Investor Presentation
May 2015
NYSE|ECR
May2015CorporatePresentation
Cautionary Statements
Forward-Looking Statements
This presentation contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, included
in this presentation that address activities, events or developments that Eclipse Resources Corporation and its subsidiaries (collectively, the “Company”, “Eclipse”, “ECR”,
“we” and “us”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,”
“intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the
absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements
contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies and objectives and anticipated financial and
operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in
this presentation. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends,
current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and
uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forwardlooking statements. These include the factors discussed or referenced under the heading “Risk Factors” in the Company’s final prospectus dated June 19, 2014 and filed
with the Securities Exchange Commission (the “SEC”) pursuant to Rule 424(b) of the Securities Act of 1933, as amended, on June 23, 2014 (the “IPO Prospectus”).
The Company 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 the Company’s 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, commodity price volatility, inflation, lack of availability of drilling, production and processing equipment and services, legal and environmental risks, drilling
and other operating risks, regulatory changes, 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 IPO Prospectus.
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 forwardlooking 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, press releases 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, 2014. Actual
quantities that may be ultimately recovered from Eclipse’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery
include the scope of Eclipse’s drilling program, which will be affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling
services and equipment, drilling results, transportation constraints, regulatory approvals and other factors, and actual drilling results.
The type curve areas included in this presentation are based upon the Company’s analysis of available Utica Shale and Marcellus 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 Eclipse Resources’ wells may be substantially less than the Company anticipates or substantially less than performance and yields of other
operators in Eclipse Resources’ area of operation.
In this presentation, “EUR,” or “Estimated Ultimate Recovery,” refers to the Company’s internal estimates of per well hydrocarbon quantities that may be potentially
recovered from a future well completed as a producer. These recoverable quantities do not represent proved reserves.
2
May2015CorporatePresentation
Company Overview
Eclipse has ~6.6 Tcfe in Total Resource Potential on 128,000 net core Utica & Marcellus acres(1)
Eclipse Resources Assets
Utica Dry Gas
~35,000 Net Acres
Key Statistics
Market Capitalization(2)
$1.4 Billion
Liquidity(2)
$393 Million
Enterprise Value
$1.6 Billion
% of 2015 Gas Hedged (May thru Dec 2015)
~65% at $3.72/MMBtu
% of 2015 Oil Hedged (May thru Dec 2015)
~65% at $55/Bbl Floor
Average Daily Production (MMcfe/d)
1Q-14
38 (20% Liquids)
2Q-14
42 (36% Liquids)
3Q-14
82 (22% Liquids)
4Q-14
124 (27% Liquids)
2014
73 (26% Liquids)
1Q-15
160 (31% Liquids)
2Q-15 E
~170-180 (~37% Liquids)
2015E
~180-190 (~32% Liquids)
355.8 Bcfe
Proved Reserves(3)
Net Core
Identified Remaining Net Drilling
Utica Liquids Rich Gas
Marcellus Liquids Rich Gas
~66,000 Net Acres
~28,000 Net Acres
128,000
Acreage(4)
Locations(5)
799
% of Core Acreage Operated
85%
Long-Term Firm Transportation
505,000 MMBtu/d
1. Unproved, undeveloped potential will require additional capital to develop. Resource potential is based on internal estimates and includes, but does not represent, total proved reserves.
