August 2016 corporate_presentation_final Eclipse resources

August 2016
INVESTOR PRESENTATION

August2016_IR
2
Cautionary Statements
Forward-Looking 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 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 10-K filed with the Securities Exchange Commission on March 4, 2016 (the
“2015 Annual Report”), and in “Item 1A. Risk Factors” of Eclipse Resources’ Quarterly Reports 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 and
the recent significant decline of the price of natural gas, NGLs, and oil, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural
gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in the 2015 Annual
Report and in “Item 1A. Risk Factors” of Eclipse Resources’ Quarterly Reports on Form 10-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 and includes market data and other statistical information from sources believed by Eclipse 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 31, 2015. Actual quantities that may be ultimately recovered from Eclipse’s interests may differ substantially from the estimates in
this presentation. The Company may use the terms “resource potential,” “EUR” and “upside potential” to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the
SEC. These are based on analogy to the Company’s existing models applied to additional acres, additional zones and tighter spacing and are the Company’s internal estimates of hydrocarbon quantities that may be potentially
discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource
Management System or SEC rules. EUR estimates, resource potential and identified drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual
locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations, which have been attributed to these
quantities.
Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment,
drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Resource potential and EUR may change
significantly as development of the Company’s oil and natural gas assets provide additional data. The Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates
of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
The type curve areas included in this presentation are based upon our analysis of available Utica Shale well data, including information regarding initial production rates, Btu content, natural gas yields and condensate yields, all of
which may change over time. As a result, the well data with respect to the type curve areas presented herein may not be indicative of the actual hydrocarbon composition for the type curve areas, and the performance, Btu content
and natural gas and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in our area of operation.
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.

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3
Key Investment Highlights
Premier Utica and
Marcellus Assets
 ~102,000 net acres in the core of the Utica shale and ~13,000 net acres in the liquids rich Marcellus shale
 Attractive returns across the portfolio of up to 63%1
 Deep inventory of 290-440 net undeveloped locations, a 14-22 year drilling inventory depending on lateral length
Prudent
Business
Plan
 Resumed activity in June 2016 based on revised 2016 capital budget of $196 million through a 1 rig program coupled with DUC
inventory completions, targeting 2017 production growth in excess of 30% YoY
 $334 million of liquidity, pro-forma for net $123 million equity offering proceeds, with undrawn borrowing base2
 Fully funded development plan through 2017 at current forward strip pricing with substantial hedges in place
 2017 one rig capital expenditure plan of $200 million – $225 million
 ~80% and ~60% of 2016 gas and oil production hedged, respectively3
 ~80% of 2017 gas and oil production hedged3, with substantial retained upside
Exceptional
Operational
Performance
 One of the lowest cost drillers in the Utica
 Highly efficient drilling has driven 200% increase in lateral lengths with a 50% decrease in cost per foot while drilling 30% faster
than peers
 A peer leader in gas price realizations through diversified marketing plan
 Transportation portfolio appropriately sized for long term production outlook
Pioneering
Super-Lateral
Program
 Eclipse is revolutionizing the development of the Utica through the Super-Lateral program
 Recently drilled and completed the longest onshore horizontal lateral well ever drilled nationwide4 (~18,500 ft completed lateral)
 Transformative to cost and efficiency, driving expected improvement in future well returns of ~35-70%
1 Based on $3.00/MMBtu and $60.00/Bbl. 2 See page 16 for detail. 3 Assumes midpoint of the Company’s announced production guidance. 4 Based on discussions with global
providers.

August2016_IR
1 As of May 31, 2016; acreage in Marcellus also included in Utica Dry. 2 As of closing price on July 29, 2016; Pro forma for $123MM equity raise. 3 See pg. 16 for detail. Pro forma
for $123MM equity raise. 4 Q1-Q2 2016 production was intentionally curtailed while commodity prices recovered; given current strip prices, the Company is returning to normal
operations in 2H 2016. 5As of December 31, 2015; proved reserves based on estimates provided by Eclipse's independent engineering firm. 6 Resource potential is based on
internal estimates and includes, but does not represent, total proved reserves.
4
Company Overview
Eclipse Utica Shale Core Asset Area
Eclipse Resources is a pure play E&P engaged in the acquisition and development of oil and gas assets with over
100,000 acres in the core of the Utica Shale
Net Core Acreage1: 115,000 (38% HBP’d)
Utica Liquids Rich: 53,000 (47% HBP’d)
Utica Dry: 49,000 (37% HBP’d)
Marcellus (Liquids Rich): 13,000 (24% HBP’d)
Valuation
Market Capitalization2 $821 million
Enterprise Value2 $1.1 billion
Liquidity3 $334 million
Average Daily Production (MMcfe/d) and % Liquids4
4Q15 247.0 (30%)
2015 exit rate 270.0 (30%)
1Q16 201.1 (25%)
2Q16 236.1 (29%)
Reserves and Potential
Proved Reserves5 348.8 Bcfe
Total Resource Potential6 6.5 Tcfe
2016 Guidance Highlights
2016 Production (MMcfe/d)4 225 - 230 (27% Liquids)
2016 Capital Expenditures $196 million
2017 Guidance
2017 Production Growth > 300MMcfe/d

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5
Strong Operational Performance
Operated Lateral Length (ft) Operated vs. Non-Op Drilling Days1
Total Cost per Lateral Foot Total Feet Drilled per Day2
6,239 6,836
8,693
13,492
18,776
2013 2014 2015 4Q15 1Q16
31
26
25
17
Non-Op
Eclipse
Non-Op
Eclipse
AllWells
SinceInception
Last20Wells
Drilled
19%
Faster
34%
Faster
$1,718
$1,165
$854
1Q15 3Q/4Q15 1Q16
772
1,011
1,536
1Q15 3Q/4Q15 1Q16
1 Normalized to 15,600’ TMD; as of December 31, 2015. 2 Includes vertical.

