analyst & investor meeting - cnx resources
TRANSCRIPT
Analyst & Investor MeetingPittsburgh, Pennsylvania
March 13, 2018
Cautionary Language
2
Risk Factors. This presentation, including the oral statements made in connection herewith, contains forward-looking statements, estimates and projections within the meaning of the federal
securities laws. Statements that are not historical are forward-looking and may include our operational and strategic plans; estimates of gas reserves and resources; projected timing and rates of
return of future investments; and projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that
could cause actual results to differ materially from those statements, estimates and projections. Investors should not place undue reliance on forward-looking statements as a prediction of future
actual results. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely
on them unduly.
Specific factors that could cause future actual results to differ materially from the forward-looking statements are described in detail under the captions "Forward Looking Statements" and "Risk
Factors" in our annual report on Form 10-K for the year ended December 31, 2017 filed with the SEC, as supplemented by our quarterly reports on Form 10-Q. Those risk factors discuss, among
other matters, pricing volatility or pricing decline for natural gas and NGLs; our operational relationship with other parties, including midstream facilities; operational risks relating to pipeline
systems, drilling natural gas wells, and customer interactions; the impact of laws and regulations on our business and industry; competitive and economic concerns; risks associated with our debt
and hedging strategy; our ability to acquire economically recoverable natural gas reserves; challenges associated with strategic determinations, including the allocation of capital to strategic
opportunities; our development and exploration projects, as well as CNXM's midstream system development.
Reserves. Currently, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a
given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We may use certain terms in this presentation, such as EUR
(estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such
estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more
speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from
aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
Title. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to
the commencement of natural gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically
responsible for curing any title defects at our expense. As a result of our title review or otherwise, we may be required to acquire property rights from third parties at our expense in order to
effectively drill and produce the gas rights we control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells.
Reconciliation. As it relates to the disclosures within this presentation of projected Adjusted EBITDA and EBITDAX for fiscal or quarterly periods in 2018-2022, for CNX or CNXM, CNX
Resources is unable to provide a reconciliation of such metrics to projected operating income, the most directly comparable financial measure calculated in accordance with GAAP, due to the
unknown effect, timing, and potential significance of certain income statement items for each of CNX and CNXM, respectively.
Data. This presentation has been prepared by CNX and includes market data and other statistical information from sources believed by CNX to be reliable, including independent industry
publications, government publications and other published independent sources. Some data are also based on CNX’s good faith estimates, which are derived from its review of internal sources as
well as the independent sources described above. Although CNX believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy or
completeness. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CNX Resources Corporation or CNX Midstream Partners LP.
Agenda
3
Strategic OverviewNick DeIuliis, Chief Executive Officer
OperationsTim Dugan, Chief Operating Officer
Andrea Passman, VP – Development
MarketingChad Griffith, VP – Marketing
FinanceDon Rush
Chuck Hardoby, VP – Finance
Questions & AnswersBusiness DevelopmentDon Rush, Chief Financial Officer
Strategic OverviewNick DeIuliis
154-Year Legacy is a Competitive Advantage
5
1980 20001860 1960 2008 2010 2014 2017 2018
The vast
interwoven
nature of
the CNX
acreage
holdings
has
resulted in
non-
operated
well data
from more
than 800
Marcellus
and Utica
wells
dating
back to
1968
The Dominion
assets CNX
acquired in 2010
trace their roots
to the late 1800s
and John D.
Rockefeller’s
Standard Oil
Company, which
formed
Consolidated
Natural Gas
Industrialist
Andrew Mellon
financed the
consolidation of
the coal estate
throughout
Appalachia
leading to the
founding of
Consolidation
Coal Company
Greater than the Sum of the Parts
6
Set in motion more than a decade ago, CNX emerged as a
premier standalone E&P company on November 29, 2017
The separation of the businesses allows CNX to efficiently
deploy its capital allocation strategy
Asset Base Creates Compelling Value Creation Opportunity
7
Large
Contiguous
Acreage
Position
531,000 /
652,00095.5% 18.6
Highly
Productive
Asset Base1,116
MMcfe/d20% 75%
Leading
Economic
Profile$1.01-$1.11
/Mcfe32% 3.3x
Net Marcellus Acres /
Net Utica Acres(1) % OperatedReserves to
Production (years)
2017 Average Net
Production
5-Year
Production CAGR
Half-Cycle Portfolio
IRR
2018E Total Cash
Production and
Gathering Costs
2017
EBITDAX Margin2017 Recycle Ratio
7.6 Tcfe
3.7
Bcfe/1000’
2.5x
Proved Reserves
Current Deep Dry
Utica Performance
Targeted Leverage
Ratio by YE2018
(1) See appendix slide 102 for complete acreage breakdown by region.
The CNX Strategy is to Grow NAV/Share via Capital Allocation
8
Strategy is reinforced by management philosophy, company values, incentive plans, and ownership
Key drivers of the strategy:
Methodical execution driving IRR and EBITDAX growth
Basin disruption through stacked pay development
Top-tier balance sheet
Opportunistic share count reduction
CNXM 15% distribution growth stability and drop inventory
$0
$500
$1,000
$1,500
$2,000
2018E 2022E
$ in m
illio
ns
Low High
Methodical Execution Driving IRR and EBITDAX Growth
9
Expected Five-Year Plan Portfolio Economics
Note: See appendix for full and half cycle economic assumptions.
(1) Based on midpoint of financial guidance.
Drill Bit Investment Driving EBITDAX Growth
38%
75%
0%
10%
20%
30%
40%
50%
60%
70%
80%
Full Cycle Half Cycle
IRR
(%
)
Stacked Pay Development Will Disrupt the Appalachian Basin
10
CNX has a non-replicable asset base allowing for stacked pay development
Stacked pay drives superior IRRs through economies of scale and greater flexibility
▪ Reduces capital
▪ Reduces cycle times
▪ Reduces LOE
▪ Reduces gathering and processing fees
▪ Seismic across acreage hold that de-risks drilling, completion, and production
▪ Increases utilization and efficiencies
▪ Extends growth opportunity
Note: Assumes six Marcellus laterals at 9,500’ and six Utica laterals at 8,500’.
0%
20%
40%
60%
80%
100%
120%
$0
$50
$100
$150
$200
$250
$300
$2.00 $2.50 $3.00
IRR
(%
)
NP
V (
$ in m
illio
ns)
Gas Price
Stacked Pay Pad Economics Example
Unstacked NPV Stacked NPV
Unstacked IRR % Stacked IRR %
Stacked pay provides 30%
increase to total field NPV
Top Tier Balance Sheet Strength Drives Capital Optionality
11
IRR
ANALYSIS
DRILL BIT
BOLT-ON ACQUISITIONS
SHARE COUNT REDUCTION
STEADY STATE
2.5X LEVERAGE RATIO
ROBUST HEDGE BOOK &
FT STRATEGY
DISCRETIONARY CASH FLOW
ASSET MONETIZATIONS
BALANCE SHEET CAPACITY
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
$10,000
-
50
100
150
200
250
2017 2018E 2019E 2020E 2021E 2022E
Mark
et C
ap (
$ m
illio
ns)
Share
s O
uts
tandin
g (
mill
ions)
Shares Outstanding Market Cap
$0
$500
$1,000
$1,500
$2,000
$2,500
0.0x
0.5x
1.0x
1.5x
2.0x
2.5x
3.0x
2018E 2019E 2020E 2021E 2022E
EB
ITD
AX
($ in m
illio
ns)
Net
Debt
/ E
BIT
DA
X
Available debt capacity at 2.5x leverage ratio for share buybacks
Net Debt / EBITDAX excluding share buybacks or asset sale proceeds
EBITDAX Range
Leverage Ratio Capacity Allows for Share Count Reduction
12
Potential to reduce float ~40% by
YE2022 under status quo plan
or ~60% by YE 2022 with deployment
of potential drop proceeds
Note: Leverage ratio assumes the high case of financial guidance, while assuming no additional asset sales or drops.
(1) Stock repurchase price assumes static year-forward EV/EBITDAX multiple of 5.9x on guided adjusted EBITDAX and net debt levels. Does not assume deployment of
~$1.6 billion in potential drop proceeds and $0.2 billion in alternative minimum tax refund.