2. Market capitalization as of May 5, 2015. Liquidity as of March 31, 2015
3. Proved reserves based on estimates provided by Eclipse Resources’ independent engineering firm as of December 31, 2014 using SEC pricing
4. As of December 31, 2014. Acreage in Marcellus also included in Utica Dry
5. As of December 31, 2014. As Eclipse converts generically identified drilling locations with an assumed lateral length of 6,000' to planned or proposed locations, which currently have an average
lateral length 7,900', net locations will decline. 799 locations utilizes 750’ and 1,000’ inter-lateral spacing for liquids and dry gas wells, respectively
3
May2015CorporatePresentation
1Q15 Accomplishments
Production
Growth
Operational
Achievements
Financial
Highlights
1. A non-GAAP financial measure
 Grew average production by 316% from 38 MMcfe/d in the first 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 $0.08, or 7%, over the fourth quarter of 2014
 Strong Balance Sheet & Liquidity anchored with the close of private placement
4
May2015CorporatePresentation
Developing Value & Improving Efficiencies
Eclipse continues to convert unproved assets into proved reserves, while its drilling plan
generates superior growth
Proved Reserves (Bcfe)(1)
316%
75
38.5
1Q14
-
1Q15
Adjusted Revenue(2) ($ MM)
60
50
40
224%
6,000
110
1Q14
4Q14
12
73%
20.7
9
6
11.9
3
1Q14
1Q15
-
1Q15
Well Costs(3) ($ MM)
10
-
1Q14
15
20
10
5,996
5,000
Adjusted EBITDAX
49.8
23.3
7,173
5,500
30
20
20%
6,500
30
113%
7,500
7,000
150
60
-
356
225
90
30
300
1Q14
1Q15
0
~23%
10.5
9.5
8.2
7.4
2014
1. As of December 31, 2014; proved reserves based on estimates provided by Eclipse Resources’ independent engineering firm using SEC pricing
2. Adjusted Revenue includes the impact of cash settled derivatives
3. Type Curve Well AFE costs assuming a 6,000’ lateral
Dry Gas
159.6
Wet Gas
150
120
8,000
375
Dry Gas
180
Average Gross Lateral Feet per Well
Wet Gas
Net Production (MMcfe/d)
2015
5
May2015CorporatePresentation
Efficiently Growing Production through the Drill Bit
Highlights
 Expect ~150% year-over-year production growth from
2014 to 2015
 Grew first quarter production by 316% from 38
MMcfe/d in 2014 to 160 in 2015
 Expect to drill 19 operated and 2 non-operated net
wells in 2015 vs. 41 operated and 14 non-operated net
wells in 2014
 Expect to turn 29 net wells to sales in 2015 vs. 31 net
wells in 2014
– 11 net wells turned to sales in 1Q15
– Average lateral length of 7,030 feet
 ~19 net wells drilled, but not completed, in the
Condensate and Rich Gas areas will provide additional
growth as liquids prices recover
Net Production (MMcfe/d)
200
200
175
175
150
160
125
75
50
50
25
-
38
1Q14
9
50
9
6
25
4Q14
-
1Q15
2014
2015E
12
55
35
10
40
8
30
6
11
11
30
31
29
25
20
5
4
21
10
1Q14
4Q14
1Q15
15
6
20
2
-
73
Net Wells Turned to Sales
60
8
100
75
Net Wells Spud
10
150
125
124
100
185
-
4
10
2
2014
2015E
-
5
1Q14
4Q14
1Q15
-
2014
2015E
6
May2015CorporatePresentation
Liquidity, Capitalization & Hedging
Highlights
Liquidity ($ MM)(1)
 Strong liquidity and hedge position
 Ended first quarter with liquidity of $393
million
 ~65% of expected 2015 gas hedged at
$3.72.Mcf
 ~65% of expected 2015 oil hedged at a floor
price of $55.00/Bbl
450
$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
7
May2015CorporatePresentation
Peer Leading Growth with Reduced CapEx
Eclipse expects to achieve peer leading growth even as the company significantly reduces
capital expenditures
Consensus Average Production Growth (2015 -2017)(1)(2)
100%
80%
60%
40%
Peer Average = 24%
20%
0%
ECR
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
2014 CapEx = $809 MM