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6
Restarting Activity & Growing Production
Modest D&C spending in the second half 2016 and 2017 on the completion of DUCs and the restart of a one-rig
drilling program generates in excess of 30% year-over-year production growth in 2017
 Through Q2 2016 Eclipse voluntarily curtailed its production to ~200
MMcfe/d
― Current strip gas prices motivate return to unconstrained production
 The Company is using the proceeds from the offering to fund its restarted
drilling and completion program
 Restarting the DUC completions and a 1 rig drilling program in the second
half of 2016 leads to over 30% YoY production growth in 2017
― The Company TD’d the most recent well in its 2016 program with a
10,000’ completed lateral in 18 days and began fracing its first DUC
pad in the liquids window, completing 8 stages in the first day
― 10-12 net wells to be spud in 2016 with 1 rig program
$43
$153
$200 - $225
1H16E 2H16E FY 2017E
Note: 13.4 net DUC wells to be turned to sales by year end 2016, with the remaining 6.7 net DUC’s turned to sales by Q2 2017.
0
50
100
150
200
250
300
350
400
450
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16E 4Q16E
2017 YoY Growth in Excess
of 30% or >300 MMcfe/d2016 Full Year
Guidance: 227.5 MMcfe/d
Actual Production
Operational Plan Highlights
Production (MMcfe/d)
Projected Capex ($ MM)

August2016_IR
65% 75% 71% 73%
73% 73%
19%
17%
19%
16%
17%
17%15% 8%
10%
10%
11%
10%208 201
236
218
250
228
2015 1Q16 2Q16 3Q16E 4Q16E 2016E
Gas NGL Oil
Low High Low High
Avg. Daily Production (MMcfe/d) 215 220 225 230
% Natural Gas 70% 75% 70% 75%
% NGL 15% 17% 16% 18%
% Oil 10% 12% 9% 11%
Forecasted Realizations1
Natural Gas ($/Mcf)
Differential to NYMEX $(0.55) $(0.60) $(0.25) $(0.35)
Firm Transportation $(0.35) $(0.40) $(0.35) $(0.45)
Total Differential $(0.90) $(1.00) $(0.60) $(0.80)
NGL
Price as % of WTI 23% 28% 25% 30%
Oil ($/Bbl)
Differential to NYMEX $(9.00) $(11.00) $(9.00) $(12.00)
Projected Operating Costs
Operating Cost per Mcfe2
$1.15 $1.20 $1.15 $1.20
Cash G&A $6.0MM $7.0MM
Cash Exploration $4MM $6MM
Capital Expenditures3
Operational Metrics
Net Wells Spud 10 12
Net DUCs Completed 19 22
Net Wells TTS 17 20
Q3 2016E FY 2016E
$30MM
$25MM - $30MM
$196MM
7
Eclipse Q3 & Full Year 2016 Guidance
The Company resumed drilling and completions at the beginning of June and now expects full year 2016
production to be ~228 MMcfe/d, a 14% increase from the Company’s initial guidance of ~200 MMcfe/d
Op D&C
85%
Non-Op D&C
5%
Midstream
2%
Land & Other
8%
1 Excludes impact of hedges.
2 Excludes firm transportation, DD&A, exploration, and general and administrative expenses.
3 Excludes land and producing asset acquisitions.
Total 2016E Capex: $196MM
2016 Capital Expenditures
Production Mix (MMcfe/d)

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Super-Lateral Program
Eclipse aims to revolutionize the cost structure and returns profile of the Utica Shale through its
Super-Lateral program
$854
$1,111
$1,450
Purple Hayes
18,544' ²
Peer 1 TC
9,000'
Peer 2 TC
9,000'
D&C/ft
1 Based on discussions with global service providers. 2 Completed lateral length.
 Eclipse’s Super-Lateral test well in the Utica condensate window was
completed in Q2 2016
 Longest onshore horizontal lateral ever drilled in the country1
— Total measured depth of 27,048 feet drilled in 17.6 days with
completed lateral extension of ~18,500 feet
― 124 stages at 150 foot stage spacing completed at 5.3 stages per day
 Total D&C costs of ~$850 / lateral foot
 Reduces D&C cost per foot and improves well economic metrics
 F&D costs expected to drop ~20%-30% in the condensate area,
improving well returns by ~35-70% over shorter lateral type wells
 Lessons learned give Eclipse the ability to maximize lateral lengths on all
of its operated acreage
Eclipse’s Purple Hayes D&C cost/ft is significantly below peers,
while targeting the same EUR of 1.0 Bcfe/1,000 ft in the condensate area
Purple Hayes 1H Highlights
Enhancing Economics through Longer Laterals

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0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
0 100,000 200,000 300,000 400,000 500,000
Tubing Pressure (PSI)
Cumulative Gas (MCF)
0
100
200
300
400
500
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 10 20 30 40 50 60 70 80 90 100
BBL/MMcf
Mcf/d, PSI
Days On Production
Wellhead Gas Rate Tubing Pressure Condensate Yield
9
Purple Hayes 1H Update
 The Purple Hayes well has exceeded internal expectations
during its first 90 days of production
― Flat gas production
― Flat condensate yield
― Very shallow pressure decline
 Eclipse’s pressure managed production method is designed to
produce weekly pressure drawdowns of approximately 100 PSI
per week (in liquids-rich areas)
― The Purple Hayes well has averaged approximately 45 PSI
per week decrease over the first 90 days of production
 Tracer surveys to date have confirmed that the toe stages of the
well are contributing to production
 The Purple Hayes well offsets Eclipse’s Fritz Pad which has
been one of its best performing pads in the condensate area
― The Fritz wells have a projected EUR of approximately 0.83
Bcfe/1000’ lateral
 When comparing the Purple Hayes pressure drawdown to
Eclipse’s Fritz Pad, the Purple Hayes well appears to be
following a trend of shallower pressure decline which may
indicate a more effective completion and higher EUR per 1000 ft
of lateral
― 150’ stage lengths vs. 200’ stage lengths
― 100% slick water vs. 70% slick water
― Sand concentration 1,400 lbs/ft vs. 1,800 lbs/ft
Tubing Pressure vs. Cumulative Gas Production
Daily Rates

August2016_IR
0
5,000
10,000
15,000
0 500 1,000 1,500 2,000 2,500 3,000
Cumulative Production (MMCFE)
Days On Production
Historical Production
High Forecast ‐ 1.2 BCFE per 1,000 ft.
Mid Forecast ‐ 1.1 BCFE per 1,000 ft.
Low Forecast ‐ 0.9 BCFE per 1,000 ft.
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
0 6 12 18 24 30 36
Gas Rate (Mcf/d), Tubing Pressure (psi)
Months On Production
Gas Rate (Mcf/D)
High Forecast ‐ 1.2 BCFE per 1,000 ft.
Mid Forecast ‐ 1.1 BCFE per 1,000 ft.
Low Forecast ‐ 0.9 BCFE per 1,000 ft.
Flowing Tubing Pressure (psi)
Line Pressure = 360 psi
1 Year
Cumulative
4.7 BCFE
Flat Period
Cumulative
6.0 BCFE
8.5 BCFE
36 Month
Cumulative
9.8 BCFE
10
Purple Hayes 1H Update
Given the well results over the first 90 days, Eclipse believes the Purple Hayes well is trending towards its Mid to
High Forecast if production continues to remain flat and pressure drawdowns continue on current trends
Note: BT IRR’s shown based on Purple Hayes 1H actual well cost and $3.00/MMBtu gas and $60/Bbl oil, flat.
62% BT IRR
53% BT IRR
46% BT IRR
1.2 Bcfe produced to date
36% Gas
41% Condensate
23% NGL

