0% 6.0% 6.0% 6.0%

20

Hedging Summary

1. Henry Hub Natural Gas Differentials

Start Date Term Volume (Dth/d) Average Differential ($/Dth)1

Nov-14 5 months 25,000 ($1.067)Apr-15 7 months 25,000 ($1.208)

Natural Gas Basis Swaps

Description Volume(MMbtu/d)

Production Period Weighted Average Swap Price ($MMBtu)

Natural Gas Swaps20,000 July - December 2014 $4.1820,000 January - December 2015 $4.09

Natural Gas Put Spread Purchased Put 20,000 June - December 2014 $4.50 Sold Put 20,000 June - December 2014 $4.00Natural Gas Put - Sold Sold Put 16,800 January - December 2015 $3.35

21

Adjusted EBITDAX

Change %Net loss (112,648) (18,451) ($94,197) 511% (131,099) Depreciation, depletion & amortization 9,957 12,027 ($2,070) -17% 21,984 Exploration Expense 9,295 4,545 $4,750 105% 13,840 Incentive unit compensation 27 29 ($2) -7% 56 Accretion of asset retirement obligations 191 186 $5 3% 377 Gain on reduction of pension liablilty 0 (2,208) $2,208 -100% (2,208) Loss on derivative instruments 863 3,611 ($2,748) -76% 4,474 Net cash payment on derivative instruments (790) (1,441) $651 -45% (2,231) Net cash paid for option premium (141) 0 ($141) (141) Interest expense 11,618 13,636 ($2,018) -15% 25,254 Other income (1,585) 0 ($1,585) (1,585) Income tax expense 94,541 0 $94,541 94,541Adjusted EBITDAX 11,328 11,934 ($606) -5% 23,262

per Mcfe $2.97 $3.46 ($0) -14% $2.81

1H2014(in thousands except per Mcfe data)

2Q14 1Q14Quarter to Quarter

22

Change %Loss Before Income Taxes, as reported (18,107) (18,451) $344 -2% (36,558)Loss on derivative instruments 863 3,611 ($2,748) -76% 4,474Net cash payment on derivative instruments (790) (1,441) $651 -45% (2,231)Net cash paid for option premium (141) 0 ($141) (141)Less Gain on Reduction of Pension Liability 0 (2,208) $2,208 -100% (2,208)Add Impairment of Unproved Properties 3,666 0 $3,666 3,666Add Dry Hole Expense 102 27 $75 278% 129Add Non-Cash Compensation Expense 27 29 ($2) -7% 56Less Gain on Acquisition (1,586) 0 ($1,586) (1,586)Loss Before Income Taxes, as adjusted (15,966) (18,433) $2,467 -13% (34,399)Income Tax Benefit, adjusted (a) 5,588 6,452 ($863) -13% 12,040Adjusted Net Loss (10,378) (11,981) $1,604 -13% (22,359)

Non-GAAP Adjusted Net Loss Per Share ($0.08) ($0.09) $0 -13% ($0.17)(a) Income tax benefit represents the effect of company’s estimated annual tax rate 35% on Loss Before Income Taxes, adjusted

(in thousands except per share data)2Q14 1Q14

Quarter to Quarter1H2014

Adjusted Net Loss

23

Type Eq. Norm. Gas Norm. Gas NGL Cond.Curve 6,000 ft IP 6,000 ft IP Gas Shrink Yield Yield %

Well Name Area (Boe / d) (MMcf / d) BTU (%) (Bbls / MMcf) (Bbls / MMcf) Liquids

1 Stalder 3UH* 6,436 38.6 NA -- -- -- -- 2 Irons 1-4H 4,571 27.4 1,072 -- -- -- -- 3 Porterfield 1H-17 4,105 NA NA NA NA NA 214 Tippens 6H* 3,966 23.8 1,035 -- -- -- -- 5 Richland B 1H-34 3,651 NA NA NA NA NA 296 Stutzman 1-14H 2,821 14.6 1,078 11 45 -- 23

Average: 4,258 26.1 1,062 3% 11 -- 12%

1 Yontz 1H 10,415 45.6 1,161 13 82 1 362 Rubel 1H 7,248 28.5 1,231 17 109 7 463 Rubel 2H 7,137 28.2 1,217 17 106 8 454 Norman 1H 6,745 28.5 1,186 15 93 2 405 Rubel 3H 6,629 26.5 1,220 17 106 5 446 Shugert 1-12H 5,477 20.9 1,204 10 102 11 437 Noble 1H 5,218 14.2 1,216 20 152 49 558 Guernsey 2H 5,128 13.4 1,207 20 148 70 579 Shugert 1-1H 5,119 20.8 1,204 17 100 7 4410 Guernsey 1H 4,964 12.7 1,216 20 152 72 5711 Gary 2H 4,885 19.5 1,220 16 106 6 4412 Dollison 1H 4,398 12.0 1,238 18 119 112 6313 Wagner 1-28H 3,426 12.6 1,214 18 110 25 5014 Buell 8H 2,814 8.9 NA NA NA NA 4715 J. Anderson 2H 2,783 7.4 1,257 12 147 83 6116 J. Anderson 5H 2,713 7.2 1,257 12 156 76 6117 J. Anderson 3H 2,620 7.1 1,257 12 151 71 6018 J. Anderson 4H 2,616 7.1 1,257 12 150 73 6019 J. Anderson 1H 2,584 7.1 1,257 12 146 69 5920 Cadiz 1H-23 2,568 NA NA NA NA NA 5721 Wagner 3-28H 2,278 8.5 1,214 18 110 22 4922 McCort 1-28H 1,774 7.7 1,167 14 87 -- 3823 McCort 2-28H 1,708 7.3 1,167 14 87 2 38