Growing EBITDAX Creates Natural Capacity
within 2.5x Leverage Ratio
Available Capacity Reinvested
in Share Count Reduction
(1)
Cumulative available capacity of
~$3 billion 2018-2022
Steady State Leverage Ratio: 2.5x~$70/share
on baseline
capacity(1)
~$30/share(1)
CNXM 15% Distribution Growth De-Risked
13
Expected CNXM Distributions to CNX 2017-2022E
$28
$42
$60
$80
$103
$130
$0
$20
$40
$60
$80
$100
$120
$140
2017 2018 2019 2020 2021 2022
$ in m
illio
ns
LP Distribution to CNX (as Declared)
GP & IDR Distribution (as Declared)
(1)
(1) 2017 GP IDR at 50% ownership.
CNXM Distributable Cash Flows by Source
2017-2022E
$0
$50
$100
$150
$200
$250
$300
2017 2018E 2019E 2020E 2021E 2022E
$ in m
illio
ns
PDPs pre-S/P Drop Shirley-Penns MVC
McQuay Activity Commitments Activity Above MVC & Commitments
Total Distributions
Compensation Plan Reinforces Strategy
14
Short-Term Incentive
Compensation Program
Long-Term Incentive
Program (PSUs)
2016
2017
50%
Relative TSR (S&P 500)
50%
Absolute Stock Price
Free Cash Flow
Free Cash Flow
Adjusted EBITDA/Share
Company-wide short-term
incentive plan
Governed by 2.5x
leverage ratio target
Encourages return of
capital to shareholders
CEO compensation 90%
at-risk (STIC, RSUs, and
PSUs)
Compensation plans motivate
management to execute on:
▪ Methodical operational execution
▪ Balance sheet discipline
▪ Basin disruption through stacked pay
development
▪ CNXM growth stability and upside
opportunities
▪ Share count reduction
2018 &
Beyond
Importance of Both Numerator and Denominator in NAV/Share
15
NA
VS
HA
RE
S
OU
TS
TA
ND
ING
DR
IVE
N B
Y OPERATIONAL EXECUTION
DIFFERENTIATED ASSET BASE
GROWING RESERVES VALUE
PRUDENT ASSET MONETIZATION
OPTIMIZED VALUE OF MLP
Share count reduction can
be the best capital allocation
decision if it passes through
the NAV and IRR filters
=NAV/Share
Accretion &
Recognition
BALANCE SHEET & HEDGE BOOK
OperationsTim Dugan
Andrea Passman
Unique Stacked Acreage Portfolio Sets the Stage
17
531,000 Total Net Marcellus Acres
582Net Undeveloped Marcellus
Locations in SWPA
652,000Total Net Utica Acres
~90% Total Company HBP
~89%Total Company Average NRI
669 Net Undeveloped Utica
Locations in SWPA
Vast multi-formation acreage
position built over 150+ years
Premier gathering infrastructure
and midstream MLP
Monetization opportunities outside
core development plan
Modeling, delineation, and innovative
solutions driven by decades of data
Cutting edge strategic intelligence
through extensive acreage position
Multi-basin experience delivered by
personnel and joint ventures
ASSET BASE HIGHLIGHTS
SKILL SET
Type Curve Guidance Areas Refined For Modeling Accuracy
(1) See http://investors.cnx.com/events-and-presentations/events/2018.
18
▪ Type curve (TC) guidance areas refined to present
more accurate characteristics of acreage
- Went from five TC regions (SWPA, CPA, WV,
and OH Dry & Wet) to now eight (SWPA: Central
& Greater, WV: SHR/PENS & East, CPA: South
& North, and OH: Dry & Wet)
- SWPA Central type curves increased in both
Marcellus and Utica compared to prior divisions
- ~80% of three-year plan in SWPA Central
▪ New type curve assumptions include:
- Increased lateral spacing in OH dry Utica and
adjustment for dry Utica sale in Jefferson County
- EURs increased in three of four focus areas in
three year plan (SWPA Central, WV SHR/PENS,
and OH Dry)
▪ Available electronic type curve data allows for
detailed modeling of the CNX production profile(1)
0%
20%
40%
60%
80%
100%
120%
140%
160%
0.7
4
1.2
1
1.5
6
1.9
4
2.0
0
2.1
7
2.4
4
1.2
2
1.6
1
2.3
0
2.4
8
2.7
1
2.9
9
3.1
8
3.8
5
5.0
6
1.8
6
2.9
2
3.3
9
2.0
3
4.7
7
4.4
6
3.2
6
2.4
0
2.1
8
2.6
9
2.3
1
5.6
6
2.6
3
1.8
5
3.0
7
2.6
7
2.5
1
2.5
9
2.5
4
2.7
8
2.7
9
3.4
5
2.9
1
3.5
5
2.8
9
2.9
3
2.2
7
2.3
9
2.4
2
2.5
7
2.8
5
2015 2016 2017 2018E
BT
AX
IR
R (
%)
EUR/CAPEX (Mcfe/$)
Capital Efficiency Continues to Improve
Note: Bars represent single well-level economics, which includes total D&C capital employed.
19
▪ NAV growth driven by
optimization and
stacked pay
▪ Increased EURs from
model-driven spacing,
completion design, and
managed pressure
drawdown
▪ Service cost inflation in
2017 offset by
increased EURs
Capital Efficiency (Mcfe/$)
1.83 Mcfe/$ 2.78 Mcfe/$ 2.78 Mcfe/$ 2.84 Mcfe/$
Avg BTAX IRR 25%
Avg BTAX IRR 52%Avg BTAX IRR 57%
Avg BTAX IRR 85%
EUR Increases Driven by Modeling and Optimization
20
Modeling Maximizes NAV
▪ 85% increase in proppant loading from
pre-2016 to 2018E
▪ Subsurface communication mitigation
implemented
▪ Lateral spacing optimization
▪ Managed pressure drawdown
▪ Cluster diversion technology
▪ Min/max stress optimization
▪ 3-D seismic guided drill plans
▪ Core area delineation
1.7
2.72.9
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
<2016 2016-2017 2018E
EU
R (
Bcfe
/10
00')
1.4
2.6
3.3
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
<2016 2016-2017 2018E
EU
R (
Bcfe
/10
00')
Marcellus EURs
Utica EURs
Possible FCF at Maintenance Capital
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
2018E 2019E 2020E 2021E 2022E
$ in m
illio
ns
Maintenance Capital Planned Capital
Possible FCF at Maintenance Capital Average Maintenance Capital
PDP Performance Drives Low Maintenance Capital
PDP Base Decline % Maintenance Capital
(1) For illustrative purposes; assumes annual production of 507 Bcfe (1.39 Bcfe/d exit rate), average EBITDAX of $800 million and interest expense of $100 million.
(2) December 2017 net daily average.
▪ Average maintenance capital of ~$325 million per year to
hold exit rate flat at 1.39 Bcfe/d(2)
▪ Expected exit-to-exit base decline rate of 32% in FY2018,
compared to FY2017
(1)
Possible Cumulative FCF of ~$1.4 billion
2019E-2022E
21
0%
5%
10%
15%
20%
25%
30%
35%
2018 2019 2020 2021 2022
<20% in Q2
2019
<10% in Q2
2021
2018E 2019E 2020E 2021E 2022E
Drilling Days Declining Steadily in Every Region
22
Total Marcellus – Average Drilling Days per Well
Ohio Wet Utica – Average Drilling Days per Well Ohio Dry Utica – Average Drilling Days per Well
CPA Utica – Average Drilling Days per Well
0
5
10
15
20
25
30
2014 2015 2016 2017 2018E
Drilli
ng D
ays
0
5
10
15
20
25
30
35
2014 2015 2016 2017 2018E
Drilli
ng D
ays
0
10
20
30
40
50
60
70
80
2014 2015 2016 2017 2018E
Drilli
ng D
ays
0
20
40
60
80
100
120
140
2015 2016 2017 2018E
Drilli
ng D
ays
Completion Cycle Times Driving Capital Efficiency
23
Total Portfolio Completions Cycle Times Marcellus Completions Cycle Times
0
1
2
3
4
5
2014 2015 2016 2017 2018E
Avera
ge D
ays/1
,0000 f
t
0
1
2
3
4
5
2014 2015 2016 2017 2018E
Avera
ge D
ays/1
,0000 f
t
24
DEVELOPMENT PLAN
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
YE
2017
YE
2018
E
YE
2019
E
YE
2020
E
YE
2021
E
YE
2022
E
Bcfe
/d
Marcellus Utica Other
Shift to SWPA and Stacked Pay: Surplus Core Marcellus Inventory
Stacked Pay Factory
up and running
20% Production CAGR
2017-2022E(1)
TILs 46
TILs 55
TILs 73
0
50
100
150
200
250
300
350
400
450
Entering 2018 2018 2019 2020 Year End 2020
TIL
Loca
tion
s
▪ As CNX returns focus to the core SWPA region, the company is expected to consume only a fraction of existing CNXM DevCo I Marcellus locations in the near term
- This creates valuable optionality in the development plan
- Increases activity
- Extends stacked pay development
- Creates asset sale and swap opportunities
25
(1) Based on the midpoint of guidance.
