Investor presentation posted on Marcellus/Utica driller Eclipse Resources' website--loaded with charts and maps and very useful information. The map/chart on page 23 is particularly interesting. It shows all of the Utica wells drilled by Eclipse to date, color coded by the "zone" where the well was drilled, and with production information.

1. NYSE|ECR
Corporate PresentationSeptember 2014

2. 2
Cautionary Statements
This 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 capitalexpenditures, 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 ReportonForm 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 andoil. 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 oilreserves 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 measuredinan 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.

3. 3

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 Highlights
Premier 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 2ndquarter 2014 end
Eclipse Resources Activity

4. 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. 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/Mcfgas and $90.00/Bbloil 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 Area
Eclipse Acreage Area
Drilling Units
(2)
REXX Rich Gas (3) Wells
Avg. IP Rate 5,103 Boe/d
56% Liquids
AR/ECR AMI Condensate (9) Wells
Avg. IP Rate 4,767 Boe/d
67% Liquids
AR Rich Gas (6) Wells
Avg. IP Rate 7,167 Boe/d
43% Liquids
ECRTippens6HS
Dry Gas Well
IP Rate 24 MMcf/d
GPOR Rich Gas (2) Wells
Avg. IP Rate 5,298 Boe/d
44% Liquids
MHR/Eclipse Stalder3UH
Dry Gas Well
IP Rate 32.5 MMcf/d
ECR Herrick Dry Gas (3) Wells
Avg. 30 Day Rate 11.7 MMcf/d per well
ECRShroyerPad
2 Dry Gas Wells
Avg. Rate 21.3 MMcf.d
ECR MizerPad (5) Condensate Wells
Avg. Rate 695 Boe/d
51% Liquids
RICE Bigfoot 9H
Dry Gas Well
Avg. IP Rate 6,948 Boe/d

6. 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
Tippens
Herrick
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 fracbarrier in the Utica
Eclipse Acreage Area
Poor
Excellent

7. 7
Utica Single-Well Economics (1)
(1)
Assumes $4.00/Mcfnatural gas, $90.00/Bbloil and $43.20/BblNGLs; gas differential assumes ($1.00)/MMbtu
(2)
WTIoil price held constant at $90.00 /Bbl
Eclipse’s Utica Shale asset base generates top returns even in challenging gas price environments
Gas Price IRRSensitivities (2)
Rich ClassificationCondensateIdentified Net Drilling Locations25024016754Pre-Tax PV-10 ($MM)6.95.06.43.1Pre-Tax IRR58%35%55%24% Undiscounted Payback (mos)18261936D&C Capital ($MM)9.510.59.59.530-Day IP Rate (MMcf/d)5,96118,4552,3821,189Bcfe / 1,000'1.32.30.90.6Lateral Length (ft.)6,0006,0006,0006,000Rich GasDry GasCondensate
Rich Gas
Condensate
Rich Condensate
Dry Gas

8. 8
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
East
West
Thickness (ft)
MHR Ormet:
3 wells, Avg. per well IP rate 3.9 MMcf/d, 596 Bbls/d Oil
Protégé II Eisenbarth:
1 well, AvgIP 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/MMcfCond. Yield
In Eclipse’s Marcellus Project Area, the Tully Limestone is absent resulting in the GeneseoShale (Upper Devonian) sitting directly on top of Marcellus Shale

9. 9
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)
ClassificationIdentified Net Drilling Locations245Pre-Tax PV-10 ($MM)8.8Pre-Tax IRR53% Undiscounted Payback (yrs)24D&C Capital ($MM)6.630-Day IP Rate (MMcf/d)1,387Bcfe / 1,000'1.2Lateral Length (ft.)6,000Marcellus
(1)
Assumes $4.00/Mcfnatural gas, $90.00/Bbloil and $43.20/BblNGLs; gas differential assumes ($1.00)/MMbtu
(2)
WTI oil price held constant at $90.00 /Bbl

10. 10
First Half 2014 Activity
Operated Drilling Activity

4 Operated horizontal rigs

Spud 24 gross (16 net) wells in 2ndquarter, 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 2ndquarter
−
Average of 3.6 fracstages per pad per day

Deliberate frac design testing program in progress
Non-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 2014Spud25.0Completed4.2Turned to Sales2.5Net Operated1H 2014Spud3.7Completed0.8Turned to Sales5.9Net Non- Operated