 Eclipse has decreased its
total capital expenditures
budget by 56% from 2014
to 2015
 Operated D&C capital
expenditures are focused
on Dry Gas Area of the
Utica Shale until liquids
prices recover
Land &
Other
20%
Non-Op
D&C
15%
Op D&C:
Dry Gas
10%
Op D&C:
Liquids
55%
1. Peer group represents the following companies: AR, CHK, CNX, COG, EQT, GPOR, MHR, REXX, RICE, RRC, SWN
2. Source: Company disclosures, IBES estimates, Bloomberg as of April 8, 2015
Peer 9
Peer 8
Peer 10
Peer 11
2015 CapEx = $352 MM
Land &
Other
12%
Op D&C:
Dry Gas
46%
Non-Op
D&C
29%
Op D&C:
Liquids
12%
8
May2015CorporatePresentation
Top Tier 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
40
Days to TD
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
9
May2015CorporatePresentation
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
10
May2015CorporatePresentation
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
11
May2015CorporatePresentation
Diversified Midstream Strategy
Eclipse’s acreage is centered across a confluence of major pipelines in the country
providing significant in- and out-of-basin optionality
Highlights
 The location of Eclipse’s acreage offers
access to numerous interstate pipeline
outlets
 Firm gathering, processing and
fractionation with Blue Racer Midstream for
its operated Utica Shale liquids area
acreage in place
 Firm gathering with Eureka Hunter for its
operated Utica Shale dry gas acreage in
place
 Firm condensate gathering and stabilization
with EnLink Midstream in place
 Firm transportation & marketing agreement
for Propane and Butane sales in place on
Mariner East II system to international
markets (Sales expected to commence Q416)
 Gas sales into Rockies Express, Texas
Eastern, and Dominion Transmission
PA
OH
TETCO
REX
WV
Blue Racer
Processing
Markwest
Processing
Dominion
Processing
Shell
Ethane Cracker
12
May2015CorporatePresentation
Premier Southern Utica & Rich Marcellus Position(1)
Eclipse’s core acreage position is well delineated in the heart of a world-class play
ECR 2 Wells
IP Rate 7.6 MMcfe/d
64% Liquids
Avg. 7,901’ Lateral
*
*
ECR 10 Wells
IP Rate 4.6 MMcfe/d
60% Liquids
Avg. 6,044’ Lateral
ECR 6 Wells
IP Rate 7.1 MMcfe/d
61% Liquids
Avg. 6,637’ Lateral
ECR 3 Wells
IP Rate 4.5 MMcfe/d
63% Liquids
Avg. 7,397’ Lateral
ECR 3 Wells
IP Rate 5.2 MMcfe/d
62% Liquids
Avg. 6,724’ Lateral
ECR 1 Well
IP Rate 13.8 MMcfe/d
23% Liquids
Avg. 8,853’ Lateral
ECR 4 Wells
IP Rate 3.7 MMcfe/d
61% Liquids
Avg. 6,298’ Lateral
***
**
ECR 4 Wells
IP Rate 4.2 MMcfe/d
59% Liquids
Avg. 7,797’ Lateral
*
*
ECR 1 Well
IP Rate 18.6 MMcfe/d
0% Liquids
Avg. 5,850’ Lateral
1. Producing 30-day average sales rate; assumes ethane rejection with contractual 30% recovery
*
*
ECR 2 Wells
IP Rate 23.5 MMcfe/d
0% Liquids
Avg. 7,422’ Lateral
ECR 3 Wells
IP Rate 12.9 MMcfe/d
0% Liquids
Avg. 6,124’ Lateral
13
May2015CorporatePresentation
2015 Type Well Economics
Eclipse has expanded its Utica type curve bands
across its acreage position into seven areas,
utilizing gas in place, thermal maturity
expectations, and historical well results to better
predict rates and liquids yields across the fairway
 Updated our gas in place and thermal maturity
models
 Expanded western boundary of Dry Gas West type
curve area to 1,175 BTU line to reflect processing
economics
 Revised curve parameters to better match production
data and Eclipse’s restricted choke production practice
Type Curve
Metrics
EUR (Bcfe)
EUR (Bcfe/1000 ft)
%Gas
%Condensate
%NGL
Lateral Length (ft.)
Net Locations
Well Cost ($MM)
(1)
IRR - Strip
IRR - $4.00/$80.00
1. Strip pricing as of March 9, 2015
Condensate Areas
Rich
Lean
Condensate
Condensate
