First Quarter 2015:
Financial Review &
Operational Update
May 7, 2015
NYSE|ECR
1Q15EarningsCall
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 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.
2
1Q15EarningsCall
1Q15 Accomplishments
Production
Growth
Operational
Achievements
Financial
Highlights
1. A non-GAAP financial measure
 Grew average production by 316% from 38.5 MMcfe/d in the fourth quarter of 2014
to 160 MMcfe/d in the first quarter of 2015
 29% sequential quarterly production increase over the fourth quarter of 2014
 Grew total production for the first quarter to 14.4 Bcfe from 11.4 Bcfe for the fourth
quarter of 2014
Turned 11 gross (8.6 net) operated and 9 gross (2.6 net) non-operated wells to sales
Drilling days for the last 20 wells averaged 18 days
Increased average stages per day by 67% from 3 stages per day to 5 stages per day
All-in stage costs reduced from ~$170k in 2014 to ~$85k currently
Reduced average well costs by ~$2 million year over year
Reduced total drilling cost per foot to $286 per foot in our most recent 20 wells
drilled compared to $343 per foot four our first 20 wells drilled
 Recent agreement to lock-in cost savings of ~50% year-over-year for fracture
stimulation services through 2016






 Grew adjusted revenues(1) 113% from the first quarter of 2014 to $49.8 million
 Adjusted EBITDAX(1) grew to $20.7 million, a 73% increase over the first quarter of 2014
 Unit operating costs were $1.25 per Mcfe for the first quarter 2015, representing a
sequential increase of $0.08, or 7%, over the fourth quarter of 2014
 Strong Balance Sheet & Liquidity anchored with the close of private placement
3
1Q15EarningsCall
Peer Leading Drilling Performance
 Eclipse has participated to date in drilling 181 gross Utica Shale wells
to Total Depth (TD)
– 67 operated wells
– 114 non-operated wells with 8 different operators
Days to TD
40
31%
faster
30
 Operated wells have been drilled to TD in an average of 25 days for
all wells to date vs. an average of 36 days for all non-operated wells
 The last 20 operated wells have been drilled to TD in an average of
18 days vs. an average of 34 days for the last 20 non-operated wells
36
25
20
10
0
Eclipse
Non-Operated
Drilling Days (Normalized to 15,600’ TMD)
Last 20
Wells
Eclipses Resources
47% faster
18
Non-Operated
34
Eclipses Resources
All
Wells
25
Operator 1
36
Operator 2
36
Other Operators
40
0
5
10
15
20
25
30
35
40
45
4
1Q15EarningsCall
Well Cost Progression
Eclipse has reduced its type well drilling and completion costs in each development area
through drilling efficiencies, modified casing designs and downward pressure on
completions services; lower rig costs can reduce these prices further (~$250k per well)
Wet Gas ($ MM)(1)
12
Dry Gas ($ MM)(1)
12
10.5
10
10
9.5
0.7
0.7
8
7.4
4.2
8
8.2
4.5
0.7
0.7
6
6
3.8
3.5
4
4
4.6
3.9
2
-
2.7
0.7
0.5
2014
AFE
2015
Expected Cost
3.3
2
-
1. Normalized to a 6,000’ lateral
2. Drilling may incur an additional $0.75MM for a pilot hole and $0.4MM for a coal void if encountered
0.7
0.4
2014
AFE
2015
Expected Cost
5
1Q15EarningsCall
Operated Producing Utica Wells
6 13
8
Wells Average
Map Operated Unit
in Completed
ID
Name
Unit Lat Length