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11
Pushing the Boundaries on Completion Design
 Optimized fluid chemistry within the Utica by performing benchmark testing on all frac chemicals
 100% slickwater design for high fracture complexity and conductivity
 Testing decreased stage spacing to maximize stimulated reservoir volume
 Effectively placing up to 3,000 pounds per foot with 100% slickwater system
 Changing frac water chemistry has significantly decreased water volumes by 20% per each frac stage
 Understanding the Utica formation has led to no coil tubing screen-outs in two years
 Using experienced service providers for a safe and efficient operation
 Experienced and technically driven operational team to maintain Utica leading efficiencies
Eclipse continues to push the boundaries of technical feasibility, while significantly reducing the cost structure
Pad Name
“Typical” Early
Time Well
Weekender Purple Hayes Borton Wheeler
Completion Date 2014 May 2015 March 2016 June 2016 July 2016
Stage Spacing 200-250 225 150 150 110
Sand Loading (lbs/ft) 1,400 1,400 1,400 2,000 2,400
Slickwater 30-50% 60% 100% 100% 100%

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12
Attractive Single Well Economics1
 Significant economic enhancement achieved through longer laterals
― Lower cost per foot
― Fewer pads constructed
― Less midstream infrastructure
1 See Appendix for detailed assumptions. Assumes ethane rejection with contractual 30% recovery.
2 Marcellus returns / locations shown for 10,000’ lateral.
3 Includes undeveloped leasehold within HBP’d units.
59%
96%
139%
49%
82%
119%
45%
76%
110%
15%
42%
75%
24%
47%
73%
37%
56%
78%
39%
56%
75%
41%
56%
72%
63%
93%
128%
$3.00 Gas, $60 Oil $3.50 Gas, $65 Oil $4.00 Gas, $70 Oil
Dry Gas
East
Dry Gas
Central
Dry Gas
West
Rich Gas
Condensate /
Rich Gas
Lean
Condensate
Rich
Condensate
Very Rich
Condensate
Marcellus
Net Undeveloped Acres3
12,080 15,320 16,710 6,510 11,730 17,600 3,390 6,750 12,810
Locations at 13,000'2
37 47 52 20 41 61 12 24 58
BT IRR by Type Curve Area (13,000’ Lateral Length)2

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13
Diversified Midstream Strategy
 Firm gathering, processing and fractionation without volume commitments
 ~355,000 MMBtu/d in non-recallable long term firm interstate gas
transportation contracts to price advantaged markets
 Firm NGL (propane and butane) contract in Mariner East II pipeline for
transport and sale at East Asia Index Prices (4Q16)
 Firm ethane sales contract with recently announced Shell cracker in
Pennsylvania provides Eclipse optionality for up to 100% of expected ethane
volumes
Blue Racer Processing and Fractionation (Berne and Natrium)
ET Rover
100,000 Dth/d –
Gulf
50,000 Dth/d ‐
Dawn
ET Rover
Term: 15 years
100,000 Dth/d – Gulf
(Expected In-service 2Q17)
50,000 Dth/d – Dawn
(Expected In-service 4Q17)
Columbia
Expected
In-service
in 4Q16
Term: 15
years
205,000
Dth/d
TCO Pool
Texas
Eastern
In-service
Term: 9.5
years
75,000
Dth/d
Gulf, M3,
Lebanon
Rockies Express / ANR South
In-service
Term: 17 months
50,000 Dth/d
ANR SE
Mariner
East II
Expected
In-service
in 4Q16
Significant
portion of
expected
propane
and butane
production
Shell Ethane Cracker
¹ Based on average of Q4 2015 and Q1 2016 average realized price before the effects of hedges; peers include AR, COG, EQT, GPOR, RICE, RRC, and SWN.
$2.19 $2.18
$2.11
$1.94
$1.79
$1.51 $1.51 $1.46
ECR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
Highlights
Last Two Quarters Average Realized Gas Price¹
Eclipse’s acreage is centered across a confluence of major interstate pipelines providing significant
in- and out-of-basin optionality

August2016_IR
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
May-2016 Aug-2016 Nov-2016 Feb-2017 May-2017
MMbtu/d
Columbia ‐
Texas Eastern ‐ ELA/WLA
Texas Eastern ‐ M3
Texas Eastern ‐ Lebanon Hub
Rex ‐ ANR ‐ SE
Firm Sales
14
Firm Gas Transportation Portfolio Sized for
Production Growth
Eclipse's Diverse Firm Gas Transportation Portfolio provides significant optionality to various end markets, with
appropriately sized positions to adequately protect future production
Minimal unutilized firm transportation
expense of < $2.0MM in 20171
2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17
Expected Gross
Operated Gas
Production
1 Based on 2017 guidance.
Recallable
Capacity
MMBtu/d
$(0.50)
$ 0.00
$ 0.50
Jan-14 Oct-14 Aug-15 Jun-16
Historical TCO Basis Differential

August2016_IR
‐
100.0
200.0
300.0
400.0
$‐
$1.00
$2.00
$3.00
$4.00
$5.00
2014 2015 2016e 2017e
Production (MMcfe/d)
$/Mcfe
LOE Production Taxes Transportation, Gathering & Processing Firm Transportation G&A Interest
15
Declining Cost Structure
Eclipse continues to reduce its costs structure and anticipates further per unit reductions
with recommencement in development activity
Reduced cash G&A from $45 million in 2014 to an annual run rate of $25 million by 2H16
Achieved 42%
reduction to
cash
operating
expenses /
Mcfe from
2014
Reductions in
2016
mitigated by
voluntarily
curtailing
production
~10%
continued
decline in per
unit expense
anticipated
with
resumption in
drilling
Expected
G&A to fall to
11% of total
expenses
Interest per
unit should
decline ~30%
G&A reduced
from 35% to
20% of total
expenses
G&A further
reduced to
15% of total
expenses
Operating Costs per Mcfe