Rich Gas Areas
Condensate
Rich
/ Rich Gas
Gas
Dry Gas Areas
Dry Gas
Dry Gas
West
East
4.3
0.7
45%
26%
29%
6,000
25
$7.4
6.3
1.1
50%
20%
30%
6,000
103
$7.4
7.5
1.2
59%
8%
33%
6,000
85
$7.4
10.5
1.7
69%
3%
28%
6,000
51
$7.4
12.4
2.1
100%
16.1
2.7
100%
N/A
N/A
N/A
N/A
6,000
216
$8.2
7%
15%
9%
12%
22%
43%
26%
31%
Marcellus Areas
Marcellus
Marcellus
West
East
6,000
66
$8.2
3.9
0.7
41%
21%
38%
6,000
114
$6.3
9.0
1.5
45%
13%
42%
6,000
91
$6.3
24%
39%
11%
51%
46%
74%
31%
139%
14
May2015CorporatePresentation
Production vs. Type Curves



Eclipse has interests in 122 producing Utica Shale
gas wells to date
– 43 Dry Gas wells
– 16 Rich Gas wells
– 63 Condensate wells
Newer vintage wells, with more intensive frack
designs, appear to have better performance
– Tighter stages (170 – 200’ vs. 250 -300’)
– Greater sand concentrations
– Slickwater vs. Gel
Eclipse is currently producing wells on a restricted
choke program to enhance performance
Dry Gas Areas
10,000
MMcfe
1,000
100
10
Condensate Areas
Rich Gas Areas
10,000
10,000
1,000
1,000
MMcfe
MMcfe
100
10
Only two operated wells in Dry
Gas East Area; both performing
well vs Dry Gas East Type Curve
Early wells were predominately nonoperated and produced at unrestricted
rates which may have negatively
affected cumulative production
100
10
15
May2015CorporatePresentation
2015 Guidance
Average Daily Production
% Natural Gas
% NGL
% Oil
Natural Gas Price Differential from NYMEX Before Transportation Expense(1)
Firm Transportation Expense ($/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
16
APPENDIX
May2015CorporatePresentation
Highly Experienced Management Team
Prior Experience
Years in
Industry
Name
Position
Benjamin Hulburt
President & CEO
14
Thomas Liberatore
Chief Operating Officer
34
Matthew DeNezza
Chief Financial Officer
13
Christopher Hulburt
General Counsel
14
Roy Steward
SVP, Chief Accounting Officer
15
Oleg Tolmachev
VP, Drilling & Completions
16
Bryan Moody
VP, Business Development
11
Marty Byrd
VP, Land
35
Dr. Brian Panetta
VP, Geology
18
Bruce King
VP, Operations
26
Melissa Hamsher
VP, Health, Safety, Environmental & Regulatory
14
Lawrence Gorski
VP, Administration
17
Todd Bart
VP, Controller
18
Dana Bryant
VP, Marketing and Midstream
16
John Colling
VP, Treasurer
9
Daniel Sweeney
VP, Assistant General Counsel
7
Timothy Loos
VP, Financial Planning & Analysis
10
Douglas Kris
VP, Investor Relations
22
Mark Spears
VP, Reservoir Engineering
34
18
May2015CorporatePresentation
Favorable Lease Expiration Schedule
~46% of leases have a 5-year extension option
Utica Core Area Leasehold Expiration(1)
45%
41.2%
40%
35%
29.1%
30%
25%
20%
15%
<7% of Eclipse's acreage
expires before 2017
11.2%
12.2%
10%
5%
4.7%
1.6%
0%
2015
1. As of December 31, 2014
2016
2017
2018
2019+
Fee/HBP
19
May2015CorporatePresentation
Northeast Supply/Demand Balance
Significant excess out-of-basin transportation capacity to meet production growth
expectations as Eclipse enters the winter of 2015
Northeast Supply-Demand and New Pipeline Capacity
Supply/Demand Balance
with 8 Bcf/d of new
takeaway capacity on
2 Bcf/d supply growth
Bcf/d
50
40
50
2-4 Bcf/d
oversupplied
40
30
30
20
20
10
10
-
-
Northeast Natural
Gas Market (Bcf/d)
Committed
Capacity (Bcf/d)
Committed takeaway:
60
Bcf/d
60
Demand plus Growth
Seneca
TEAM 2014
Uniondale
TEAM South
Leidy SE
Niagara
U2 GC
Eastside
Constitution
Layne-Reach Xpress
CT Expansion
AIM
Gulf Mkt
Rover
Cameron LNG
Broad Run Exp
Access S.
Adair SW
Northeast Exp
Atl Sunrise
Mnt Xpress
W Marcellus
Mtn Valley
Storage
Line 400
Rose Lake
Westside
East-West
Utica Backhaul
Broad Run Flex
OPEN
Tusc Lateral
C Tioga Ext
New Mkt
SoNo
Clarington W.
