NYSE|ECR

Year-End 2014:Financial Review &Operational UpdateMarch 5, 2015

2

Year-End 2014 Earnings Call

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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Year-End 2014 Earnings Call

2014 Accomplishments

Grew average annual production by ~1,600% from 4.5 MMcfe/d in 2013 to 131 MMcfe/d in 2014

Grew adjusted net production ~1,200% to 131 MMcfe/d during the 4th quarter 2014 from 10 MMcfe/d during 4th quarter 2013

Turned 28 gross operated wells to sales at an average of 11 days ahead of schedule Grew proved reserves by 353% from 78.5 Bcfe to 355.8 Bcfe

1. Revolver was increased from $100MM to $125MM subsequent to year-end

Production & Reserve Growth

Operational Achievements

Financial Highlights

Completed one of the largest oil and gas initial public offerings of the year raising ~$818 million in gross proceeds

Established senior secured revolving credit facility, increasing borrowing capacity from $25 million to $125 million(1)

Entered into a private placement offering raising ~$440 million in gross proceeds

Spud 57 gross operated wells vs. plan of 40 gross operated wells Drilled 59 gross operated wells to TD in line with plan Increased average stages per day by 67% from 3 stages per day to 5 stages per day Completed 36 gross operated wells vs. plan of 44 gross operated wells with 15 wells

delayed due to the decline in commodity prices Reduced drilling times by 36% from IPO plan of 25 days to 16 days (normalized for 6,000’

lateral) Reduced average well costs by 55% year over year

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Year-End 2014 Earnings Call

2015 Strategy Update

Raised $434 million of net proceeds in private placement Expanded borrowing base to $125 million(1)

– Pro forma for both actions, liquidity at Dec 31, 2014 was ~$600MM

Joint venture process underway(2)

– JV to accelerate drilling activity without negative impact on liquidity and potentially provide opportunistic acquisition capital

1. Revolver was increased from $100MM to $125MM subsequent to year-end2. There can be no assurance that Eclipse Resources will be successful in closing such a transaction or the terms or timing of any such transaction

Eclipse will focus on preserving liquidity in the current market while still projecting over 100% year over year production growth

OperationalActions

FinancialActions

Reduce operated rig count to one rig– Active in the our Utica Shale Dry Gas area

Defer completions on 19 net wells to date in the liquids portion of the Utica Shale to date

Focus on operational efficiencies and service cost reductions– Significant efficiencies already achieved; rapid cost reductions in progress– Expected D&C costs down 12% currently with further 12% reduction expected in

the near term

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Year-End 2014 Earnings Call

Developing Value & Improving Efficiencies

Proved Reserves (Bcfe)(2)

Eclipse continues to convert unproved assets into proved reserves, while its drilling plan generates superior growth

1. Fourth quarter 2014 represents adjusted net production2. As of December 31, 2014; proved reserves based on estimates provided by Eclipse Resources’ independent engineering firm

Proved PV-10 ($ MM)(2)Net Production (MMcfe/d)(1)

Average Gross Lateral Feet per Well Average Days Spud to Rig Release

78

356

-

100

200

300

400

Q4-13 Q4-14

161

509

-

100

200

300

400

500

600

Q4-13 Q4-14

12.9

137.8

-

20.0

40.0

60.0

80.0

100.0

120.0

140.0

Q4-13 Q4-14

Revenue ($ MM)

49.8

19.0

-

10

20

30

40

50

60

Q1-14 Q4-14

10

131

-

25

50

75

100

125

150

Q4-13 Q4-14

5,996

7,173

-

2,000

4,000

6,000

8,000

10,000

Q4-13 Q4-14

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Year-End 2014 Earnings Call

-

30

60

90

120

150

Q1-14 Q2-14 Q3-14 Q4-14

Op Non-Op Full Year Guidance - Midpoint 2014 Average

2014 Average Daily Production (MMcfe/d)

(2)

Operated Producing Utica Wells

1. Assumes ethane rejection with contractual 30% recovery2. Adjusted net production

1011

9

86

7 5

1

423

Map ID

Operated Unit Name

Wells in Unit

Avg. Completed Lat Length

Type Curve Area

Turn toSales

Month

Producing 30-Day Avg Sales Rate/Well(1)