August2016_IR
$237
$334
~$153
$125
$28
$‐
$50
$100
$150
$200
$250
$300
$350
$400
Pro Forma Cash Borrowing
Base
Outstanding
Letters of Credit
6.30.16
Liquidity
3Q‐4Q16 CapEx
$550
$510
12.31.15 6.30.16
16
Liquidity & Debt Reduction
 Q2 2016 liquidity of $334 million, pro forma for equity offering with net
proceeds of $123 million
 Conducted open market debt repurchases for ~$40 million of face amount at a
cost of 59.3% of face value
• Do not anticipate any further debt repurchases at current open market
prices
 Completed 3 non-core asset sales resulting in net cash proceeds of ~$14
million in first half 2016
 Plan to end 2016 with significant cash on hand and no incremental debt
 Eclipse is focused on maintaining a conservative balance sheet with strong liquidity to fund development of its world-class assets
 Strong pro forma liquidity with fully funded 2017 plan
Year to date, Eclipse
has reduced
outstanding debt by
~$40MM, resulting in
annual interest
savings of $3.5MM
1 Pro forma for equity offering net proceeds of $123 million
Highlights Senior Notes ($ MM)
Liquidity as of 6.30.16 ($ MM)1

August2016_IR
Natural Gas
63%
NGL
15%
Oil
22%
17
Overview of Eclipse’s Attractive Hedge Portfolio1
Summary of Current Hedges 2016 Pre-Hedged Revenues
1 See Appendix for slide detailing hedges.
2 Based on midpoint of the Company’s announced production guidance.
Natural Gas (MMBtu/d) Oil (Bbl/d)
$’s indicate Avg. Floor Price $’s indicate Avg. Floor Price
2016 Hedges2
 ~80% of natural gas production hedged at average floor price of $3.11/MMBtu
 ~60% of oil production hedged at average floor price of $53.84/Bbl
 ~50% of propane production hedged at average price of $0.456/Gal in 2016
2017 Hedges2
 ~80% of natural gas production hedged at average floor price of $2.84/MMBtu
 ~80% of oil production hedged at average floor price of $46.00/Bbl
2018 Hedges
 50,000 MMBtu/d of natural gas production hedged at average floor price of
$2.81/MMBtu
 Eclipse continues to actively hedge expected production to provide predictable cash flows and limit capital plan funding risk
 Recently added base load of 2018 natural gas collars with a $2.81 average floor
65,000 65,000 65,000 65,000
10,000 10,000 10,000 10,000
30,000 30,000 30,000 30,000
150,000 150,000 150,000 150,000
50,000 50,000 50,000 50,000
40,000 40,000 40,000 40,000
30,000 30,000 30,000 30,000
$3.11 $3.11 $3.11 $3.11
$2.84 $2.84 $2.84 $2.84
$2.81 $2.81 $2.81 $2.81
‐
40,000
80,000
120,000
160,000
200,000
1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18
283
850 850 850
2,000
333
1,000 1,000 1,000
4,000 4,000 4,000
2,000
$54.51
$53.52 $53.52 $53.52
$46.00 $46.00 $46.00
$46.00
‐
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

August2016_IR
19
Type Curve Areas with OGIPs

August2016_IR
20
Premier Southern Utica & Rich Marcellus Position1
1 Producing 30-day average sales rate; assumes ethane rejection with contractual 30% recovery
10 Eclipse Wells
IP Rate: 4.4 MMcfe/d
60% Liquids
Average Lateral: 6,049’
2 Eclipse Wells
64% Liquids
1 Eclipse Well
23% Liquids
Lateral: 8,853’
1 Eclipse Well
IP Rate: 18.6 MMcf/d
0% Liquids
Lateral: 5,850’
3 Eclipse Wells
0% Liquids
3 Eclipse Wells
0% Liquids
6 Eclipse Wells
62% Liquids
4 Eclipse Wells
55% Liquids
2 Eclipse Wells
0% Liquids
7 Eclipse Wells
0% Liquids
3 Eclipse Wells
63% Liquids
1 Eclipse Well
64% Liquids
Lateral: 18,544’
4 Eclipse Wells
61% Liquids
3 Eclipse Wells
62% Liquids
4 Eclipse Wells
59% Liquids

August2016_IR
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
MMbtu/d
Texas Eastern ‐ ELA/WLA
Texas Eastern ‐ M3
Texas Eastern ‐ Lebanon Hub
Rex ‐ ANR ‐ SE
Firm Sales
21
Firm Transportation and Sales Outlets
$ 0.50 $ 0.51 $ 0.56
$ 0.04 $ 0.05
$ 0.05
$ 0.54 $ 0.56
$ 0.61
2016 2017 2018
Demand Variable
MMBtu/d 2016 2017 2018 2019 +
North East
Texas Eastern - M3 37,500 37,500 37,500 37,500
Canada
Dawn - Canada 0 8,333 50,000 50,000
Premium Basin
Columbia - TCO Pool 34,167 205,000 205,000 205,000
Lebanon Hub 12,501 12,501 12,501 12,501
Gulf
Rover - Trunkline Z1A 0 75,000 100,000 100,000
Rex - ANR - SE 41,667 0 0 0
Texas Eastern - ELA/WLA 24,999 24,999 24,999 24,999
Total 150,833 363,333 430,000 430,000
MMBtu/d
Recallable
Capacity
2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19
Firm Transportation Costs ($/MMBtu) Annual Average Firm Transportation
Firm Commitments per MMBtu per day

August2016_IR
22
NGL Infrastructure
Edmonton
Markets
Midwest
Markets
Ontario
Markets
Northeast
Markets
South
Markets
Gulf
Markets
Marcus
HookStephen
City, VA
Rail Transport
Natrium
Plant
Mariner East I
Mariner East II (4Q16)
Shell
Cracker
 Q2 2016 avg. realized price of $13.60/Bbl and represents ~20% of total production
 Mariner East II contract to begin in Q4 2016
― Contract to market propane and butane using East Asia
Index benchmark
― Global propane prices have not weakened with the same magnitude as US
prices
 NGL prices should firm with growing number of outlets for NGL demand, export
capacity increasing through the second half of 2016, and with the migration
through the shoulder season
 Increasing diversification of ethane markets
― Current access to ATEX and Mariner East I
― Commitment to Shell cracker (FID announced 6/7/16)
Propane
38%
Ethane
37%
C5+
12%
Normal
Butane
7%
ISO Butane
6%
Propane
38%
Ethane
33%Normal
Butane
12%
ISO
Butane
9%
C5+
8%
Mount Belvieu Eclipse
Marketing by Region