Net SWPA
Central
Marcellus
Inventory
391
Net SWPA
Central
Marcellus
Inventory
217
Stacked Pay Creates Substantial Uplift Beyond Longer Laterals
26
▪ Stacked pay PV10 is 4.4x unstacked pay
PV10(1)
▪ Longer lateral PV10 is 1.9x shorter lateral
PV10(1)
▪ Stacked pay is a more influential
economic driver than only focusing on
lateral length; CNX combines both value
drivers in development
▪ Extending laterals delays turn-in-line,
while stacked pays can be added at a
later date optimizing IRR and EBITDAX
Note: Example based on Richhill SWPA Marcellus and Utica development employing wet/dry blending strategy foregoing processing costs.
(1) Based on $2.00 gas price.
0
20
40
60
80
100
120
140
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$2.00 $2.50 $3.00
IRR
(%
)
PV
10 (
$ in t
housands)
Gas Price
Unstacked 9500' Unstacked 12000' Stacked 9500'
Stacked 12000' Unstacked 9500' ROR Stacked 9500' ROR
Unstacked 9500' Unstacked 12000' Stacked 9500' Stacked 12000'
LOE ($/Mcf) 0.10 0.10 0.05 0.05
Gathering rate ($/Mcf) 1.13 1.13 0.46 0.46
CAPEX ($ in millions) 8.4 9.8 8.3 9.7
Technological Advances Driving Tangible Results
27
EARTH MODEL
DATA ACQUISTION
DESIGN
OPTIMIZATION
STACKED PAY
FACTORY
PORTFOLIO NAV
OPTIMIZATION
▪ Fully integrated
subsurface model
▪ Neural net drives
productivity
indicators
▪ Core, logs, seismic
▪ Third party data
▪ Delineation
▪ Testing
▪ Reservoir and frac
modeling
▪ Managed pressure
drawdown via rate
transient analysis
▪ Machine learning
▪ System modeling
▪ Linear
programming
▪ Big data analysis
► Ensures highest
NPV combination
of fields while
balancing risk
► Managed pressure
drawdown
improves EUR by
20%
► Designs are
optimized in 3
wells vs. 13
► Improves field NPV
by 30%
► Seismic de-risks
SWPA stacked pay
development and
improves NAV by
$60 million► Drove
understanding of
three Utica areas
Three Utica Areas Require Distinct Development Plans
28
OHIO UTICA
▪ Manufacturing play
▪ 3.2 Bcf/1,000’
▪ 80’ of pay
▪ Low fracture intensity
▪ Optimized 10,500’ laterals
▪ 10,500’ TVD
CPA UTICA
▪ Stacked pay play within the
Utica and Point Pleasant
▪ 3.5+ Bcf/1,000’
▪ 300’ of pay in Utica, Point
Pleasant and Lexington
▪ 13,200’ TVD
SWPA UTICA
▪ Stacked pay factory with Marcellus
▪ 3.2 Bcf/1,000’
▪ 80’ of pay
▪ Intermittently fractured
▪ 12,000 TVD
MARCHAND 3M
GAUT 4I
GH 9SWITZ
FIELD
RHL 11
The Utica is a Precision Play
29
Understanding
reservoir
characteristics in
combination with
facies drives
productivity
OHIO (SWITZ) SWPA (RHL11E) CPA (Marchand3M)
Ohio Utica Model Drove SWPA and CPA Success
30
The model drove early success and eliminated the need
for trial and error testing
▪ Ohio Utica is the analogue model for rapid SWPA and
CPA Utica optimization
▪ Optimization of variable sand loading up to 3,000 lbs/ft
within variable inter-lateral spacing up to 1,500’
▪ Tail-in ceramic proppant
▪ Landing point defined by area
- Modeling defines target zone in a highly siliceous area
to maximize both drilling efficiency and well
productivity
Legacy Base Optimized
Fracture Conductivity (md-ft)
SWPA Utica: Very Strong Early Results from Richhill 11E
(1) Measured perforation to perforation.
(2) As of 3/8/2018. Turned in line 2/17/2018, excludes first four days of flowback/clean up.
(3) Normalized for lateral length to align with 6,200’ RHL11E (target capital lateral length in SWPA Utica is 8,500 ft. 31
Drilled through series of natural fracture clusters, which were
identified in 3D seismic analysis
▪ Required more drilling days than the expected run rate, which
elevated drilling costs
- Elevated drilling costs offset by productivity of the well due to
natural fracture clusters
Other additional costs related to completion design testing drove the
RHL11E well to exceed target capital costs, but there is clear line of
sight to the projected $14.3 million
RHL11E Summary
Lateral length(1) 6,200
Total capital less science $21 million
Average flowing pressure 8,445 psig
Average production(2) 22.1 MMcf/d
Target flowing production @ flat first 12 months 18 MMcf/d
Richhill 11E SWPA Utica well currently flowing above
3.2 Bcfe/1000’ type curveMost Recent SWPA Utica Well
on Path to Target Capital
$0
$5
$10
$15
$20
$25
Drilling Completions Water,Construction, and
Other
Total
Capital ($
in m
illio
ns)
RHL11E Actual AFE, less Science SWPA Utica Target Capital(3)
SWPA Utica Requires Engineered Design
32
▪ Success is consistently hitting
repeatable results by:
- Drilling on seismic
- Managed pressure drilling
- Cyber steering to improve in-zone
statistics
- Customized well layouts
- Engineered completion designs to
optimize for natural fractures and
over-pressured faults
▪ Target well cost in SWPA Utica:
$14.3 million
Point Pleasant
Onondaga
SWPA Region Overview: Greater and Central
33
▪ Core focus area for future development
▪ Stacked pay approach for increased returns
SWPA Central Marcellus Utica
Undeveloped Net Locations 391 438
EUR (Bcfe/1000’)(1) 2.8 3.2
Total NRI 87% 89%
Total PDPs 182 1
Net Current Production (Bcfe/d) 0.412 0.004
SWPA Greater Marcellus Utica
Undeveloped Net Locations 191 231
EUR (Bcf/1000’)(1) 2.7 3.0
Total NRI 91% 91%
Total PDPs 12 -
Net Current Production (Bcfe/d) 0.082 -
▪ ACAA development drives SWPA Greater, with two
pads completed to date
Morris FieldRichhill Field
Wadestown
Note: See appendix slide 104 for peer capital efficiency comparison.
(1) See appendix slides 108 and 109 for complete modeling assumptions and type curve.
SWPA Central: Focus of Activity in Three-Year Plan
34
▪ Average EUR/1,000’ increased 77% from legacy Morris wells(1)
- Morris-30 completed with enhanced stimulated reservoir
design
- Increased proppant loading, min/max stress optimization
along with the mechanical diversion testing program
- Changed targeted section of Marcellus to be drilled
▪ Morris pads being designed for future stacked pay development
▪ Morris wells expected to make up more than 65% of 2018E
SWPA Marcellus TIL activity
11
46
55
73
0
10
20
30
40
50
60
70
80
2017 2018E 2019E 2020E
TIL
s
SWPA Marcellus TILs: 2017 vs. Three-Year Plan
▪ SWPA Marcellus comprises a much larger portion of the three-
year plan than in 2017
- Activity in the Morris, Richhill, and Wadestown fields driving
the increase
- Plan to run 2-3 rigs in region throughout the time period
▪ ~80% of three-year plan activity located in SWPA Central
Marcellus/Utica
Morris Production – Legacy vs. Now
(1) Legacy Morris comprised of 21 wells TIL March 2012-June 2013; Morris 30 pad comprised of 5 wells TIL mid-2017.
Blending Strategy Helps Drive DevCo I Stacked Pay Economics
Note: Defined as Dry Utica 1010-1040 BTU; Dry Marcellus 1060-1110 BTU; Damp Marcellus 1110-1150; Wet Marcellus 1150+ BTU .