Leb West II
East Pipeline
TBA
Atl Bridge
Utica Access
NEXUS
Marcell/Loudon
PennEast
Atl Coast
Layne-Reach Xpress II
Expected Supply
Annual NE Natural Gas Production
2013
11.2
2014
15.7
2015
18.2
2016
20.4
2017
22.5
Annual NE Natural Gas Demand
14.9
15.3
15.1
15.5
15.8
Northeast Gas Surplus / (Deficit)
(3.7)
0.4
3.1
4.9
6.7
2.6
4.7
8.3
9.1
Cumulative Takeaway Additions (2014-2017)
2.6
7.3
15.7
24.8
Excess Out-of-Basin Capacity
2.3
4.2
10.8
18.1
Fully Committed Takeaway Projects
Source: EIA, FERC and Asset Risk Management, LLC
-
20
May2015CorporatePresentation
Type Curve & Cost Assumptions
Rich Condensate
Identified Net Drilling Locations
Lean Condensate
Condensate /
Rich Gas
Rich Gas
Dry Gas West
Dry Gas East
Marcellus West
Marcellus East
25
103
85
51
216
66
114
91
2.0
3.2
4.5
7.0
10.5
13.5
1.8
4.3
Initial Decline (%)
20%
20%
20%
20%
20%
20%
20%
20%
Months
8
8
8
8
8
8
8
8
Type Curve Assumptions
Gas Characteristics
Initial Production (MMcf/d) (1)
Exponential Phase
Hyperbolic Phase
Initial Decline (%)
55%
55%
55%
55%
55%
55%
55%
55%
B Factor
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
Terminal Decline (%)
6.0%
6.0%
6.0%
6.0%
6.0%
6.0%
6.0%
6.0%
Condensate Characteristics
175
120
60
15
N/A
N/A
150
100
Terminal Cond. Yield (Bbl/MMcf)
70
48
15
5
N/A
N/A
60
35
Cond. Yield Transition Time (Mth)
12
12
10
8
N/A
N/A
8
8
Initial Cond. Yield (Bbl/MMcf)
NGL Characteristics
NGL Yield (Bbl/MMcf)
Gas Shrink
92
88
80
60
N/A
N/A
125
125
85.1%
85.2%
86.2%
90.0%
N/A
N/A
81.0%
81.0%
BTU
1,300
1,287
1,265
1,200
1,050
1,025
1,400
1,400
Residue BTU
1,125
1,120
1,100
1,085
1,050
1,025
1,130
1,130
EUR (MMcfe) (2)
8,973
4,254
6,320
7,457
10,462
12,391
16,116
3,913
Oil (MBbl)
187
210
99
47
0
0
135
201
NGL (MBbl)
205
322
410
485
0
0
248
622
1,904
3,130
4,400
7,271
12,391
16,116
1,610
4,033
Residue Gas (MMcf)
% Liquids
55.2%
50.5%
41.0%
30.5%
0.0%
0.0%
58.9%
55.1%
Lateral Length (ft.)
Differentials
Gas ($/MMBtu)
Condensate ($/Bbl)
NGL (% of WTI)
6,000
6,000
6,000
6,000
6,000
6,000
6,000
6,000
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
($0.80)
(8.00)
40.0%
Operating Costs ($MM)
Fixed OPEX ($/well/mo)
Gathering & Compression ($/Mcf)
Processing ($/Dth)
Severance Tax (%)
$8,500
$0.89
$0.75
6.0%
$8,500
$0.89
$0.74
6.0%
$8,500
$0.89
$0.70
6.0%
$8,500
$0.89
$0.60
6.0%
$8,500
$0.49
$0.00
6.0%
$8,500
$0.49
$0.00
6.0%
$8,500
$0.89
$0.75
6.0%
$8,500
$0.89
$0.75
6.0%
Capital Cost ($MM)
Pad
$0.5
$0.5
$0.5
$0.5
$0.4
$0.4
$0.1
$0.1
Drilling
2.7
2.7
2.7
2.7
3.3
3.3
2.4
2.4
Completions
3.5
3.5
3.5
3.5
3.8
3.8
3.1
3.1
Facilities
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
1. 24-hour rate
2. Assumes ethane rejection with contractual 30% recovery
21
May2015CorporatePresentation
Proved Reserves Summary(1)
All Wells - Year-end 2014
SEC
Pricing
Net Oil
Net NGL
Net Gas
Net Total
Net PV-10
(MBbls)
(MBbls)
(MMcf)
(MMcfe)
($M)
PDP
PNP/PBP
PUD
Total Proved
2,967
914
1,816
5,697
4,269
2,489
4,120
10,879
159
11
150
137
25
18
500
75
50
15
94
-
200
$321
100
50
39
PDP
PNP/PBP
Natural Gas
NGL
PUD
Oil
-
$113
60
150
137
25
400
300
200
123
$509
$75
300
250
60
5
Net PV-10 ($ MM)
356
350
159
26
321,184
113,180
75,025
509,389
600
400
175
100
136,978
59,818
158,972
355,768
Total Reserves (Bcfe)
2014 Year-end Reserves (Bcfe)
125
93,561
39,398
123,350
256,310
Total Reserves
1. As of December 31, 2014; proved reserves based on estimates provided by Eclipse Resources’ independent engineering firm
100
-
Net PV-10
22
May2015CorporatePresentation
Operated Producing Well Detail
Well Name
Completed Lat Length
Tippens 6HS
5,850
5,761