(MMcfe/d) % Gas % NGL % Oil

1 Tippens 1 5,850 Dry Gas Dec-13 18.6 100% 0% 0%

2 Herrick A 1 5,761 Dry Gas Jun-14 13.5 100% 0% 0%

3 Herrick B 1 6,380 Dry Gas Jun-14 10.8 100% 0% 0%

4 Herrick C 1 6,232 Dry Gas Jun-14 14.5 100% 0% 0%

5 Shroyer 2 7,422 Dry Gas Aug-14 23.5 100% 0% 0%

6 Mizer 5 5,923 Condensate Aug-14 5.5 40% 24% 35%

7 Duane Weisend 1 8,853 Rich Gas Sep-14 13.8 77% 23% 0%

8 Mizer Farms 5 6,176 Condensate Sep-14 3.4 39% 24% 37%

9 Fritz 3 7,394 Condensate Nov-14 4.5 37% 23% 40%

10 Hayes 4 6,298 Condensate Nov-14 3.7 39% 24% 38%

11 Pora 4 7,797 Condensate Dec-14 4.2 41% 26% 33%

Total/Average 28 6,678 7.4

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Year-End 2014 Earnings Call

13.7

25.7

5.8

1.0

18.0 1.0

19.31.6

5.8

0

10

20

30

40

50

60

9/30/2013 3/1/2015Producing DrillingAwaiting Completion/ Completing Deferred CompletionsAwaiting Turn To Sales

Operated Wells in Progress

1. As of March 1, 2015

Eclipse has elected to defer completions on 765 stages across 25 Utica wells (19.3 net) in the company’s Condensate type curve window to date

Operated Wells in Progress(1)Operated Net Well Summary

• At strip pricing, achieving Further Cost Improvements will increase the Condensate type curve IRR by ~5.6 percentage points• At our 2015 Budget AFE, increasing oil price $5/bbl increases the Condensate type curve IRR by ~4.1 percentage points

Deferred Completions

Waiting on Pipeline

Drilling

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Year-End 2014 Earnings Call

0.7 0.5 0.5

3.9 3.1

2.7

4.2

4.1

3.5

0.7

0.7

0.7

9.5

8.4

7.4

-

2.0

4.0

6.0

8.0

10.0

12.0

2014AFE

2015Budget AFE

Further CostImprovements

Construction Drilling Completions Facilities(2)

0.7 0.5 0.4

4.6

3.6 3.3

4.5

4.3 3.8

0.7

0.7

0.7

10.5

9.1

8.2

-

2.0

4.0

6.0

8.0

10.0

12.0

2014AFE

2015Budget AFE

Further CostImprovements

Construction Drilling Completions Facilities(2)

Type Curve Well Cost

Wet Gas ($ MM)(1) Dry Gas ($ MM)(1)

1. Normalized to a 6000’ lateral2. Drilling may incur an additional $0.75MM for a pilot hole and $0.4MM for a coal void if encountered

Reductions in service costs should significantly enhance returns in this pricing environment

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Year-End 2014 Earnings Call

$2.45$2.72

-

0.50

1.00

1.50

2.00

2.50

3.00

Summer 2015 -Yearend

2016

20%

40%

22%

18%

Marketing Considerations & Impact

1. After transportation expense, pricing as of 3/3/2015

Rex and TETCO connections now in place and selling gas daily into both systems Flowing into firm capacity starting April 2015 ~100% of produced gas moving to firm transportation/sales arrangements as firm comes

on lineMidwest & Gulf Coast Capacity

Uplift ($/Mcf)(1)Realized Netback for Midwest

& Gulf Coast ($/Mcf)(1)

Access to Gulf Coast and Midwest markets expected to provide ~$0.50/Mcf of uplift after transportation expense relative to Dom South in 2015 and ~$0.45/Mcf in 2016(1)

Firm Transportation and Production (MMBtu/d)Start Date Term Volume (Dth/d) Market

Firm Sales Nov-14 Various Up to 95,000 Dominion South / TETCO M2TETCO Apr-15 9.5 years 100,000 Gulf Coast, Midwest & M3Rockies Express Jun-15 17 months 50,000 Gulf CoastTCO Nov-16 15 years 205,000 TCO PoolEnergy Transfer Dec-16 15 years 100,000 Gulf CoastEnergy Transfer Jul-17 15 years 50,000 Dawn Hub

Remainder 2015 Sales Markets

85%

15%

Q1 Sales Markets

$0.51$0.48

-

0.10

0.20

0.30

0.40

0.50

0.60

Summer 2015 -Yearend

2016

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Year-End 2014 Earnings Call

Revenues & EBITDAX

1. Includes cash settled derivatives

Adjusted Revenue ($ MM)(1)