11. 11
Second Half 2014 Planned Activity

Adding 2 rigs in the 4thquarter; exit the year running 6 horizontal rigs

Run 2 fracspreads

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-Operated
Operated
2H 2014FY 2014Spud31.556.5Completed19.623.8Turned to Sales16.519.0Net Operated2H 2014FY 2014Spud10.414.1Completed11.212.0Turned to Sales5.811.7Net Non- Operated

12. 12
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 2015201220132014201520162017Annual NE Natural Gas Production7.611.215.718.220.422.5Annual NE Natural Gas Demand14.114.915.315.115.515.8Northeast Gas Surplus / (Deficit)(6.5)(3.7)0.43.14.96.7Annual Takeaway Additions- - 2.64.78.39.1Cumulative Takeaway Additions (2014-2017)2.67.315.724.8Excess Out of Basin Capacity2.34.210.818.1Northeast Natural Gas Market (Bcf/d) Committed Capacity (Bcf/d)
Excess TakeawayCapacity

13. 13
Diversified Midstream Strategy
Our 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 MarkWestproviding additional diversity
▪
Agreements in place for advantaged ethane sales (Shell Cracker), propane and butane sales (Mariner East II) and condensate sales (Enlink/E2)
REX
REX
TCO
TCO
0 mi
20 mi
40 mi
Cadiz
HoustonComplex
Lewis
Berne
Natrium
Mobley
Hastings
Petersburg
Seneca
Eclipse Acreage Area
BlueRacerProcessing Plant
MarkWestProcessing Plant
Dominion Processing Plant
Shell Chemical Ethane Cracker
Dominion North/South Divide
BlueRacer

14. 14
Firm Sales & Firm Transportation
Focused on developing a diversified transportation strategy to access Appalachian, Gulf Coast and Mid-West markets
Midwest
50,000 Dth/d
Apr. 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 4thquarter 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
Type
StartDate
Tenor
Volume (Dth/d)
Market
Floating Basis
Nov.2014
5 months
80,000
DominionSouth
FixedBasis
Apr. 2015
7 months
50,000
HH less $1.328
FixedBasis
Nov. 2015
5 months
20,000
HH less $0.900
Long Term Firm Transportation In Place
M350,000 Dth/d
Apr. 2015

15. 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

16. Appendix

17. 17
Guidance
Third Quarter 2014Full Year 2014Average Daily Production70 - 85 Mmcfe/d73 - 79 Mmcfe/d% Natural Gas80 - 85%72 - 77% % NGL7 - 10%8 - 11% % Oil8 - 10%12 - 14% % Operated65 - 75%65 - 75% Operated Natural Gas Basis Differential$ (1.65 - 1.75) / MMbtu$ (1.15 - 1.25) / MmbtuLease Operating$ 0.40 - 0.50 / Mcfe$ 0.40 - 0.50 / McfeGathering, Transportation, Compression & Processing$ 0.75 - 0.95 / Mcfe$ 0.75 - 0.95 / McfeProduction Taxes3.5% of revenue3.5% of revenueCash General and Administrative$ 11 - 12 million$ 39 - 42 millionCapital Expenditures$ 690 - 735 millionOperatingExpensesandCapital ExpendituresProductionandBasisDifferential