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
14
9 15
12 10
11
5
7
1
3
2 4
Tippens
Herrick A
Herrick B
Herrick C
Shroyer
Mizer
Duane Weisend
Mizer Farms
Fritz
Hayes
Pora
Frank Miller
John Mills West
Andy Yoder A
Andy Yoder D
Total/Average
1
1
1
1
2
5
1
5
3
4
4
3
2
3
3
39
5,850
5,761
6,380
6,232
7,422
5,923
8,853
6,176
7,394
6,298
7,797
6,724
7,901
7,021
6,253
6,738
Type
Curve Area
Turn to
Sales
Month
Dry Gas West
Dry Gas West
Dry Gas West
Dry Gas West
Dry Gas East
Lean Condensate
Dry Gas West
Lean Condensate
Lean Condensate
Lean Condensate
Lean Condensate
Lean Condensate
Lean Condensate
Lean Condensate
Lean Condensate
Dec-13
Jun-14
Jun-14
Jun-14
Aug-14
Aug-14
Sep-14
Sep-14
Nov-14
Nov-14
Dec-14
Feb-15
Feb-15
Mar-15
Mar-15
Producing 30-Day
Avg. Sales
Rate/Well(1)
(MMcfe/d)
18.6
13.5
10.8
14.5
23.5
5.5
13.8
3.4
4.5
3.7
4.2
5.2
7.6
7.4
6.7
7.2
% Gas % NGL % Oil
100%
100%
100%
100%
100%
40%
77%
39%
37%
39%
41%
38%
36%
37%
40%
0%
0%
0%
0%
0%
24%
23%
24%
23%
24%
26%
23%
22%
23%
25%
0%
0%
0%
0%
0%
35%
0%
37%
40%
38%
33%
39%
42%
40%
36%
Average Daily Production (MMcfe/d)
200
2015 Guidance = 185MMcfe/d
159.6
150
123.8
100
50
-
85.8
38.3
1Q14
41.9
2Q14
Operated
1. Assumes ethane rejection with contractual 30% recovery
3Q14
Non-Operated
4Q14
2015 Full Year Guidance
1Q15
6
1Q15EarningsCall
Production vs. Type Curves



Eclipse has interests in 122 producing Utica Shale
gas wells to date
– 43 Dry Gas wells
– 16 Rich Gas wells
– 63 Condensate wells
Newer vintage wells, with more intensive frack
designs, appear to have better performance
– Tighter stages (170 – 200’ vs. 250 -300’)
– Greater sand concentrations
– Slick water vs. Gel
Eclipse is currently producing wells on a restricted
choke program to enhance performance
Dry Gas Areas
10,000
Mmcfe
1,000
100
10
Condensate Areas
Rich Gas Areas
10,000
10,000
1,000
1,000
Mmcfe
Mmcfe
100
10
Only two operated wells in Dry
Gas East Area; both performing
well vs Dry Gas East Type Curve
Early wells were predominately nonoperated and produced at unrestricted
rates which may have negatively
affected cumulative production
100
10
7
1Q15EarningsCall
Operated Wells in Progress
Eclipse has elected to defer completions on 765 stages across 25 Utica wells (19.8 net) in the
company’s Condensate type curve window to date
Operated Wells as of May 1, 2015
Operated Net Well Summary
60
50
33.5
40
32.1
30
1.0
20
19.8
19.7
10
3.0
3.0
-
March 31, 2015
Drilling
Awaiting Completions
1.0
Awaiting Completions
May 1, 2015
Deferred Completions
Completing
Drilling
Deferred Completions
Producing
Completing
Producing
8
1Q15EarningsCall
Revenues & EBITDAX
Adjusted Revenue(1) ($ MM)
60
50
Average Net Price ($/Mcfe)
Avg / Mcfe Price, as reported
Plus cash settled derivatives
Realized Price
49.8
40
30
20
23.3
Natual Gas ($/ Mcf)
Avg Henry Hub Price
Less Differential
10
-
1Q14
1Q15
Realized Price(2)
EBITDAX ($ MM)
$3.50
$3.46
$3.00
20
20.7
15
10
$2.00
$1.50
11.9
$1.44
5
-
$2.50
$1.00
$/Mcfe
25
Oil ($/Bbl)
Avg WTI Price
Less Differential
Realized Price
NGL ($/Bbl)
% WTI
Realized Price
1Q15
$
$
3.05
0.42
3.47
$
2.90
(0.51)
$
2.39
$
$
48.49
(12.83)
35.66
$
40%
19.17
$0.50
1Q14
EBITDAX
1Q15
EBITDAX/Mcfe
1. Includes cash settled derivatives