August2016_IR
June 30, June 30,
($ in thousands) 2016 2015
Net Loss (73,011)$                         (41,970)$
   Depreciation, depletion & amortization 20,949                            60,641
   Exploration expense 17,444                            6,243
Rig  contract termination 1,292                               366
  Stock‐based compensation 2,226                               1,410
   Impairment of oil and gas properties ‐                                   ‐
   Accretion of asset retirement obligations 89                                    399
  Gain on deriative instruments 29,596                            3,523
   Net cash receipts on derivative instruments 12,880                            8,457
   Interest expense 12,439                            14,401
(Gain) loss of sale of assets (1,024)                             (5,553)
Gain on debt extinguishment (5,825)
Other income (expense) 2                                       2
   Income tax expense ‐                                   (16,412)
Adjusted EBITDAX 17,057$                          31,507$
For the Three Months Ended
23
Non-GAAP Reconciliations
1 Proved reserves based on estimates provided by Eclipse's independent engineering firm. PV-10 based on SEC pricing.
Future Net Cash Flows 300,059$           792,091$
Present Value of future net fash flows
Before income tax (pre‐tax PV‐10) 212,866              509,389
Income Taxes ‐                       (178,732)
After income tax (Standardized Measure) 212,866$           330,657$
Year ended December 31,
Adjusted EBITDAX
Adjusted Revenue PV-101
June 30, June 30,
Total Revenues 47,066$                          74,453$
Net cash receipts (payments) on derivative instruments 12,880                            8,457
Brokered natural gas and marketing (1,165)                             (9,469)
Adjusted revenue 58,781$                          73,441$
Three Months Ended

August2016_IR
24
Financial and Operational Summary
FY 2014 1Q15 2Q15 3Q15 4Q15 FY 2015 1Q16 2Q16 3Q16 Guidance FY 2016 Guidance
Production
Natural Gas (Mcf/d) 54,137 109,614 114,131 145,787 171,891 135,555 150,410 168,115
NGL (MBbls/d) 1,468 4,383 7,502 7,209 7,716 6,713 5,645 7,537
Oil (MBbls/d) 1,630 3,939 6,584 6,028 4,808 5,344 2,805 3,793
Total Daily Equivalent (MMcfe/d) 72.7 159.6 198.6 225.2 247.0 207.9 201.1 236.1 217.5 227.5
Total Equivalent (MMcfe) 26,546 14,360 18,077 20,719 22,727 75,882 18,301 21,485
Natural Gas Realized Price ($/Mcf)
Average NYMEX Henry Hub ($/MMBtu) 4.26$ 2.90$ 2.74$ 2.76$ 2.10$ 2.57$ 2.02$ 2.16$
Differential to Henry Hub (0.75) (0.51) (0.03) 0.10 0.22 0.05 0.03 (0.60) (0.58)$ (0.30)$
Realized Price before Firm Transportation 3.51$ 2.39$ 2.71$ 2.86$ 2.32$ 2.62$ 2.05$ 1.56$
Firm Transportation (0.07) (0.41) (0.30) (0.33) - 0.44 0.45 (0.38)$ (0.40)$
Realized Price after Firm Transportation 3.51$ 2.32$ 2.30$ 2.56$ 1.99$ 2.31$ 1.61$ 1.12$
Impact of Cash Settled Derivatives 0.01 0.61 0.75 0.64 0.66 0.65 0.88 0.75
Realized Price after Cash Settled Derivatives 3.52$ 3.00$ 3.46$ 3.50$ 2.98$ 3.27$ 2.93$ 2.31$
Realized Price after Hedging and Firm Transportation 3.52$ 2.92$ 3.05$ 3.20$ 2.65$ 2.95$ 2.49$ 1.86$
NGL Realized Price ($/Bbl)
Average NYMEX WTI ($/Bbl) 92.91$ 48.49$ 57.67$ 46.81$ 47.13$ 49.33$ 33.67$ 46.21$
% of WTI 0% 0% 0% 9% 35% 25% 38% 29% 26% 28%
Oil Realized Price ($/Bbl)
Average NYMEX WTI ($/Bbl) 92.91$ 48.49$ 57.67$ 46.81$ 47.13$ 49.33$ 33.67$ 46.21$
Differential to WTI (13.37) (12.83) (12.19) (9.29) (9.75) (10.95) (10.46) (9.47) (10.00)$ (10.50)$
Realized Price before Hedging 79.54$ 35.66$ 45.48$ 37.52$ 37.38$ 38.38$ 23.21$ 36.74$
Impact of Cash Settled Derivatives - 0.00 1.16 1.46 0.87 2.54 23.21 4.64
Realized Price after Cash Settled Derivatives 79.54$ 35.66$ 46.64$ 38.98$ 38.25$ 40.92$ 46.42$ 41.38$
Operating expenses per Mcfe ($/Mcfe)
Lease operating 0.32$ 0.23$ 0.20$ 0.16$ 0.17$ 0.18$ 0.15$ 0.10$
Transportation, gathering and compression 0.68$ 0.87$ 1.25$ 1.10$ 1.23$ 1.13$ 1.26$ 1.32$
Production and ad valorem taxes 0.27$ 0.15$ 0.17$ 0.15$ 0.14$ 0.15$ (0.12)$ 0.10$
Unit Operating Costs 1.27$ 1.25$ 1.62$ 1.41$ 1.54$ 1.46$ 1.29$ 1.52$
OpEx excluding Firm Transportation 1.27$ 0.97$ 1.38$ 1.22$ 1.31$ 1.26$ 0.95$ 1.20$ 1.18$ 1.18$
Depreciation, depletion and amortization 3.36$ 2.95$ 3.35$ 3.24$ 3.28$ 3.23$ 0.83$ 0.98$
General and administrative 1.71$ 0.83$ 0.70$ 0.66$ 0.35$ 0.61$ 0.54$ 0.48$
Revenues ($ thousands)
Natural gas sales 69,450$ 23,609$ 28,715$ 38,360$ 36,617$ 129,561$ 28,041$ 23,888$
NGL sales 21,048$ 7,564$ 9,563$ 2,757$ 10,293$ 30,177$ 6,522$ 9,331$
Oil sales 47,318$ 12,641$ 27,246$ 20,811$ 14,165$ 74,863$ 5,925$ 12,682$
Oil and natural gas sales 137,816$ 43,814$ 64,984$ 61,928$ 61,075$ 234,601$ 40,488$ 45,901$
Brokered natural gas and marketing revenue 9,469$ 9,244$ 4,807$ 20,720$ 9,118$ 1,165$
Total revenues excluding Hedging 137,816$ 43,814$ 74,453$ 71,172$ 65,882$ 255,321$ 49,606$ 47,066$
Net of Cash Settled Derivatives 179$ 5,965$ 8,457$ 9,332$ 13,320$ 37,074$ 18,378$ 12,880$
Total revenues after Hedging 137,995$ 49,779$ 82,910$ 80,504$ 79,202$ 292,395$ 67,984$ 59,946$
Expenses ($ thousands)
Lease operating 8,518$ 3,346$ 3,589$ 3,212$ 3,757$ 13,904$ 2,677$ 2,248$
Transportation, gathering and compression 18,114$ 12,451$ 22,634$ 22,811$ 27,950$ 85,846$ 23,137$ 28,254$
Production and ad valorem taxes 7,084$ 2,100$ 3,078$ 3,175$ 3,268$ 11,621$ (2,284)$ 2,051$
Total Lifting Costs 33,716$ 17,897$ 29,301$ 29,198$ 34,975$ 111,372$ 23,530$ 32,553$
Cash general and administrative 45,136$ 18,827$ 11,306$ 12,473$ 6,798$ 41,774$ 9,800$ 8,176$ 6,500$ 30,000$
Brokered natural gas and marketing expense 10,795$ 9,262$ 6,116$ 26,173$ 9,402$ 2,160$
Adjusted EBITDAX 62,426$ 20,686$ 31,507$ 29,571$ 31,313$ 113,077$ 25,251$ 17,057$
Rig termination 3,283$ 7,056$ 366$ 174$ 2,075$ 9,672$ 2,663$ 1,292$
Depreciation, depletion and amortization 89,218$ 42,432$ 60,641$ 67,172$ 74,505$ 244,750$ 15,113$ 20,949$
Exploration 21,186$ 13,453$ 6,243$ 3,244$ 93,271$ 116,211$ 15,656$ 17,444$
Impairment of oil and gas properties 34,855$ -$ -$ -$ 691,334$ 691,334$ 17,665$ -$
Net Income (Loss) (183,176)$ (34,103)$ (41,970)$ (81,468)$ (813,869)$ (971,410)$ (40,687)$ (73,011)$
Capital Expenditures ($ millions)
Drilling and Completion 644.5$ 88.1$ 106.9$ 48.3$ 40.3$ 283.6$ 12.7$ 20.7$
Midstream 33.3$ 12.4$ (28.3)$ 0.2$ (2.4)$ (18.1)$ 0.9$ 1.4$
Land 132.0$ 21.3$ 9.5$ 3.2$ 7.2$ 41.2$ 3.8$ 2.6$
Other 4.1$ 2.1$ 0.6$ 0.0$ 0.1$ 2.8$ 0.5$ 0.0$
Total 813.8$ 123.9$ 88.7$ 51.7$ 45.1$ 309.5$ 17.9$ 24.6$ 196.0$