18. 18
Rich ClassificationCondensateGas IP Rate (MMcf/d)6.018.62.41.21.4Initial Condensate Yield (Bbl/MMcf)50-180325165Terminal Condensate Yield (Bbl/MMcf)20-7215075Condensate Transition Time (Months)18-242418EUR (Bcfe)8.014.15.53.87.4NGL Yield (Bbl/MMcf)71-9093118Gas Shrink87.5%-85.2%84.4%80.5% Lateral Length (ft.)6,0006,0006,0006,0006,000Frac Stage Length250'300'250'250'250' Well Cost ($MM)$9.5$10.5$9.5$9.5$6.6Bcfe / 1,000'1.32.30.90.61.2DifferentialsGas ($/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 ROR57.8%35.3%54.5%23.8%53.4% Rich GasDry GasCondensateMarcellus
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/Mcfnatural gas, $90.00/Bbloil and $43.20/BblNGLs
(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. 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 GasDry GasCondensateRich CondensateMarcellusIdentified Net Drilling Locations25024016754245Well CharacteristicsInitial Production (MMcf/d) (1)6.018.62.41.21.4Gas Shrink87.5%-85.2%84.4%80.5% Initial Cond. Yield (Bbl/MMcf) 50-180325165Terminal Cond. Yield (Bbl/MMcf)20-7215075Cond. Yield Transition Time (Mth)18-242418NGL Yield (Bbl/MMcf)71-9093118EUR (MMcfe) (2)7,97114,0735,5423,8217,439Oil (MBbl)149n/a275282315NGL (MBbl)389n/a252142434Residue Gas (MMcf)4,74314,0732,3801,2772,945% Liquids59.5%n/a56.4%66.6%60.4% BTU1,2401,0351,3001,2971,385Residue BTU1,0901,0351,1001,0991,120Lateral Length (ft.)6,0006,0006,0006,0006,000Weighted Avg Net Revenue Interest (3)84.8%80.6%83.3%81.0%80.2% DifferentialsGas ($/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$0.1Drilling3.64.33.63.62.2Completions4.85.14.84.83.7Facilities0.60.60.60.60.6Type Curve AssumptionsExponential PhaseInitial Decline (%)15%20%17%20%20% Months63613Hyperbolic PhaseInitial Decline (%)65%70%55%55%30% B Factor1.01.01.01.21.4Terminal Decline (%)6.0%6.0%6.0%6.0%6.0%

20. 20
Hedging Summary
1.
Henry Hub Natural Gas Differentials
Start DateTermVolume (Dth/d)Average Differential ($/Dth)1Nov-145 months25,000($1.067) Apr-157 months25,000($1.208) Natural Gas Basis SwapsDescriptionVolume(MMbtu/d) Production PeriodWeighted Average Swap Price ($MMBtu) Natural Gas Swaps20,000July - December 2014$4.1820,000January - December 2015$4.09Natural Gas Put Spread Purchased Put20,000June - December 2014$4.50 Sold Put20,000June - December 2014$4.00Natural Gas Put - Sold Sold Put16,800January - December 2015$3.35

21. 21
Adjusted EBITDAX
Change% Net loss(112,648)(18,451)($94,197)511%(131,099) Depreciation, depletion & amortization9,95712,027($2,070)-17%21,984 Exploration Expense9,2954,545$4,750105%13,840 Incentive unit compensation2729($2)-7%56 Accretion of asset retirement obligations191186$53%377 Gain on reduction of pension liablilty0(2,208)$2,208-100%(2,208) Loss on derivative instruments8633,611($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 expense11,61813,636($2,018)-15%25,254 Other income(1,585)0($1,585)(1,585) Income tax expense94,5410$94,54194,541Adjusted EBITDAX11,32811,934($606)-5%23,262per Mcfe$2.97$3.46($0)-14%$2.811H2014(in thousands except per Mcfe data) 2Q141Q14Quarter to Quarter

22. 22
Change% Loss Before Income Taxes, as reported(18,107)(18,451)$344-2%(36,558) Loss on derivative instruments8633,611($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 Liability0(2,208)$2,208-100%(2,208) Add Impairment of Unproved Properties3,6660$3,6663,666Add Dry Hole Expense10227$75278%129Add Non-Cash Compensation Expense2729($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)5,5886,452($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) 2Q141Q14Quarter to Quarter1H2014
Adjusted Net Loss