35
Re
qu
ire
s P
roc
es
sin
gD
oe
s N
ot
Re
qu
ire
Pro
ce
ss
ing
BT
U C
on
ten
t
1110
1150
1100
1040
1010
1200
1070
Dry Tariff Line
Wet Marcellus Gas
Damp Marcellus Gas
Dry
Utica/Marcellus
Gas
Damp acreage requires processing to meet
BTU specifications
Blended Gas = Damp Marcellus + Dry Utica/Marcellus▪ Avoids processing cost of $0.55-0.60/Dth
▪ Meets BTU tariff
- One Utica well required for every 3-4 damp Marcellus wells
Two Pipe Gathering System Creates Flexibility in DevCo I
36
Sta
nd
ard
Gath
ering S
yste
m
Industry Standard One-Pipe System CNX DevCo I Two-Pipe System
Hig
h P
ressu
re P
ipe
Lo
w P
ressu
re P
ipe
New Pad(High Pressure)
Compression / Dehydration
As new high
pressure wells are
TIL, higher
pressure gas
supplants older low
pressure wells
choking back total
production
Planned compressor stations
will create flexibility to
customize pressures in
specific gathering lines and
optimize marketing plans as
the project matures
The low pressure pipe
provides the option to
continue producing
existing wells rather than
interrupt production when
new higher pressure wells
are brought online
During stacked pay
development, Marcellus and
Utica wells can be brought
online simultaneously or
independently
▪ Most Marcellus producers
lack the ability to rapidly
bring on production as the
single pipe systems stay
near full capacity
Exis
tin
g P
ad
(Low
Pre
ssure
)
CH
OK
ED
Exis
ting P
ad
(Low
Pre
ssure
)
New Stacked Pay Pad(High Pressure and Low Pressure)
Richhill (RHL): Stacked Pay Development
37
RHL Development Case Study
▪ 30% NPV uplift due to stacked pay development
▪ CAPEX, OPEX, and cycle time savings from shared infrastructure increase
returns on both formations
▪ CNX’s blending strategy provides significant uplift on top of the advantages of
CAPEX, OPEX, and cycle time reduction
Marcellus Utica Stacked
Well Count 96 144 240
Capex ($ in millions) $816 $1,944 $2,700
NPV ($ in millions) $497 $809 $1,616
BTAX IRR 48% 49% 59%
▪ Premier stacked pay field in SWPA Central
- CNX expects to develop wet Marcellus laterals in the northern corridor first
- While the northern Marcellus corridor is being developed, two dry Utica pads
(MAJ6 and MAJ10) will be developed to blend wet Marcellus
- Marcellus development will continue after the wet northern corridor is
complete, with the second corridor being blended with Utica
- Utica development will follow behind Marcellus until completion
CPA Dry Utica Update: Aikens 5J and 5M
38
Aikens Wells EURs at 3.7 Bcf/1000’
▪ Located in Westmoreland County, PA (CPA South region); two wells offsetting successful Gaut 4IH well
▪ Average capital per well: approximately $15 million
▪ Currently performing above CPA Utica 3.5 Bcf/1000’ EUR with an average lateral length of ~7,000’(1)
- Cumulative production for combined wells is 3.58 Bcf through first 77 days
▪ Wells averaged 23 MMcf/d during first 77 days of production with average flowing pressure of 8,419 psig
- Expect production to be flat for ~18 months
▪ Executing managed pressure drawdown
▪ Aikens 5J: validating Gaut 4IH results by replicating completion design and achieving similar results
▪ Aikens 5M: testing higher proppant loading and model driven ceramic selection
- The Aikens 5M well is on track to be the second best well in the basin to date
Aikens 5J
Aikens 5M
(1) Measured in lateral feet from perforation to perforation; average drilled length of 7,500’.
0
5000
10000
15000
20000
25000
30000
35000
40000
0 100 200 300 400 500 600 700R
ate
(M
cf/
d)
DaysAikens 5M Actual (Mcf/d) 3.5 Bcf/1000' Type Curve
0
5000
10000
15000
20000
25000
30000
0 100 200 300 400 500 600 700
Rate
(M
cf/
d)
Days
Aikens 5J Actual (Mcf/d) 3.5 Bcf/1000' Type Curve
UT
ICA
Stacked Utica with Utica in CPA
39
▪ Utica, Point Pleasant and
Lexington are all gas bearing
contributing zones with a
total thickness of nearly 300’
- Verified by the Marchand
core and logs
▪ Potential to multiply Utica
locations within CPA by
stacking multiple wellbores in
the 300’ section to maximize
recovery from the pay zone
▪ Simultaneous development
of Utica stacked laterals may
maximize recovery through
pressure shadowing and
eliminate future infill drilling
PO
INT
PL
EA
SA
NT
LE
XIN
GT
ON
2018 Stacked Pay Baseline
$30.0
$10.9
$6.4
$2.9
$0.4
$0.8
2018 Stacked PayBaseline
Lateral Length Increase
Technology Utilization
Mineral PurchaseOptimization
Data Analytics
LOE Efficiencies
“Perfect Pad” to Create Stacked Pay Benchmark in 2019
40
12 Marcellus
wells drilled
Process
Dry month construction
Subsurface Marcellus well heads
Marcellus
completions
8 Utica
wells drilled
Utica
completions
3D seismic drives well bore optimization
Marcellus wells turned in line
M M M M M M
M M M M M M
U U U U
U U U U
Utica wells turned in line
Lo
w P
ressu
re
Lin
e
Cellar technology construction allows for subsurface well heads
for faster return
Two pipe system creates flexibility to produce high pressure and
low pressure wells simultaneously
Hig
h P
ressu
re L
ine
Hig
h P
ressu
re L
ine
Lo
w P
ressu
re
Lin
eM M M M M M
M M M M M M
Prior
Days
Target
Days
120 90
122 97
142 78
124 102
119 57
Optimal inter-lateral spacing: Marcellus 750 ft, Utica 1200-1500 ft
Combined NPV Gains from Marcellus & Utica in
SWPA Perfect Pad
Incremental NPV
of ~$21 million
31%
Reduction
35%
Reduction
($ in millions)
Central PA Overview: North and South
41
▪ Gaut & Aikens wells have proved area for Utica development
▪ Potential to stack Marcellus with Utica
▪ Continue to explore opportunities to expand gathering
infrastructure
CPA South Marcellus Utica
Undeveloped Net Locations 634 513
EUR (Bcf/1000’)(1) 1.8 3.5
Total NRI 87% 87%
Total PDPs 47 3
Net Current Production (Bcfe/d) 0.034 0.046
CPA North Marcellus Utica
Undeveloped Net Locations 615 498
EUR (Bcf/1000’)(1) 1.5 3.5
Total NRI 86% 86%
Total PDPs 9 -
Net Current Production (Bcfe/d) 0.005 -
▪ Currently delineating Utica to define Northern boundary driven from earth model
(1) See appendix slides 112 and 113 for complete modeling assumptions and type curve.
Development Areas in Three-Year Plan
42
CPA South
▪ Utica
SWPA Central
▪ Marcellus and UticaSHR/PENS
▪ Marcellus
OH Dry
▪ Utica
Three-Year Drill Schedule and Estimated Reserves Growth
43
Rig 1
Rig 2
Rig 3
Rig 4
Rig 5
Rig 6
Q1 Q2 Q3 Q4 Q4Q3Q2Q1 Q2 Q3 Q4 Q1
202020192018
TD Count
2018 2019 2020 Total
SWPA Marcellus 62 60 71 193
SWPA Utica 3 19 27 49
WV Marcellus 5 10 15 30
CPA Utica 4 0 9 13
OH Utica 8 0 0 8
Total 82 89 122 293
Reserve Growth and Estimates 2015-2022E
10,000
12,000
14,500
5,6436,251
7,582
8,500
10,000
12,500
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
2015 2016 2017 2018E 2019E 2020E
Bcfe
Rig Schedule 2018E-2020E
(1) Based on midpoint.
Low High
Three-Year Development Plan
44
(1) 50% working interest.
(2) Non-D&C capital for 2018E-2020E includes between $200-$300 million in each year associated with land, midstream, and water infrastructure.