August2016_IR
25
Hedging Summary1
1 As of July 15, 2016
Natural Gas Hedges
Volume
(MMBtu/d)
Production Period
Weighted Average
Price ($/MMBtu)
Natural Gas Swaps
65,000 Current – December 2016 $3.28
10,000 January 2017 – December 2017 $2.98
Natural Gas Call/Put Options
Floor sold 16,800 Current – December 2016 $2.75
Ceiling Sold 40,000 January 2018 ‐ December 2018 $3.75
Natural Gas – Collars
Floor Purchased (Put) 30,000 Current – December 2017 $3.00
Ceiling Sold (Call) 30,000 Current – December 2017 $3.50
Floor Purchased (Put) 100,000 January 2017 – December 2017 $2.80
Ceiling Sold (Call) 100,000 January 2017 – December 2017 $3.17
Natural Gas – Three‐Way Collars
Floor Purchased (Put) 40,000 Current – December 2016 $2.90
Ceiling Sold (Call) 20,000 Current – December 2016 $3.24
Floor Sold (Put) 40,000 Current – December 2016 $2.35
Floor Sold (Put) 30,000 January 2017 – December 2017 $2.25
Oil Hedges
Volume
(Bbl/d)
Production Period
Weighted Average
Price ($/Bbl)
Oil Swap
850 Current – December 2016 $45.55
Oil – Three‐Way Collar
Floor purchased (put) 1,000 Current ‐ December 2016 $60.00
Ceiling sold (call) 1,000 Current ‐ December 2016 $70.10
Floor sold (put) 1,000 Current ‐ December 2016 $45.00
Floor purchased (put) 2,000 January 2017 ‐ December 2017 $46.00
Ceiling sold (call) 2,000 January 2017 ‐ December 2017 $60.00
Floor sold (put) 2,000 January 2017 ‐ December 2017 $38.00
Floor purchased (put) 2,000 January 2017 ‐ September 2017 $46.00
Ceiling sold (call) 2,000 January 2017 ‐ September 2017 $59.50
Floor sold (put) 2,000 January 2017 ‐ September 2017 $38.00
Oil Call/Put Options
Ceiling Sold 1,000 January 2018 ‐ December 2018 $50.00
NGL Hedges
Volume
(Gal/d)
Production Period
Weighted Average
Price ($/Gal)
Swaps
Propane 42,000 Current ‐ December 2016 $0.46
Propane 10,500 July 2016 ‐ September 2016 $0.46

August2016_IR
26
Favorable Lease Expirations
1 As of May 31, 2016.
0.2% 0.8% 1.1%
5.5%3.8%
17.8%
8.5%
8.0%
4.0%
18.6%
9.6%
13.4%
11.8%
42.5%
2016 2017 2018 2019+ Annual Delay Rentals Fee/HBP
Expiring Acres Expiring Acres with Extension Options
Utica Core Area Leasehold Expirations1
Eclipse is aggressively amending its leases whose primary term is set to expire in 2017 and 2018 to replace the
five year lump sum extension option with optional annual payments over 5-8 years

August2016_IR
27
Proved Reserves Summary1
78.5
355.8 348.8
0.0
100.0
200.0
300.0
400.0
4Q13 4Q14 4Q15
Reserves(Bcfe)
PDP PNP/PBP PUD
Net Oil
(MBbls)
Net NGL
(MBbls)
Net Gas
(MMcf)
Net Total
(MMcfe)
Net PV-10
($M)
SEC Pricing
PDP 4,137 7,142 208,526 276,199 205,956
PNP/PBP 102 104 1,008 2,244 1,941
PUD 454 513 64,527 70,329 4,968
Total Proved 4,693 7,759 274,061 348,772 212,865
Eclipse has been able to achieve significant growth in proved reserves and proved developed
reserves since the commencement of its active drilling program in late 2013
Total Proved Reserves
1 Proved reserves based on estimates provided by Eclipse's independent engineering firm as of December 31, 2015.