Herrick A 3H
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
6,467
Mizer Farms 3H
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
John Mills West 1
8,516
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 24-Hr Peak Sales Rate (Mcfe/d) Producing 30-Day Avg Sales Rate(1) (Mcfe/d)
Dry Gas West
December-13
23,585
18,601
Dry Gas West
June-14
17,068
13,511
Dry Gas West
June-14
14,616
10,828
Dry Gas West
June-14
16,590
14,503
Dry Gas East
August-14
30,144
24,848
Dry Gas East
August-14
23,663
22,131
Lean Condensate
August-14
7,910
5,540
Lean Condensate
August-14
7,798
5,856
Lean Condensate
August-14
6,173
4,473
Lean Condensate
August-14
7,559
5,978
Lean Condensate
August-14
6,999
5,522
Dry Gas West
September-14
15,525
13,770
Lean Condensate
September-14
6,882
3,491
Lean Condensate
September-14
5,299
2,343
Lean Condensate
September-14
6,795
2,747
Lean Condensate
September-14
6,904
3,556
Lean Condensate
September-14
7,761
4,781
Lean Condensate
November-14
7,535
4,627
Lean Condensate
November-14
6,931
4,532
Lean Condensate
November-14
7,155
4,310
Lean Condensate
November-14
7,022
3,486
Lean Condensate
November-14
7,557
4,256
Lean Condensate
November-14
6,710
3,790
Lean Condensate
December-14
5,929
3,419
Lean Condensate
December-14
7,211
4,538
Lean Condensate
December-14
7,127
4,546
Lean Condensate
December-14
5,210
3,760
Lean Condensate
December-14
5,190
3,982
Lean Condensate
February-15
6,701
5,079
Lean Condensate
February-15
6,593
5,143
Lean Condensate
February-15
6,830
5,295
Lean Condensate
February-15
8,961
7,670
Lean Condensate
March-15
8,546
7,612
Lean Condensate
March-15
8,762
7,230
Lean Condensate
March-15
7,143
6,807
Lean Condensate
March-15
8,684
7,607
Lean Condensate
March-15
7,074
6,716
Lean Condensate
March-15
8,272
7,381
Lean Condensate
March-15
6,961
6,656
9,471
7,203
1. Assumes ethane rejection with contractual 30% recovery
% Gas % NGL % Oil
0%
0%
100%
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%
23
May2015CorporatePresentation
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 – October 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
$45.000
Natural Gas Hedges
Natural Gas Swaps
Natural Gas Put Options
Natural Gas Basis Swaps
Oil Hedges
Oil – Collar
1. Includes post March 31, 2015 trades
2. Dominion South / Henry Hub Natural Gas Differentials
24
May2015CorporatePresentation
Non-GAAP Reconciliations
Adjusted Net Loss
Adjusted EBITDAX
Three Months Ended
March 31,
March 31,
2015
2014
($ in thousands)
Net Loss
$
Three Months Ended
March 31,
March 31,
2015
2014
($ in thousands)
(34,103) $
(18,451)
Depreciation, depletion & amortization
42,432
12,027
Exploration expense
13,453
4,545
7,057
-
Net cash payment on derivative instruments
5,965
(1,441)
Impairment of oil and gas properties
-
-
Rig Termination Expenses
7,057
-
Incentive unit compensation
747
29
Gain on reduction of pension liability
-
(2,208)
Accretion of asset retirement obligations
386
186
Gain on reduction of pension liability
-
(2,208)
Impairment of unproven properties
Gain/Loss on derivative instruments
(11,371)
3,611
Other expense
5,965
(1,441)
Loss of sale of assets
-
-
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
$
$
Gain/Loss on derivative instruments
Dry hole expense
Income Tax Benefit, adjusted
(51,682) $
(11,371)
4
1,624
Loss Before Income Taxes, as adjusted
-
(17,579)
Loss Before Income Taxes, as reported
(1)
Adjusted Net Loss
$
(18,451)
311
28
-
(402)
-
80
-
(48,725)
(21,761)
16,440
7,616
(32,285) $
(14,145)
11,934
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
25