2018E 2019E 2020E
($ in millions) TD FRAC TIL Capex TD FRAC TIL Capex TD FRAC TIL Capex
SWPA
Central
Marcellus 62 48 46 60 52 55 71 78 73
Utica 3 1 1 19 14 14 27 28 28
WV
Shirley-Penns
Marcellus 5 5 5 10 10 7 15 11 11
Utica - - - - - - - - -
CPA South Utica 4 4 2 - 1 3 9 5 3
OH DryUtica
8 10 15 - - - - - -
OH Wet(1) - 5 5 - - - - - -
Total 82 73 74 $790-$915 89 77 79 $1,010-$1,150 122 122 115 $1,200-$1,380 (2) (2) (2)
Greene County, PA Dry Utica:
Richhill 11E TIL Feb. 2018
14 SWPA Central dry Utica wells 28 SWPA Central dry Utica wells
Indiana County, PA Dry Utica:
Marchand 3M TIL set for Q3 2018
3 CPA deep dry Utica wellsNotable Wells
Business DevelopmentDon Rush
Track Record of Success: History of Monetizing Assets
46
▪ Annual average of ~$600 million in asset monetization
from 2014-2017
▪ $414 million in assets sold in 2017
▪ 2018 effort continues
- Shirley-Pennsboro midstream asset drop netted
$265 million in proceeds
- Shallow Oil & Gas (SOG) transaction in February:
$85 million in cash plus $190 million in liabilities
related to gas well plugging (asset retirement
obligations)
Future opportunities include:
▪ Non-core upstream assets
▪ Drops to CNX Midstream
▪ CNXM LP Units and IDRs
▪ Shale acres not in near-term development plan
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
$ in m
illio
ns
Asset Sale Totals by Year
Dry powder of ~$4 billion in drop down and other
non-core asset sales from 2019-2022 provides
substantial upside to current plan
SOG Sale Drives Continued Reduction in Legacy Liabilities
(1) Excludes wells located in the Murray and CONSOL Energy development area.
47
Conventional Shallow Oil and Gas (SOG) assets sold in
West Virginia and Pennsylvania, including CBM(1)
▪ Agreement signed mid-February
- Expected close by end of March
▪ 11,000 wells
▪ Cash proceeds of $85 million
▪ Buyer assumed plugging and abandonment liabilities of
$190 million
- Found in asset retirement obligations on balance sheet
▪ Associated annual production of ~20 Bcfe
▪ Associated EBITDA with transaction of ~$14 million in
2018E due to partial year sale; typical SOG EBITDA
between $15-$20 million per year; in addition, reduces
annual cash servicing cost by $5 million
SOG Wells Included in Sale
Virginia Coalbed Methane (CBM): Upstream
48
Low Risk Proven IRR
▪ ~270,000 contiguous acres, 100% WI
▪ 88% HBP, 87.5% NRI
▪ ~4,000 PDPs at 165 MMcf/d
▪ 2017 EBITDA of ~$100 million
Future Potential
▪ 4,300 potential undeveloped CBM locations
▪ 1,532 Bcf Net CBM Resource Potential
▪ Lexington & Conasauga shows with a strong supporting analog
▪ 391 potential laterals at 10k ft length
200,000
300,000
400,000
500,000
600,000
$150,000
$200,000
$250,000
$300,000
$350,000
$400,000
2014 2015 2016 2017
EU
R (
Mcf)
CapE
x (
$)
Virginia CBM – Capital Efficiency
CapEx EUR
Ohio Utica Joint Venture Overview
49
Low Risk, Mature Development
▪ 65% fee ownership, 46.5% avg. NRI (93% gross JV NRI)
▪ 31 gross operated JV wells (Noble County)
▪ 65 gross non-op JV wells, 47 non-op gross 3rd party wells
▪ ~85 MMcfe/d net production (~170 MMcfe/d net to JV production)
▪ 72% gas, 26% NGL, 2% condensate
Future Potential
▪ ~39,000 net core acres, 50% WI, (79,000 gross JV acres)
▪ 315 locations remaining(1)
▪ 3.95 Tcfe estimated total resource (7.9 Tcfe net to JV)
Strategic Options
▪ Sell the JV asset
▪ Divide assets to obtain 100% WI with JV partner
▪ Drill the assets per the governing agreements
14,000 gross acres
29,000 gross acres
36,000 gross acres
(1) Excludes stranded acreage.
50
CNX MIDSTREAMASSET AND OPPORTUNITY
$0
$50
$100
$150
$200
$250
$300
2017 2018E 2019E 2020E 2021E 2022E
$ in m
illio
ns
PDPs pre-S/P Drop Shirley-Penns MVC McQuay Activity Commitments Activity Above MVC & Commitments Total Distributions
De-Risked CNX Midstream Growth Driving CNX Upside
51
Ability to sustain 15% CNXM
distribution growth is projected
without additional asset drops
Coverage Ratio(1) 1.25x 1.56x 1.44x 1.31x 1.21x
(1) Assumes Shirley-Pennsboro drop effective as of 4/1/2018.
(2) Represents activity at an illustrative 140 well development level.
CNXM Distributable Cash Flows by Source 2017-2022E
(2)
Drop Inventory Drives Meaningful Upside to CNXM 15% Growth
52
Completed Year-To-Date
▪ Shirley-Pennsboro system: February 2018- $265 million: Expected to add $22-$24 million of pro
forma 2018 EBITDA for CNXM growing to $40-$50 million in 2020E
CNX Retained Undropped EBITDA including
Potential Drop Candidates 2017 vs. 2020EPotential Candidates 2018E-2020E
CONVEY Water Business
Existing DevCos
Primarily Wadestown in DevCo III
CPA Utica Gathering System
Cardinal States Gathering System
$-
$50
$100
$150
$200
2017 2017PF for S/P Drop 2020E
$ in
mill
ions
Retained Undropped EBITDA Potential
CONVEY: CNX’s Water Business
53
Annual Volume of Water Moved
Projected Water Infrastructure: YE2018
PA WV OH Total
Cumulative Water System CapEx
($ millions)$219 $94 $17 $330
Water Pipelines (miles) 189 79 33 301
Water Storage Facilities (MMBbl) 1.2 0.6 0.3 2.1
Total Water Moved (MMBbl) 33 4 8 45
-
20
40
60
80
100
120
2017(A) 2018(E) 2019(E) 2020(E)
Mill
ions o
f B
arr
els
(M
MB
bl)
PA WV OH 3rd Party
2017 2018E 2019E 2020E
Wadestown
SWPA Buildout
CONVEY: Major Projects
54
Wadestown Development
▪ ~$65 million - 5 year CapEx
spend
▪ NPV ~ $165 million, IRR ~ 120%
▪ Initial water infrastructure
buildout
▪ 38 miles of new water
infrastructure
▪ Eliminates seasonal water
variability
▪ Uninterruptable water capacity
for single completion crew
54
SWPA Water Build Out
▪ ~$155 million – 5 year CapEx spend
▪ NPV ~ $120 million, IRR ~ 80%
▪ 24 miles of new water infrastructure
▪ Uninterruptable water capacity capable of supplying
two completion crews
$-
$20
$40
$60
$80
$100
$120
$140
2017 2018E 2019E 2020E
CONVEY: Drives High Distribution Growth Rate
(1) EBITDA assumes water costs above, but subject to change based on final set rates. With exception of third-party sales, CONVEY EBITDA is eliminated in CNX
financial statements. Rates are determined based on 50% margin for fresh, 40% margin on reuse, and 30% margin on disposal (example costs below recent peer
comparisons).