2. Excludes firm transportation expense
$-
9
1Q15EarningsCall
Operating Expenses
Per unit operating expenses increased slightly due to increased liquid processing and treating
expense; however, costs remained below our guidance range
Operating Expenses ($ MM)(1)
20
$2.00
17.9
18
$1.65
$1.75
16
$1.50
14
13.3
12
11.1
$1.25
$1.17
10
8
$1.25
$1.00
$0.88
$/Mcfe
$1.40
$0.75
6.3
6
$0.50
4
3.0
$0.25
2
-
1Q14
1. Excluding DD&A and G&A
2Q14
3Q14
4Q14
1Q15
$-
10
1Q15EarningsCall
Liquidity, Capitalization & Hedging
Highlights




Liquidity ($ MM)(1)
450
Strong liquidity and hedge position
Ended first quarter with liquidity of $393 million
Approximately 84,000 MMBtu/d of gas hedged at
average price of $3.72/Mcf for the remainder of
2015
– ~65% of expected gas at guidance midpoint
Approximately 3,000 Bbls/d of oil hedged at floor
price of $55.00/Bbls in 2015
– ~65% of expected oil at guidance midpoint
$28
400
$393
$125
350
300
$295
250
200
150
100
50
-
Cash
Borrowing
Base
Gas Hedges(2)
Outstanding
Letters of Credit
Liquidity
3.31.15
Oil Hedges(2)
3,000
$90.00
-
Volume (MMBtu/d)
1. As of March 31, 2015
2. See Appendix for slide detailing hedges
Weighted Average Price
1,000
-
1,000
$3.30
$50.00
1,000
500
$55.71
$3.45
$60.00
$55.00
1,000
$70.00
Q2-15 Q3-15 Q4-15 Q1-16 Q2-16 Q3-16 Q4-16
Volume (Bbls/d)
$/Bbl
$60.00
$60.00
$60.00
2,333
$80.00
1,500
$55.00
Bbls/d
2,000
$55.00
25,000
25,000
Q2-15 Q3-15 Q4-15 Q1-16 Q2-16 Q3-16 Q4-16
$/MMBtu
$3.66
$3.66
$3.66
$3.66
25,000
15,000
$3.75
$3.60
25,000
30,000
$3.69
45,000
$3.75
60,000
2,500
$3.90
$3.71
MMBtu/d
75,000
3,000
$4.05
3,000
90,000
3,000
$100.00
77,333
3,500
87,000
$4.20
87,333
105,000
$40.00
$30.00
Floor Price
11
1Q15EarningsCall
2015 Gas Marketing Summary
Access to Gulf Coast and Midwest markets expected to provide ~$0.40-0.50/Mcf of uplift
after transportation expense relative to Dom South in 2015(1)
Highlights
Q1-15 Sales Markets
 Eclipse expects to market
57% of its gas to the
Midwest and Gulf Coast
markets in 2015 with
expected gas price
differentials of ($0.60) –
($0.70) after
transportation expenses
Q2 to Q4-15 Sales Markets
Mid
West
16%
Mid
West
21%
App
Basin
84%
M3
24%
App
Basin
10%
Gulf
Coast
45%
Summary of Firm Interstate Transportation Agreements
Firm Sales
TETCO
Rockies Express/ANR
TCO
Energy Transfer
Energy Transfer
Start Date
Apr-15
Apr-15
Jun-15
Nov-16
Dec-16
Jul-17
1. After transportation expense, pricing as of May 4, 2015
Term
Various
9.5 years
17 months
15 years
15 years
15 years
Volume (MMBtu/d)
Up to 50,000
100,000
50,000
205,000
100,000
50,000
Market
Dominion South / TETCO M2
Gulf Coast, Midwest & M3
Gulf Coast
TCO Pool
Gulf Coast
Dawn Hub
12
1Q15EarningsCall
2015 Guidance
Average Daily Production
% Natural Gas
% NGL
% Oil
Natural Gas Price Differential from NYMEX Before Transportation Expense(1)
Firm Transportation Expense ($/Mcf)
Natural Gas Price Differential from NYMEX After Transportation Expense(1)
Oil Price Differential from WTI(1)
NGL Price as % of WTI
Operating Expense(2)
Cash General and Administrative(3)
Capital Expenditures(4)
Second Quarter 2015
170 - 180 MMcfe/d
62 - 64%
18 - 20%
17 - 19%
Full Year 2015
180 - 190 MMcfe/d
67 - 70%
15 - 19%
13 - 16%
($0.40) - ($0.45)/Mcf