Average: 4,402 16.0 1,217 15% 120 37 50%

1 Milligan 2H 6,712 17.2 1,276 22 137 121 662 Milligan 3H 6,095 17.5 1,276 21 137 80 623 Wayne 4H 5,265 13.1 1,265 21 134 135 674 Wayne 3HA 5,231 13.1 1,272 21 137 130 675 Coal 3H 4,544 11.7 1,278 22 137 123 676 Wayne 2H 4,191 10.7 1,281 22 138 122 677 Milligan 1H 4,009 9.9 1,276 22 138 136 688 Miley 2H 3,647 8.4 1,278 22 136 169 709 BK Stephens 1-16H 3,420 7.8 1,207 11 110 177 6610 Miley 5HA 3,211 7.3 1,291 22 142 167 7011 Detweiler 42-3H 3,163 5.1 1,263 21 173 327 8112 Rector 1H 2,339 4.3 1,248 17 111 300 7513 Scheetz 3H 2,339 7.3 1,290 8 60 109 5314 Myron 1H 2,224 7.2 1,265 8 54 99 5015 Neuhart 3H 2,209 6.5 1,291 9 60 130 5516 Scheetz 2H 2,195 6.7 1,290 9 60 114 5317 Ryser 1-25H 2,109 4.3 1,160 21 110 252 7318 Myron 3H 2,067 6.9 1,265 9 54 94 4919 Coal 2H 2,041 6.6 1,278 8 56 101 5020 Clay 1-4H 1,812 4.8 1,258 27 129 127 6821 Boy Scout 5-33H 1,654 2.9 1,259 22 132 311 7722 Stout 1-28H 1,526 4.2 1,237 19 123 105 6323 Myron 2H 1,382 4.4 1,265 8 54 107 5124 Boy Scout 4-33H 1,070 2.1 1,289 22 132 260 7525 Stout 2-28H 1,127 2.9 1,269 20 135 125 6626 Clay 3-4H 910 2.2 1,258 27 129 157 70

Average: 2,942 7.5 1,265 18% 112 157 65%

1 Boy Scout 1-33H 2,600 5.3 1,310 25 142 220 742 Onega Comm. 14-25H 2,280 3.4 1,254 20 183 445 953 Groh 1-12H 2,144 3.1 1,247 18 131 424 804 Lyon 2-27H 1,591 1.5 1,320 23 155 763 885 Lyon 1-27H 1,577 2.2 1,271 21 137 435 816 Sanford 1H 962 1.5 1,316 22 142 363 797 Boy Scout 2-33H 922 1.5 1,310 25 142 356 808 Lyon 3-27H 869 1.7 1,271 21 137 239 74

Average: 1,618 2.5 1,287 22% 146 405 81%

Dry

Gas

Ric

h G

asC

onde

nsat

eR

ich

Con

dens

ate

(3)

(2)

(1)

(4)(4)(4)(4)(4)

(5)

(1)

(5)(5)

(5)

(5)

(5)

(5)

Source: Public Company data and Ohio Department of Natural Resources.IP-rate testing time periods as follows: (1) 12 hours; (2) 18hours; (3) 32 hours; (4) 5 days; (5) 7 days; (6) 30 days.Note: Indicates Eclipse participation.

Best Initial Results in the Utica Play

AR CHK GPOR HES MHR PDCE REXX ECR CRZO

Best IP rates within each

type curve area fall within Eclipse’s

acreage area (6)(6)

(6)(6)

(6)(6)

(6)

54

6

26

6

17

3

13

223

8

925

112

14

10 22

19

11

9

71

24

4

21

35

20

12

12

7

1

1916

23

Rich CondensateCondensateRich GasDry GasStacked Pay AreaEclipse Acreage Area

13

2

87

6

15108 6

514

1813432

1

1817

1615

215

4

22

20

24

Out of Basin Takeaway Additions2014 2015 2016 2017

Project:Rockies Express 0.6Dominion 0.3Texas Eastern 0.6Tennessee Gas Pipeline 0.2Tennessee Gas Pipeline 0.0Columbia Pipeline Group 0.4Texas Eastern 0.3Dominion 0.2Rockies Express 1.2Transco 0.5Tennessee Gas Pipeline 0.4Tennessee Gas Pipeline 0.2Tennessee Gas Pipeline 0.6Texas Eastern 0.4Texas Eastern 0.6Columbia Pipeline Group 0.5Columbia Pipeline Group 0.3NFG 0.1Transco 0.7ANR 0.2Columbia Pipeline Group 1.2Dominion 0.1Tennessee Gas Pipeline 0.1Iroquois Gas Transmission 0.3Rockies Express 2.4Texas Eastern 0.2Energy Transfer 3.3ANR 2.0Tennessee Gas Pipeline 1.0Columbia Pipeline Group 0.8Tennessee Gas Pipeline 0.2Texas Eastern 1.0Tennessee Gas Pipeline 1.2Columbia Pipeline Group 1.2Transco 1.7

Total Annual Takeaway Additions 2.6 4.7 8.3 9.1

Cumulative Takeaway Additions (2014-2017) 2.6 7.3 15.7 24.8

Committed & Funded Capacity (Bcf/d)