(2) Water operating costs are based on historical averages in region and do not include infrastructure expenses.55
~$55 million water EBITDA at proposed rates in 2018(1)
▪ Driven by margin on CNX fresh, reuse, and disposal rates
▪ Final rates to be determined at time of drop
▪ Produced water accounts for 18% of 2018 proposed EBITDA
Over 100 miles of new water infrastructure to begin in 2018
▪ Ohio River to SWPA fresh water supply line
▪ Richhill and Majorsville infrastructure
▪ Wadestown development infrastructure
Fixed rates promote efficiencies for water operations
▪ CONVEY will continue to drive down costs to increase margins
▪ CNXM will benefit from cash flow stability
Steady Water EBITDA Growth(1)
Assumed Water Operating Costs ($/Bbl)(2)
PA WV OH
Fresh $0.95 $0.91 $1.62
Reuse $3.48 $4.78 $5.82
Disposal $8.12 $5.89 $7.11
Infrastructure supply
upgrade complete
Drop Down Inventory: Wadestown
56
Wadestown: Five-Year Investment Outlook
▪ Greenfield Marcellus and Utica dedication in DevCo III
▪ Wadestown metering and regulation Facility
- New 1.2 Bcf/d Dominion interconnect
- Wadestown compressor station
- Total buildout horsepower 42,750
▪ Pipelines: 39 miles
Expected Midstream Capital and EBITDA 2018E-2020E
$0
$20
$40
$60
$80
$100
$120
$140
$160
2018E 2019E 2020E 2021E 2022E
$ in m
illio
ns
CapEx EBITDA
Wadestown: Proposed Pipeline Buildout
Drop Down Inventory: Central PA Midstream Buildout
57
Central PA Utica: Five-Year Investment Outlook
▪ Currently undedicated to any midstream company
▪ Recent dry Utica well results proving commercial
viability
▪ Opportunity to be first-mover midstream company to
provide regional solution
- Estimated 425,000 Mcf/d of throughput by 2022
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
2018E 2019E 2020E 2021E 2022E
MM
cf/
d
Expected CPA Utica Throughput 2018E-2022E
Virginia Coalbed Methane: Midstream (Cardinal States Gathering)
58
Best-in-Class and Location
▪ Interconnects TransCanada TCO pipeline to premium Enbridge ETNG pipeline system
▪ “As is” 40% of the 250 MMcf/d capacity available to gather 3rd
party gas and provide significant revenue source
▪ Provides premium market outlet for CNX and 3rd party producers and shippers. Average basis differential of +$0.60/MMBtu
Organic Value Creation Opportunity
▪ Premier drop opportunity into CNX Midstream
▪ Upsize throughput capacity from 250 to 385 MMcf/d with relatively minimal capital expenditure. Convert into a FERC regulated system to transport TCO shale gas to southern markets
- Open Season 2/19/2018 to 3/2/2018; potential shippers being reviewed
- System to be spun into new entity, CNX Transmission LLC, which will then file a certificate application to become an interstate pipeline subject to FERC jurisdiction
CNX Midstream Ownership Valuation
(1) See detailed IDR Model in appendix slide 100.
(2) Reflects recent market comparisons.
(3) Unit price as of market close on 3/8/2018.
(4) 2020E unit price calculated using expected market yield of 6.0% on FY2020E distributions.
(5) 2018E retained EBITDA pro forma for Shirley-Pennsboro drop.
(6) Based on pro forma year-to-date share count of 219.8 million on 3/8/2018.59
CNX Midstream drives value
through four main avenues
▪ IDR cash distributions
▪ Ownership of LP units
▪ Retained EBITDA
▪ Future drop downs
CNXM Represents Significant Growth for CNX in
both IDRs and Retained EBITDACNX Midstream Value to CNX
($ in millions, except per share data) 2018E 2020E
IDRs
Cash Flow(1)
12.7$ 40.8$
Multiple(2)
60.0x 30.0x
Value 761$ 1,223$
LP Units
Unit Price(3)
18.20$ 30.19$
Current Yield 7.5% 6.0%
Units Held 21.69 21.69
Value 395$ 655$
Pro Rata EBITDA Contribution
Retained EBITDA(5)
10$ 200$
Market Multiple 8.0x 8.0x
Value 80$ 1,600$
Total Potential Value 1,240$ 3,480$
Value per CNX Share(6)
5.60$ 15.80$
$1,240
$3,480
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
2018E 2020E
$ in
mill
ions
IDRs LP Units Pro Rata Retained EBITDA Contribution
(4)
MarketingChad Griffith
MARKET VIEW
▪ Current forward market
▪ Supply/demand balance
▪ Growing demand and exports
▪ Volatility is king
Marketing Overview
61
FIRM TRANSPORTATION
▪ Selective FT commitments
- Utilize basis hedges to create
synthetic FT
▪ Fraction of the FT obligations
compared to peers
▪ Low FT average demand costs
of approximately $0.29 per
MMBtu
HEDGE STRATEGY
▪ Foundation that enables the
execution of the company’s
strategy
▪ Differentiates CNX and provides
competitive advantage
▪ “Total” hedge: matching basis to
NYMEX
▪ Programmatic – dollar cost
averaging
▪ Hedge volumes in alignment
with capital investment
Firm Transportation Strategy
62
▪ CNX realizes average NYMEX differentials with 1/8th of the
average “take-or-pay” FT obligation of peers
▪ CNX instead uses a strategic mix of FT, IT, basis hedging,
gathering system optionality, and capacity releases
Note: Peers include AR, CHK, COG, EQT, GPOR, RRC, and SWN.
(1) Project costs obtained from FERC filings; Spreads calculated using futures versus TETCO M2 pricing.
(2) TG&P obligations and price differentials from SEC filings and other company reports (Q3 2017).
$(2.00)
$(1.50)
$(1.00)
$(0.50)
$-
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
$16.0
$18.0
$20.0
CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
Diff.
to N
YM
EX
Tota
l O
blig
ations (
$ in b
illio
ns)
Transportation, Gathering, & Processing Commitments and Differentials(2)
FT, Gathering, and Processing Obligations
Gas Price Diff. to NYMEX
Peer Average Gas Price Diff to NYMEX
Three-Filter Test for Taking on New FT
1
2
3
Do we need it to get it to a liquid market?
Does it get us to a better market at a positive net
back?
Does it help us manage the volatility of the
markets we’re in?
$0.000
$0.200
$0.400
$0.600
$0.800
2018 2019 2020 2021 2022
Project Examples: Future Spreads vs. Demand Charges(1)
Project A Spread Project B Spread
Project A Tariff Project B Tariff
Liquidity of In-Basin Markets Negates Need for FT
(1) Based on midpoint of guided range.
(2) Based on recent results. Approximately 80% of CNX production nominated to FT.
63
Average Daily Production and Takeaway 2018E-2020E (Bcf/d)
2018E 2019E 2020E
CNX Gas Production(1) 1.3 1.5 1.8
Less: Estimated Production Sold Directly
into Basin (M2)(2) not requiring FT0.3 0.3 0.4
Gas Production Sold via FT 1.0 1.2 1.4
Current FT Capacity 1.2 1.5 1.4
It is no longer essential to have in-basin FT capacity to sell gas due to the
liquidity of the in-basin markets
▪ Gas can be reliably sold on M2 without taking on unnecessary and
expensive FT commitments
▪ CNX expects to continue selling gas into M2 in line with historical
proportional averages as seen below
- These in-basin sales essentially supplement the low-cost FT book
as it stands, as seen below
$1.1 $1.8
$3.7
$7.1
$8.9
$11.6
$18.4
CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
1.7x
3.1x
5.2x
6.2x
8.3x9.0x
11.1x
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
18%
48%
72%
139% 141%
180%198%
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Peer Firm Transportation Benchmarking
64
Total FT and Processing Commitments
$2.1 $2.7
$5.6
$10.8 $12.2
$18.7
$21.7
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
(FT Commitments + 2018E Adjusted Net Debt) /
2018E EBITDAX(1)(2)(3)(4)
(FT Commitments + 2018E Adjusted Net Debt) /
Adjusted EV(1)(2)(3)
Note: Peers include AR, COG, EQT, GPOR, RRC, and SWN. FT and processing commitments are off-balance sheet.
(1) CNX commitments as of 12/31/2017. Peer group commitments as of 9/30/2017.
(2) CNX debt as of 12/31/2017. Peer group debt as of 9/30/2017.
(3) Adjusted for remaining 2017E and 2018E outspend and present value of hedges. Outspend calculated as EBITDAX – capex – interest.
(4) CNX 2018E EBITDAX per company projections. Peer group 2018E EBITDAX per FactSet consensus estimates as of 2/13/2018.
Total FT Commitments + 2018E Adjusted Net Debt(1)(2)(3)
Differentiated Firm Transportation Portfolio
65
-
200
400
600
800
1,000
1,200
1,400
1,600
Jan 18 Jan 19 Jan 20 Jan 21 Jan 22
ETNG
TCO Pool
MichconELAWLA
M3
M2
000s
MM
Btu
/d
Dominion South
Note: Not all production requires reserved capacity. For example, certain “receipt point” sales are sold into gathering systems requiring no interstate FT, certain M2 and
M3 sales use capacity held by others, and some production is transported under IT arrangements.