($0.35) - ($0.40)/Mcf
($0.75) - ($0.85)/Mcf
($0.32) - ($0.37)/Mcf
($0.38) - ($0.43)/Mcf
($0.70) - ($0.80)/Mcf
($12.00) - ($15.00)/Bbl
37% - 42%
($11.00) - ($15.00)/Bbl
37% - 42%
$ 1.40 - 1.48 / Mcfe
$ 13.5 - 14.5 million
$ 1.35 - 1.45 / Mcfe
$ 55 - 58 million
$ 352 million
1. Excludes impact of hedges
2. Excludes DD&A, exploration, and general and administrative expenses
3. Excludes costs associated with rig terminations, which will be booked as expenses in general and administrative
4. Includes routine lease acquisition, land related expenses, and net of projected midstream reimbursements; excludes land and producing asset acquisitions
13
APPENDIX
1Q15EarningsCall
Operated Producing Well Detail
Well Name
Completed Lat Length
Tippens 6HS
5,850
Herrick A 3H
5,761
Herrick B 5H
6,380
Herrick C 8H
6,232
Shroyer 2H
8,235
Shroyer 4H
6,608
Mizer 2H
5,986
Mizer 4H
5,903
Mizer 6H
5,811
Mizer 8H
5,970
Mizer 10H
5,943
Duane Weisend 4
8,853
Mizer Farms 1H
6,421
Mizer Farms 3H
6,467
Mizer Farms 5H
6,343
Mizer Farms 7H
5,826
Mizer Farms 9H
5,823
Fritz 3H
7,431
Fritz 5H
7,436
Fritz 7H
7,315
Hayes 2H
6,201
Hayes 4H
6,324
Hayes 6H
6,347
Hayes 8H
6,320
Pora 2H
7,862
Pora 4H
7,741
Pora 6H
7,812
Pora 8H
7,771
Frank Miller 2H
6,755
Frank Miller 4H
6,771
Frank Miller 6H
6,646
8,516
John Mills West 1
John Mills West 3
7,285
Andy Yoder A 1H
7,323
Andy Yoder D 2H
6,242
Andy Yoder A 3H
6,978
Andy Yoder D 4H
6,262
Andy Yoder A 5H
6,762
Andy Yoder D 6H
6,256
Average
6,738
Type Curve Area Turn-to-Sales
Month
Dry Gas
December-13
Dry Gas
June-14
Dry Gas
June-14
Dry Gas
June-14
Dry Gas
August-14
Dry Gas
August-14
Condensate
August-14
Condensate
August-14
Condensate
August-14
Condensate
August-14
Condensate
August-14
Rich Gas
September-14
Condensate
September-14
Condensate
September-14
Condensate
September-14
Condensate
September-14
Condensate
September-14
Condensate
November-14
Condensate
November-14
Condensate
November-14
Condensate
November-14
Condensate
November-14
Condensate
November-14
Condensate
December-14
Condensate
December-14
Condensate
December-14
Condensate
December-14
Condensate
December-14
Lean Condensate
February-15
Lean Condensate
February-15
Lean Condensate
February-15
Lean Condensate
February-15
Lean Condensate
March-15
Lean Condensate
March-15
Lean Condensate
March-15
Lean Condensate
March-15
Lean Condensate
March-15
Lean Condensate
March-15
Lean Condensate
March-15
1. Assumes ethane rejection with contractual 30% recovery
24-Hr Peak Sales Rate (Mcfe/d) Producing 30-Day Avg Sales Rate(1) (Mcfe/d)
23,585
18,601
17,068
13,511
14,616
10,828
16,590
14,503
30,144
24,848
23,663
22,131
7,910
5,540
7,798
5,856
6,173
4,473
7,559
5,978
6,999
5,522
15,525
13,770
6,882
3,491
5,299
2,343
6,795
2,747
6,904
3,556
7,761
4,781
7,535
4,627
6,931
4,532
7,155
4,310
7,022
3,486
7,557
4,256
6,710
3,790
5,929
3,419
7,211
4,538
7,127
4,546
5,210
3,760
5,190
3,982
6,701
5,079
6,593
5,143
6,830
5,295
8,961
7,670
8,546
7,612
8,762
7,230
7,143
6,807
8,684
7,607
7,074
6,716
8,272
7,381
6,961
6,656
9,471
7,203
% Gas % NGL % Oil
100%
0%
0%
100%
0%
0%
100%
0%
0%
100%
0%
0%
100%
0%
0%
100%
0%
0%
39%
24%
37%
40%
24%
36%
40%
24%
36%
41%
25%
34%
41%
25%
34%
77%
23%
0%
40%
25%
35%
39%
24%
37%