August2016_IR
Dry Gas East
Dry Gas
Central Dry Gas West Rich Gas
Condensate /
Rich Gas
Lean
Condensate
Rich
Condensate
Very Rich
Condensate Marcellus
Gas IP Rate (Mcf/d) 25,200 22,500 21,000 16,500 10,500 4,950 3,600 2,250 8,250
Initial Cond. Yield (Bbl/MMcf) N/A N/A N/A 15 60 150 200 300 100
EUR (w / processing) (Bcfe)1 32.21 29.35 27.36 27.39 21.73 13.94 13.22 10.83 23.89
BT IRR ($3.50 Gas, $60.00 Oil, NGL 35% of WTI) 107% 91% 84% 42% 45% 53% 52% 52% 106%
Well Cost ($MM) $12.64 $12.64 $12.64 $11.25 $11.25 $11.25 $11.25 $11.25 $9.68
Breakeven Gas Price at $60.00 Oil ($/Dth)2 $2.10 $2.17 $2.21 $2.75 $2.30 $0.85 $0.00 $0.00 $0.36
Breakeven Oil Price at $3.50 Gas ($/Bbl)2 N/A N/A N/A $31.45 $35.80 $38.70 $38.80 $39.30 $27.10
EUR, Bcfe/1000' 2.1 2.0 1.8 1.8 1.4 0.9 0.9 0.7 1.6
Gas IP Rate (Mcf/d) 21,840 19,500 18,200 14,300 9,100 4,290 3,120 1,950 7,150
Well Cost ($MM) $11.53 $11.53 $11.53 $10.39 $10.39 $10.39 $10.39 $10.39 $8.86
EUR, Bcfe/1000' 2.1 1.9 1.8 1.8 1.4 0.9 0.9 0.7 1.6
Gas IP Rate (Mcf/d) 16,800 15,000 14,000 11,000 7,000 3,300 2,400 1,500 5,500
Well Cost ($MM) $10.12 $10.12 $10.12 $8.93 $8.93 $8.93 $8.93 $8.93 $7.44
EUR, Bcfe/1000' 2.1 1.9 1.8 1.8 1.4 0.9 0.9 0.7 1.6
15,000'Lateral13,000'Lateral10,000'Lateral
28
Type Curve Summary
1 Assumes ethane rejection with contractual 30% recovery.
2 Breakeven is defined as PV(10) > $0.00.

August2016_IR
29
Type Curve & Cost Assumptions Details
1 Represents 24-hour rate well-head gas production.
2 Assumes ethane rejection with contractual 30% recovery.
3 Includes transportation costs and basis differentials
Dry Gas
East
Dry Gas
Central
Dry Gas
West
Rich Gas
Condensate /
Rich Gas
Lean
Condensate
Rich
Condensate
Very Rich
Condensate
Marcellus
Identified Locations 37                      47                      52                      20                      41                      61                      12                      24                      45
Type Curve Assumptions
Lateral Length (ft) 13,000             13,000             13,000             13,000             13,000             13,000             13,000             13,000             10,000
Initial Gas Production Period (Mcf/d)
1
21,800             19,500           18,200           14,300           9,100               4,300              3,100              2,000              5,500
Flat Period (months) 8                        9                        9                        9                        9                        12                      8                        24                      4
Shrink N/A N/A N/A 90.0% 86.2% 85.2% 85.1% 84.4% 81%
NGL Yield (Bbls/MMcf) N/A N/A N/A 60.0                  80.4                  87.7                  91.5                  93.0                  125.0
Residue BTU 1,025                1,025                1,050                1,200                1,265                1,287                1,300                1,300                1,400
Post‐Processed EUR (Bcfe/1,000')
2
2.1                    1.9                  1.8                  1.8                  1.4                  0.9                  0.9                  0.7                  1.6
Post‐Processed EUR (Bcfe)
2
27.8                  25.3                23.6                23.6                18.7                 12.0                11.4                9.3                  15.8
Oil (MBbl) N/A N/A N/A 65                      215                   514                   605                   629                   316
NGL (MBbl) N/A N/A N/A 1,104                1,042                568                   507                   368                   1,114
Residue Gas (MMcf) 27,784             25,306             23,580             16,566             11,171             5,516                4,715                3,343                7,220
Post‐Processed % Gas 100% 100% 100% 70% 60% 46% 41% 36% 46%
Differentials
3
Gas ($/MMBtu off NYMEX) ($0.65) ($0.65) ($0.65) ($0.65) ($0.65) ($0.65) ($0.65) ($0.65) ($0.65)
Condensate ($/Bbl off WTI) ($10.00) ($10.00) ($10.00) ($10.00) ($10.00) ($10.00) ($10.00) ($10.00) ($10.00)
NGL (% WTI) 35% 35% 35% 35% 35% 35% 35% 35% 35%
Operating Expenses
Operating Expenses ($/well per month) $9,400 $9,400 $9,400 $6,400 $6,400 $6,400 $6,400 $6,400 $6,400
Gathering & Compression ($/Mcf) $0.28 $0.28 $0.28 $0.59 $0.59 $0.59 $0.59 $0.59 $0.59
Processing ($/Mcf) $0.00 $0.00 $0.00 $1.05 $1.05 $1.05 $1.05 $1.05 $1.05
Production Tax 6% 6% 6% 6% 6% 6% 6% 6% 6%
Well Cost Assumptions
Well Cost ($ MM) 11.5$                11.5$                11.5$                10.4$                10.4$                10.4$                10.4$                10.4$                7.4$
Well Cost per foot ($/ft) 877$                 877$                 877$                 800$                 800$                 800$                 800$                 800$                 744$

August2016_IR
30
Net Undeveloped Locations
1 Includes undeveloped leasehold within HBP’d units.
Dry Gas
East
Dry Gas
Central
Dry Gas
West
Rich Gas
Condensate /
Rich Gas
Lean
Condensate
Rich
Condensate
Very Rich
Condensate
Marcellus TOTAL
Net Undeveloped Acres(1)
12,080 15,320 16,710 6,510 11,730 17,600 3,390 6,750 12,810 102,900
Inter-Lateral Spacing 850 850 850 850 750 750 750 750 750
Risk Factor 20% 20% 20% 20% 20% 20% 20% 20% 20%
48 61 67 26 53 79 15 30 58 437
37 47 52 20 41 61 12 24 45 339
32 41 45 17 36 53 10 20 39 294
Risked Net
Undeveloped
Locations
10,000' Lateral Length
Risked Net Undeveloped Locations are calculated by taking Eclipse’s total net undeveloped acreage and multiplying such
amount by a risk factor (to account for inefficient unitization) which is then divided by Eclipse’s expected well spacing