Avg. Demand
Cost ($/Dth)
(000s Dth/d) 2018E 2018E
DOM South 345
ETNG 201
TCO Pool 475
Michcon 162
TETCO ELA 30
TETCO WLA 50
TETCO M3 100
TETCO M2 125
1,488 $0.29
Unutilized FT (reported in “Other Operating Expense”)
▪ Approximately 370,000 MMBtu/d in unused FT on Dominion
South and TCO
- Acquired as part of Dominion transaction in 2010
- Current drilling plans do not consider geographic area
where unutilized FT resides
▪ Forecasted for 2018E at approximately $36 million
- Expect to offset expense by reselling approximately $10
million per year
▪ Contracts expire in 2021 and 2022
▪ TCO Pool includes: 200,000 MMBtu/d on TCO’s
Mountaineer XPress project and 50,000 MMBtu/d of
capacity on TCO’s Leach XPress project in connection with
the Marcellus JV dissolution
Natural Gas Basis Risk and Financial Reporting Clarity
66
▪ Historical basis derived by first of month settle prices indicates
extreme volatility over the past two years
- Basis varies between $(0.39) and $(2.11) over two year
stretch(1)
$(2.50)
$(2.00)
$(1.50)
$(1.00)
$(0.50)
$-
Historical Basis Volatility
TETCO M2 Basis Dominion South Basis
Fully-hedged volumes provide revenue certainty and de-risks capital expenditures
▪ CNX hedges basis in addition to NYMEX
▪ Peers primarily only hedge NYMEX, which is a partial hedge
- Completely exposed to floating basis risk
Basis hedging and hedge reporting example
▪ October NYMEX settles @ $3.30 & M2 Basis settles @ ($1.10); M2 price of $2.20
Hedge Reporting Example CNX Company A
NYMEX Hedge $3.00 $3.00
Basis Hedge ($0.50) None
Henry Hub Settle $3.30 $3.30
M2 Basis Settle ($1.10) ($1.10)
NYMEX Hedge Payout ($0.30) ($0.30)
M2 Basis Hedge Payout +$0.60 n/a
Physical Gas Sale Price +$2.20 +$2.20
Actual Realized Sale Price $2.50 $1.90
▪ CNX would report fully-hedged price of $2.50 and receive $2.50
▪ Company A would report hedged price of $3.00, but receive only
$1.90
(1) IFERC First of Month pricing.
Power Plants and LNG Driving Demand Growth
(1) SNL
(2) EIA
67
14.7 Bcf/d incremental demand from gas fuel type
power plants by 2025
▪ CNX acreage in the center of the largest growth market, PJM
An additional 14.6 Bcf/d is proposed
0
2
4
6
8
10
12
14
16
2017 2018 2019 2020 2021 2022 2023 2024 2025
Bcf/
d
Increased Gas Demand from Planned Power Plants
2017 2018 2019 2020 2021 2022 2023 2024 2025
0
2
4
6
8
10
12
14
16
18
20
1Q2018 3Q2018 1Q2019 3Q2019 1Q2020 3Q2020 1Q2021 3Q2021 1Q2022 3Q2022
Bcf/d
LNG Expected Growth 2018-2022
In-Service Exports to Mexico 2018 2019 2020 2021 2022
13.9 Bcf/d LNG Export capacity by 2022
▪ An additional 11.6 Bcf/d is proposed without a target in-service
date (1)
Natural gas exports to Mexico via pipeline increased
to 4.2 Bcf/d in 2017(2)
NE Expansion Projects Remove Export Bottleneck
68
Projected 18.7 Bcf/d basin takeaway capacity expected by 2019
▪ Expected NE market takeaway projects to increase capacity by 12.2 Bcf/d in 2018 and an additional 6.5 Bcf/d in 2019 (1)
0
2
4
6
8
10
12
14
16
18
20B
cf/
d
Pipeline Expansion Project Takeaway Capacity
Supply Header Project
Atlantic Coast Pipeline
WB Xpress
Mountaineer Xpress
PennEast
Nexus Project
Atlantic Sunrise
Rover Phase 2
Leach Xpress
Other
(1) Company analysis.
Supply/Demand Fundamentals
(1) EIA Short-Term Energy Outlook.
69
Basin Demand Expected to Increase
▪ Roughly 6 GW of natural-gas fired power plant capacity in
Pennsylvania in 2018 (1)
▪ 20 GW capacity in 2018 across US
▪ Percentage of electricity generation from natural gas expected to
increase to 33.1% in 2018 from 31.7% in 2017 (1)
Regional Basis Narrows as Takeaway Capacity and Demand Increase
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
Henry Hub and Dominion South Pricing(Historical First of Month and Forward Strip)
Henry Hub Dominion S
▪ 2018 gas consumption expected to increase 3.5 Bcf/d to 77.5
Bcf/d and increase an additional 2.2 Bcf/d in 2019(1)
- 2018 HDD expected to be 11% higher than 2017(1)
- Power generation expected to increase 3.2 Bcf/d in 2018
▪ Net exports expected to increase 1.9 Bcf/d in 2018 and an
additional 2.3 Bcf/d in 2019 (1)
- LNG exports expected to increase from 1.9 Bcf/d in 2017 to
3.0 Bcf/d in 2018 and ramp up to 5.5 Bcf/d by end of 2019 (1)
- Natural gas exports to Mexico rose 0.4 Bcf/d in 2017 and
expected to continue on same trajectory (1)
- Natural gas imports expected to drop 0.3 Bcf/d in 2018 (1)
- US was net exporter of natural gas in 2017 for first time
since 1957 (1)
▪ 2017 storage dropped 6% below the five year average and is
expected to be roughly 6% below five year average by end of
2019 (1)
▪ 2017 production of 73.5 Bcf/d remained flat relative to 2016
levels, but an increase of 6.9 Bcf/d is expected for 2018 (1)
- Increase fueled by pipeline takeaway projects (1)
Liquids and Processing Summary
▪ CNXM and other wet gathering systems provide optionality for CNX wet production
▪ Optionality provides many benefits, including:
- Residue market optimization
- Access to existing, excess processing capacity
- Avoids being captive customer
▪ NGLs are generally marketed by processing companies – more efficient to outsource
▪ NGL pricing guidance based on contracts in place, NGL forward market, CNX view of
supply/demand/transportation fundamentals, and certain hedging programs of
processing companies
▪ $13 million in unutilized processing commitments forecasted for 2018E
ACAA
Richhill
MarkWest
MajorsvilleNoble County
Utica
Blue Racer
BerneBlue Racer
Natrium
Shirley/Penns
MarkWest
MobleyDominion
Hastings
Contracted Processing CapacityMarkWest
Blue Racer
Dominion
365 MMcf/d
70
FinanceDon Rush
Chuck Hardoby
Corporate Values Guide Decision Making
72
CO
RP
OR
AT
E
VA
LU
ES
RESPONSIBILITY
OWNERSHIP
EXCELLENCEC
NX
AS
SE
T B
AS
E
AN
D K
NO
WL
ED
GE
SE
T
NAV/SHARE FOCUS
DISCIPLINED CAPITAL
ALLOCATION STRATEGY
ALIGNMENT OF
STAKEHOLDER
INTERESTS
31%FIVE YEAR
EBITDAX CAGR(1)
(1) 2017-2022E based on midpoint of financial guidance.
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
$2,000
2018E 2019E 2020E 2021E 2022E
$ in m
illio
ns
Low High
Strategy Resulting In Substantial EBITDAX Growth
73
Expected EBITDAX 2018E-2022E(1)
(1) Based on midpoint of financial guidance. Base plan assumes no additional drops or asset sales.
Balance Sheet Capacity and Dry Powder Upside through 2022E
74
Dry powder of ~$4
billion through 2022E
consists of potential
drop proceeds, tax
refunds, CNXM LP/GP
monetization, and
non-core asset sales
~$5 billion
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
Drop CandidatesRetained EBITDA @
8x Multiple
YE2017 AlternativeMinimum Tax Refund
CNXM LP Unit/IDRMonetization
Non-Core Asset Sales Total Dry Powder +B/S Capacity @ 2.5x
Leverage Ratio
$ in m
illio
ns
Balance sheet capacity
at a steady 2.5x
leverage ratio comprises
another ~$3 billion in
available capital
Dry Powder
~$4 billion
Balance Sheet
Capacity
~$3 billion
375.9
290.6
182 181.9
94.9
43.3
44 12.1
72.3
0
50
100
150
200
250
300
350
400
2018 2019 2020 2021 2022
Gas V
olu
mes H
edged (
Bcf)
NYMEX + Basis (2) NYMEX Only Hedges Exposed to Basis
Marketing: Natural Gas Hedging and Basis Protection
75
▪ Systematically layering in
hedges out to 2022 to protect
margins on proved developed
production and a portion of
PUDs (capex)
▪ Locking-in revenue and de-
risking capital decisions by
matching NYMEX and basis
hedge volumes
▪ Protecting from in-basin blowout
through regional basis hedges
▪ Approximately 81% of total
2018E gas volumes hedged(3)
(1) Hedge positions as of 2/20/2018. Q1 2018 and 2018 exclude 6.4 Bcf and 13.9 Bcf of physical basis sales not matched with NYMEX hedges.