23. 23
Type Eq. Norm.Gas Norm.GasNGLCond. Curve6,000 ft IP6,000 ft IPGasShrinkYieldYield% Well NameArea(Boe / d)(MMcf / d) BTU(%)(Bbls / MMcf)(Bbls / MMcf)Liquids1Stalder 3UH*6,43638.6NA-- -- -- -- 2Irons 1-4H4,57127.41,072-- -- -- -- 3Porterfield 1H-174,105NANANANANA214Tippens 6H*3,96623.81,035-- -- -- -- 5Richland B 1H-343,651NANANANANA296Stutzman 1-14H2,82114.61,0781145-- 23Average:4,25826.11,0623%11--12% 1Yontz 1H10,41545.61,16113821362Rubel 1H7,24828.51,231171097463Rubel 2H7,13728.21,217171068454Norman 1H6,74528.51,18615932405Rubel 3H6,62926.51,220171065446Shugert 1-12H5,47720.91,2041010211437Noble 1H5,21814.21,2162015249558Guernsey 2H5,12813.41,2072014870579Shugert 1-1H5,11920.81,2041710074410Guernsey 1H4,96412.71,21620152725711Gary 2H4,88519.51,2201610664412Dollison 1H4,39812.01,238181191126313Wagner 1-28H3,42612.61,21418110255014Buell 8H2,8148.9NANANANA4715J. Anderson 2H2,7837.41,25712147836116J. Anderson 5H2,7137.21,25712156766117J. Anderson 3H2,6207.11,25712151716018J. Anderson 4H2,6167.11,25712150736019J. Anderson 1H2,5847.11,25712146695920Cadiz 1H-232,568NANANANANA5721Wagner 3-28H2,2788.51,21418110224922McCort 1-28H1,7747.71,1671487--3823McCort 2-28H1,7087.31,1671487238Average:4,40216.01,21715%1203750% 1Milligan 2H6,71217.21,27622137121662Milligan 3H6,09517.51,2762113780623Wayne 4H5,26513.11,26521134135674Wayne 3HA5,23113.11,27221137130675Coal 3H4,54411.71,27822137123676Wayne 2H4,19110.71,28122138122677Milligan 1H4,0099.91,27622138136688Miley 2H3,6478.41,27822136169709BK Stephens 1-16H3,4207.81,207111101776610Miley 5HA3,2117.31,291221421677011Detweiler 42-3H3,1635.11,263211733278112Rector 1H2,3394.31,248171113007513Scheetz 3H2,3397.31,2908601095314Myron 1H2,2247.21,265854995015Neuhart 3H2,2096.51,2919601305516Scheetz 2H2,1956.71,2909601145317Ryser 1-25H2,1094.31,160211102527318Myron 3H2,0676.91,265954944919Coal 2H2,0416.61,2788561015020Clay 1-4H1,8124.81,258271291276821Boy Scout 5-33H1,6542.91,259221323117722Stout 1-28H1,5264.21,237191231056323Myron 2H1,3824.41,2658541075124Boy Scout 4-33H1,0702.11,289221322607525Stout 2-28H1,1272.91,269201351256626Clay 3-4H9102.21,2582712915770Average:2,9427.51,26518%11215765% 1Boy Scout 1-33H2,6005.31,31025142220742Onega Comm.
14-25H2,2803.41,25420183445953Groh 1-12H2,1443.11,24718131424804Lyon 2-27H1,5911.51,32023155763885Lyon 1-27H1,5772.21,27121137435816Sanford 1H9621.51,31622142363797Boy Scout 2-33H9221.51,31025142356808Lyon 3-27H8691.71,2712113723974Average:1,6182.51,28722%14640581% Dry GasRich GasCondensateRich Condensate
(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)
5
4
6
26
6
17
3
13
2
23
8
9
25
11
2
14
10
22
19
11
9
7
1
24
4
21
3
5
20
12
12
7
1
19
16
23
Rich Condensate
Condensate
Rich Gas
Dry Gas
Stacked Pay Area
Eclipse Acreage Area
1
3
2
8
7
6
15
10
8
6
5
14
18
13
4
3
2
1
18
17
16
15
21
5
4
22
20

24. 24
Out of Basin Takeaway Additions
2014201520162017Project: Rockies Express0.6Dominion0.3Texas Eastern0.6Tennessee Gas Pipeline0.2Tennessee Gas Pipeline0.0Columbia Pipeline Group0.4Texas Eastern0.3Dominion0.2Rockies Express1.2Transco0.5Tennessee Gas Pipeline0.4Tennessee Gas Pipeline0.2Tennessee Gas Pipeline0.6Texas Eastern0.4Texas Eastern0.6Columbia Pipeline Group0.5Columbia Pipeline Group0.3NFG0.1Transco0.7ANR0.2Columbia Pipeline Group1.2Dominion0.1Tennessee Gas Pipeline0.1Iroquois Gas Transmission0.3Rockies Express2.4Texas Eastern0.2Energy Transfer3.3ANR2.0Tennessee Gas Pipeline1.0Columbia Pipeline Group0.8Tennessee Gas Pipeline0.2Texas Eastern1.0Tennessee Gas Pipeline1.2Columbia Pipeline Group1.2Transco1.7Total Annual Takeaway Additions2.64.78.39.1Cumulative Takeaway Additions (2014-2017)2.67.315.724.8Committed & Funded Capacity (Bcf/d)