August2016_IR
31
Dry Gas East¹
1 Assumes 13,000’ lateral. CapEx and Lat. Length IRR Sensitivities assume base commodity pricing of $3.50 gas, $60.00 oil and 35% WTI NGL pricing.
Eclipse Acreage Area
0%
20%
40%
60%
80%
100%
120%
140%
160%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 20% 40% 60% 80% 100% 120% 140%
GasPrice($/Dth)
BT IRR
0%
20%
40%
60%
80%
100%
120%
6,000 8,000 10,000 12,000 14,000 16,000
IRR
Lateral Length (ft)
Well Characteristics
Bcfe / 1000' 2.1
Inter‐Lateral Spacing (ft) 850
Lateral Length (ft) 13,000
Gross EUR (MMcfe, Post‐Processing) 27,784
Type Curve
Exponential Phase
Gas IP Rate (MMcf/d) 21.8
Initial Decline (%) 0%
Months 8
Hyperbolic Phase
B Factor 1.20
Terminal Decline (%) 6%
Liquids
Initial Cond. Yield (Bbl/MMcf) N/A
NGL Yield (Bbl/MMcf) N/A
Drilling And Completion
D&C Cost ($'000/well) 11,533
Type Curve Assumptions Map Lateral Length IRR Sensitivity
Capex IRR Sensitivity Commodity Price IRR Sensitivity

August2016_IR
32
Dry Gas Central¹
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 20% 40% 60% 80% 100% 120%
GasPrice($/Dth)
BT IRR
0%
20%
40%
60%
80%
100%
120%
140%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
6,000 8,000 10,000 12,000 14,000 16,000
BTIRR
Lateral Length (ft)
Bcfe / 1000' 1.9
Type Curve
Exponential Phase
Months 9
Hyperbolic Phase
B Factor 1.20
Liquids
D&C Cost ($'000/well) 11,533

August2016_IR
33
Dry Gas West¹
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
6,000 8,000 10,00012,00014,00016,000
BTIRR
Lateral Length (ft)
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 20% 40% 60% 80% 100% 120%
GasPrice($/Dth)
BT IRR
0%
20%
40%
60%
80%
100%
120%
140%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
Bcfe / 1000' 1.8
Type Curve
Exponential Phase
Months 9
Hyperbolic Phase
B Factor 1.20
Liquids
D&C Cost ($'000/well) 11,533

August2016_IR
0%
10%
20%
30%
40%
50%
60%
70%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
34
Rich Gas¹
$35
$45
$55
$65
$75
$85
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 10% 20% 30% 40% 50% 60% 70%
OilPrice($/Bbl)
GasPrice($/Dth)
BT IRR
Gas Sensitivity at $60.00 Oil Oil Sensitivity at $3.50 Gas
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
6,000 8,000 10,000 12,000 14,000 16,000
BTIRR
Lateral Length (ft)
Bcfe / 1000' 1.8
Type Curve
Exponential Phase
Months 9
Hyperbolic Phase
B Factor 1.20
Liquids
Initial Cond. Yield (Bbl/MMcf) 15
NGL Yield (Bbl/MMcf) 60.0
D&C Cost ($'000/well) 10,389

August2016_IR
35
Condensate / Rich Gas¹
$35.00
$45.00
$55.00
$65.00
$75.00
$85.00
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 10% 20% 30% 40% 50% 60% 70% 80%
GasPrice($/Dth)
BT IRR
0%
10%
20%
30%
40%
50%
60%
70%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
6,000 8,000 10,000 12,000 14,000 16,000
BTIRR
Lateral Length (ft)
Bcfe / 1000' 1.4
Type Curve
Exponential Phase
Months 9
Hyperbolic Phase
B Factor 1.25
Liquids
D&C Cost ($'000/well) 10,389

August2016_IR
36
Lean Condensate¹
$35
$45
$55
$65
$75
$85
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%100%
OilPrice($/Bbl)
GasPrice($/Dth)
BT IRR
0%
10%
20%
30%
40%
50%
60%
70%
80%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
55%
60%
6,000 8,000 10,000 12,000 14,000 16,000
BTIRR
Lateral Length (ft)
Bcfe / 1000' 0.9
Type Curve
Exponential Phase
Months 12
Hyperbolic Phase
B Factor 1.25
Liquids
D&C Cost ($'000/well) 10,389

August2016_IR
37
Rich Condensate¹
0%
10%
20%
30%
40%
50%
60%
6,000 8,000 10,000 12,000 14,000 16,000
BTIRR
Lateral Length (ft)
$35
$45
$55
$65
$75
$85
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%100%
OilPrice($/Bbl)
GasPrice($/Dth)
BT IRR
0%
10%
20%
30%
40%
50%
60%
70%
80%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
Bcfe / 1000' 0.9
Type Curve
Exponential Phase
Months 8
Hyperbolic Phase
B Factor 1.25
Liquids
D&C Cost ($'000/well) 10,389

August2016_IR
38
Very Rich Condensate¹
$35
$45
$55
$65
$75
$85
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%100%
OilPrice($/Bbl)
GasPrice($/Dth)
BT IRR
0%
10%
20%
30%
40%
50%
60%
70%
80%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
55%
6,000 11,000 16,000
BTIRR
Lateral Length (ft)
Bcfe / 1000' 0.7
Type Curve
Exponential Phase
Months 24
Hyperbolic Phase
B Factor 1.25
Liquids
D&C Cost ($'000/well) 10,389

August2016_IR
39
Marcellus¹
Eclipse Acreage
Area
0%
20%
40%
60%
80%
100%
120%
6,000 8,000 10,000 12,000 14,000 16,000
BTIRR
Lateral Length (ft)
$35
$45
$55
$65
$75
$85
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
0% 20% 40% 60% 80% 100%120%140%160%180%
OilPrice($/Bbl)
GasPrice($/Dth)
BT IRR
0%
20%
40%
60%
80%
100%
120%
140%
-25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25%
BTIRR
Capex Change
Bcfe / 1000' 1.6
Type Curve
Exponential Phase
Months 4
Hyperbolic Phase
B Factor 1.40
Liquids
D&C Cost ($'000/well) 7,443

August 2016 corporate_presentation_final Eclipse resources

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August 2016 corporate_presentation_final Eclipse resources