EBITDAX ($ MM)

138.0

-

25

50

75

100

125

150

2014

62.4

-

10

20

30

40

50

60

70

2014

Q4-14 2014

Average Net Price ($/Mcfe)Avg / Mcfe Price, as reported 4.61$ 5.20$

Plus Hedges (0.19) (0.01) Realized Price 4.42$ 5.19$

Natural Gas ($/Mcf)Avg Henry Hub Price 3.78$ 4.26$

Less Differential (0.41) (0.75) Realized Price 3.37$ 3.51$

Oil ($/Bbl)Avg WTI Price 73.21$ 92.91$

Less Differential (9.72) (13.37) Realized Price 63.49$ 79.54$

NGL ($/Bbl)% WTI 41% 42%

Realized Price 30.32$ 39.27$

13.1

25.9

-

5

10

15

20

25

30

3Q-14 Q4-14

36.3

52.6

-

10

20

30

40

50

60

3Q-14 Q4-14

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Year-End 2014 Earnings Call

$1.45

$1.27

$-

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$0

$5

$10

$15

$20

$25

$30

$35

$40

2013 2014

$/M

cfe$0.88

$1.65

$1.40

$1.17

$-

$0.25

$0.50

$0.75

$1.00

$1.25

$1.50

$1.75

$0

$2

$4

$6

$8

$10

$12

$14

$16

1Q14 2Q14 3Q14 4Q14$/

Mcf

e

Operating Expenses

Operating Expenses ($ MM)(1)

1. Excluding DD&A and G&A

The rapid production growth during the second half of the year was the primary driver of the ~30% reduction in per unit operating expense since the company’s IPO in June 2014

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Year-End 2014 Earnings Call

Strong Financial PositionThe closing of Eclipse Resources’ private placement equity offering in January 2015 added considerable cash to the company’s balance sheet and positions the company to weather commodity price volatility throughout the coming year

Liquidity ($ MM)

434

25

141

575 600

-

100

200

300

400

500

600

700

12/31/2014 PrivatePlacement

Pro Forma12/31/2014

Borrowing BaseRedetermination

AdjustedPro Forma 12/31/14

Cash & Cash Equivalents Available Borrowing Base

APPENDIX

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Year-End 2014 Earnings Call

Hedging Summary

Natural Gas Hedges Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu)

Natural Gas Swaps65,490 Current – December 2015 $3.79425,000 January 2016 – December 2016 $3.660

Natural Gas Put OptionsFloor sold 16,800 Current – December 2015 $3.350Floor sold 16,800 April 2015 – October 2015 $2.870

Floor purchased 16,800 April 2015– October 2015 $3.350Floor sold 16,800 January 2016 – December 2016 $2.750

Natural Gas – Three-Way CollarsFloor Purchased (Put) 15,000 January 2015 – December 2015 $3.600

Ceiling Sold (Call) 15,000 January 2015 – December 2015 $3.800Floor Sold (Put) 15,000 January 2015 – December 2015 $3.000

Natural Gas – CollarFloor Purchased (Put) 5,000 Current – March 2015 $4.000

Ceiling Sold (Call) 5,000 Current – March 2015 $4.750

Natural Gas Basis Swaps25,000 Current – October 2015 ($1.190)(1)

1. Dominion South / Henry Hub Natural Gas Differentials

Oil Hedges Volume (Bbl/d) Production Period Weighted Average Price ($/Bbl)

Oil – Collar

Floor Purchased (Put) 3,000 Current – February 2016 $55.000Ceiling Sold (Call) 3,000 Current – February 2016 $61.400

Eclipse Resources’ 2015 gas production is hedged at an average price of $3.76/MMBtu

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Year-End 2014 Earnings Call

Non-GAAP Reconciliations

1. Loss on asset sales2. Income tax benefit represents the effect of Company’s estimated annual tax rate 35.0% on Loss Before Income Taxes, adjusted

Adjusted EBITDAX Adjusted Net LossThree Months Ended

December 31,($ in thousands) 2014

Loss Before Income Taxes, as reported (45,221)$

Gain/Loss on derivative instruments (19,693)

Net cash payment on derivative instruments 2,211

Net cash paid for option premium -

Rig Termination Expenses 3,283

Gain on reduction of pension l iabil ity -

Impairment of proved oil and gas properties 30,250

Dry hole expense -

Impairment of unproven properties 1,504

Incentive unit compensation 61

Other expense(1) 272

Loss Before Income Taxes, as adjusted (27,333)