38%
24%
38%
40%
24%
36%
38%
23%
39%
36%
23%
41%
37%
23%
40%
37%
23%
40%
35%
21%
44%
39%
24%
37%
40%
25%
35%
41%
25%
34%
40%
24%
36%
42%
26%
32%
41%
26%
33%
42%
26%
32%
38%
23%
39%
37%
24%
39%
38%
23%
39%
36%
22%
42%
36%
22%
42%
37%
22%
41%
39%
25%
36%
37%
23%
40%
40%
25%
35%
38%
23%
39%
40%
24%
36%
15
1Q15EarningsCall
Hedging Summary(1)
Eclipse Resources’ 2015 gas production is hedged at an average price of $3.76/MMBtu
Volume
(MMBtu/d)
Production Period
Weighted Average
Price ($/MMBtu)
64,982
7,000
25,000
Current – December 2015
June 2015 – December 2015
January 2016 – December 2016
$3.792
$2.840
$3.660
Floor sold
Floor sold
Floor purchased
Floor sold
16,800
16,800
16,800
16,800
Current – December 2015
Current – October 2015
Current – October 2015
January 2016 – December 2016
$3.350
$2.870
$3.350
$2.750
Natural Gas – Three-Way Collars
Floor Purchased (Put)
Ceiling Sold (Call)
Floor Sold (Put)
15,000
15,000
15,000
Current – December 2015
Current – December 2015
Current – December 2015
$3.600
$3.800
$3.000
25,000
Current – October 2015
($1.208)(2)
Volume
(Bbl/d)
Production Period
Weighted Average
Price ($/Bbl)
Floor Purchased (Put)
Ceiling Sold (Call)
3,000
3,000
Current – February 2016
Current – February 2016
$55.000
$61.400
Oil – Three-Way Collar
Floor purchased (put)
Ceiling sold (call)
Floor sold (put)
1,000
1,000
1,000
March 2016 - December 2016
March 2016 - December 2016
March 2016 - December 2016
$60.000
$70.100
$45.000
Natural Gas Hedges
Natural Gas Swaps
Natural Gas Put Options
Natural Gas Basis Swaps
Oil Hedges
Oil – Collar
1. Includes post March 31, 2015 trades
2. Dominion South / Henry Hub Natural Gas Differentials
16
1Q15EarningsCall
Non-GAAP Reconciliations
Adjusted Net Loss
Adjusted EBITDAX
Three Months Ended
March 31,
March 31,
2015
2014
($ in thousands)
Net Loss
$
($ in thousands)
(34,103) $
(18,451)
Loss Before Income Taxes, as reported
Depreciation, depletion & amortization
42,432
12,027
Gain/Loss on derivative instruments
Exploration expense
13,453
4,545
7,057
-
Impairment of oil and gas properties
-
-
Incentive unit compensation
747
29
Accretion of asset retirement obligations
386
186
Gain on reduction of pension liability
-
(2,208)
Gain/Loss on derivative instruments
(11,371)
3,611
5,965
(1,441)
-
-
14,021
13,636
Rig Termination Expense
Net cash payment on derivative instruments
Net cash paid for option premium
Interest expense
(Gain) Loss of sale of assets
(322)
Income tax expense
Adjusted EBITDAX
$
20,686
0
$
$
11,934
(51,682) $
(11,371)
(18,451)
311
Net cash payment on derivative instruments
5,965
(1,441)
Rig Termination Expenses
7,057
-
Gain on reduction of pension liability
-
(2,208)
Impairment of proved oil and gas properties
-
Dry hole expense
4
Impairment of unproven properties
1,624
Incentive unit compensation
Other expense
Loss of sale of assets
Income Tax Benefit, adjusted
28
-
-
Loss Before Income Taxes, as adjusted
-
(17,579)
Three Months Ended
March 31,
March 31,
2015
2014
(1)
Adjusted Net Loss
1. Loss on asset sales
2. Income tax benefit represents the effect of Company’s estimated annual tax rate 35.0% on Loss Before Income Taxes, adjusted
$
(402)
-
80
-
(48,725)
(21,761)
16,440
7,616
(32,285) $
(14,145)
17