Income Tax Benefit, adjusted(2) 5,937

Adjusted Net Loss (21,396)$

December 31, September 30,($ in thousands) 2014 2014

Net Loss (33,023)$ (19,054)$

Depreciation, depletion & amortization 37,251 29,983

Exploration expense 4,289 3,057

Rig Termination Expense 3,283

Incentive unit compensation 61 31

Impairment of oil and gas properties 30,250 4,605

Accretion of asset retirement obligations 216 198

Gain on reduction of pension l iabil ity - -

Gain/Loss on derivative instruments (19,693) (5,572)

Net cash payment on derivative instruments 2,211 584

Net cash paid for option premium - (244)

Interest expense 13,027 10,066

Other expense(1) 272 -

Income tax expense (12,198) (10,544)

Adjusted EBITDAX 25,946$ 13,110$

Three Months Ended

Adjusted Net Production Pre-Tax PV-10December 31,

($ in thousands) 2014Before income tax (PV-10) 509,389$ Income taxes (178,732)

After income tax (standardized measure) 330,657$

Three Months EndedDecember 31,

(MMcfe/d) 2014Adjusted net production 130.7 Revision to prior estimate (3.8) Production held in suspense pending acreage (2.2) Condensate held in inventory at period end (0.9)

Net Sales Volumes 123.8

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Year-End 2014 Earnings Call

Operated Producing Well Detail

Well NameCompleted Lat Length

Type Curve Area

Turn-to-SalesMonth

24-Hr Peak Sales Rate (Mcfe/d)

Producing 30-Day Avg Sales Rate(1)

(Mcfe/d) % Gas % NGL % OilTippens 6HS 5,850 Dry Gas December-13 23,585 18,601 100% 0% 0%Herrick A 3H 5,761 Dry Gas June-14 17,068 13,511 100% 0% 0%Herrick B 5H 6,380 Dry Gas June-14 14,616 10,828 100% 0% 0%Herrick C 8H 6,232 Dry Gas June-14 16,590 14,503 100% 0% 0%Shroyer 2H 8,235 Dry Gas August-14 30,144 24,848 100% 0% 0%Shroyer 4H 6,608 Dry Gas August-14 23,663 22,131 100% 0% 0%Mizer 2H 5,986 Condensate August-14 7,910 5,540 39% 24% 37%Mizer 4H 5,903 Condensate August-14 7,798 5,856 40% 24% 36%Mizer 6H 5,811 Condensate August-14 6,173 4,473 40% 24% 36%Mizer 8H 5,970 Condensate August-14 7,559 5,978 41% 25% 34%Mizer 10H 5,943 Condensate August-14 6,999 5,522 41% 25% 34%Duane Weisend 4H 8,853 Rich Gas September-14 15,525 13,770 77% 23% 0%Mizer Farms 1H 6,421 Condensate September-14 6,882 3,491 40% 25% 35%Mizer Farms 3H 6,467 Condensate September-14 5,299 2,343 39% 24% 37%Mizer Farms 5H 6,343 Condensate September-14 6,795 2,747 38% 24% 38%Mizer Farms 7H 5,826 Condensate September-14 6,904 3,556 40% 24% 36%Mizer Farms 9H 5,823 Condensate September-14 7,761 4,781 38% 23% 39%Fri tz 3H 7,431 Condensate November-14 7,535 4,627 36% 23% 41%Fri tz 5H 7,436 Condensate November-14 6,931 4,532 37% 23% 40%Fri tz 7H 7,315 Condensate November-14 7,155 4,310 37% 23% 40%Hayes 2H 6,201 Condensate November-14 7,022 3,486 35% 21% 44%Hayes 4H 6,324 Condensate November-14 7,557 4,256 39% 24% 37%Hayes 6H 6,347 Condensate November-14 6,710 3,790 40% 25% 35%Hayes 8H 6,320 Condensate December-14 5,929 3,419 41% 25% 34%Pora 2H 7,862 Condensate December-14 7,211 4,538 40% 24% 36%Pora 4H 7,741 Condensate December-14 7,127 4,546 42% 26% 32%Pora 6H 7,812 Condensate December-14 5,210 3,760 41% 26% 33%Pora 8H 7,771 Condensate December-14 5,190 3,982 42% 26% 32%

Average 6,678 10,173 7,419

1. Assumes ethane rejection with contractual 30% recovery