(2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements.
(3) Based on midpoint of total gas production guidance of 450-475 Bcf in 2018E.
(2)
Hedge Volumes and Pricing Q1 2018 2018 2019 2020 2021 2022
NYMEX Hedges
Volumes (Bcf) 88.4 358.6 321.0 215.0 172.6 153.4
Average Prices ($/Mcf) $3.14 $3.14 $3.02 $3.09 $3.00 $3.05
Physical Fixed Price Sales
Volumes (Bcf) 4.3 17.3 12.9 11.0 21.4 13.8
Average Prices ($/Mcf) $2.61 $2.61 $2.49 $2.44 $2.45 $2.54
Total Volumes Hedged (Bcf)(1) 92.7 375.9 333.9 226.0 194.0 167.2
NYMEX + Basis (fully-covered volumes)(2)
Volumes (Bcf) 92.7 375.9 290.6 182.0 181.9 94.9
Average Prices ($/Mcf) $2.76 $2.76 $2.69 $2.76 $2.53 $2.48
NYMEX Hedges Exposed to Basis
Volumes (Bcf) - - 43.3 44.0 12.1 72.3
Average Prices ($/Mcf) - - $3.02 $3.09 $3.00 $3.05
Total Volumes Hedged (Bcf)(1) 92.7 375.9 333.9 226.0 194.0 167.2
Financial Guidance: 2018E-2020E
76
2018E 2019E 2020E
Revenue and Other Operating Income E&P Consolidated E&P Consolidated E&P Consolidated
Production Volumes:
Natural Gas (Bcf) 450-475 505-575 610-700
NGLs (MBbls) 7,500-7,700 6,800-7,400 6,800-7,400
Oil (MBbls) 15-20 15-20 15-20
Condensate (MBbls) 590-610 430-480 420-480
Total Production (Bcfe) 500-525 550-630 650-750
% Liquids 9%-10% 8%-9% 6%-7%
Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40) ($0.35)-($0.45) ($0.40)-($0.50)
NGL Realized Price ($/Bbl) $23.00-$24.00 $22.00-$23.00 $20.00-$21.00
Condensate Realized Price % of WTI 70% 70% 70%
Oil Realized Price % of WTI 100% 100% 100%
Realized Hedging Gain/(Loss) ($ in millions) (1) $85-$90 $30-$40 $30-$40
Other Operating Income (3rd party water income and resold FT) ($ in millions) $15-$20 $15-$20 $15-$20
CNXM 3rd Party Gathering Revenue $80-$85 $65-$70 $60-$65
Costs
Average per unit operating expenses ($/Mcfe):
Lease Operating Expense $0.15-$0.18 $0.11-$0.13 $0.11-$0.12
Production, Ad Valorem, and Other Fees $0.06-$0.08 $0.05-$0.06 $0.07-$0.08
Transportation, Gathering and Compression $0.80-$0.85 $0.60-$0.65 $0.90-$0.97 $0.60-$0.65 $0.85-$0.95 $0.50-$0.60
Total Cash Production and Gathering Costs $1.01-$1.11 $0.81-$0.91 $1.06-$1.16 $0.76-$0.84 $1.03-$1.15 $0.68-$0.80
($ in millions)
Selling, General, and Administrative Costs(2) $85-$95 $95-$110 $85-$100 $100-$115 $85-$100 $100-$115
Exploration Expense $10-$15 $5-$10 $5-$10
Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70 $55-$60 $50-$55
Other Non-Operating Expense $15-$20 $10-$15 $10-$15
Total Capital Expenditures $790-$915 $875-$1,005 $1,010-$1,150 $1,335-$1,525 $1,200-$1,380 $1,275-$1,465
CNXM EBITDA Attributable to CNX $60-$65 $85-$95 $145-$165
EBITDAX $825-$850 $840-$1,000 $1,040-$1,200
CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected operating income, the most comparable financial measure calculated in
accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
(1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 2/16/2018. Anticipated hedging activity is not included in projections.
(2) Excludes stock-based compensation.
Financial Guidance: E&P 2018E
77
Transportation, gathering and compression costs
expected to decline $0.15-$0.20 year-over-year
primarily due to increased contribution of lower
cost dry Utica volumes in Monroe County, OH
Unutilized FT and Processing Fees: $50 million
Idle Rig Fees: $5 million
Basis calculated on 2018 market mix.
Hedge gain/(loss) calculated on
NYMEX and financial basis hedges
2018E
Revenue and Other Operating Income E&P
Production Volumes:
Natural Gas (Bcf) 450-475
NGLs (MBbls) 7,500-7,700
Oil (MBbls) 15-20
Condensate (MBbls) 590-610
Total Production (Bcfe) 500-525
% Liquids 9%-10%
Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40)
NGL Realized Price ($/Bbl) $23.00-$24.00
Condensate Realized Price % of WTI 70%
Oil Realized Price % of WTI 100%
Realized Hedging Gain/(Loss) ($ in millions) (1) $85-$90
Other Operating Income (3rd party water income and resold FT) ($ in millions) $15-$20
CNXM 3rd Party Gathering Revenue
Costs
Average per unit operating expenses ($/Mcfe):
Lease Operating Expense $0.15-$0.18
Production, Ad Valorem, and Other Fees $0.06-$0.08
Transportation, Gathering and Compression $0.80-$0.85
Total Cash Production and Gathering Costs $1.01-$1.11
($ in millions)
Selling, General, and Administrative Costs(2) $85-$95
Exploration Expense $10-$15
Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70
Other Non-Operating Expense $15-$20
Total Capital Expenditures $790-$915
CNXM EBITDA Attributable to CNX $60-$65
EBITDAX $825-$850Note: Base plan assumes NYMEX as of 2/16/2017 of $2.78 per MMBtu + weighted average basis of ($0.36) per MMBtu.
CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected operating income, the most comparable financial measure calculated in
accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.
(1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 2/16/2018. No future hedging in forecast.
(2) Excludes stock-based compensation.
Royalty income, right of way sales, interest income
and ‘other’ all netted against bank fees, other
corporate expense, and other land rental expense
Financial Guidance: 2018E E&P Revenue Buildup
78
Note: See appendix for assumptions.
Base plan assumes NYMEX as of 2/16/2018 of $2.78 per MMBtu + weighted average basis of ($0.36) per MMBtu.
2018E Revenue
Volumes Realized PriceRevenue
($ in millions)
Natural Gas 462.5 Bcf $2.55 /Mcf $1,180
NGLs 7,600.0 MBbls $23.50 /Bbl $179
Condensate 602.5 MBbls $42.00 /Bbl $25
Oil 17.5 MBbls $60.00 /Bbl $1
Realized Hedging Gain/(Loss) $87
Total 512.0 Bcfe $2.87 /Mcfe $1,471
Average Daily 1,410.0 MMcfe/d
Purchased Gas Sales $58
Other Operating Income
Water Income (3rd party sales) $8
Gathering Income (resold unutilized FT) $9
Total Revenue and Operating Income $1,545
Financial Guidance: 2018E Natural Gas Marketing Mix and Basis
Northeast Pipeline Projects
Southeast Pipeline Projects
Note: Forward market prices are as of 2/16/2018.
ETNG/Cascade Creek TZ5
2018E Gas: 11%
CY18 Basis: $0.34
TCO Pool
2018E Gas: 10%
CY18 Basis: ($0.26)
TETCO ELA & WLA
2018E Gas: 5%
CY18 Basis: ($0.09)
Dawn Pipeline Projects
Gulf Market Pipelines
Michcon
2018E Gas: 6%
CY18 Basis: ($0.21)
DOM South
2018E Gas: 10%
CY18 Basis: ($0.67)
TETCO M2
2018E Gas: 52%
CY18 Basis: ($0.67)
TETCO M3
2018E Gas: 6%
CY18 Basis: $0.23
Percentages include physical sales
Volumes 2018E CY 2018
(000 MMBtu) Gas Sold (%) Basis
DOM South 45,074 9% ($0.67)
ETNG/Cascade Creek TZ5 9,097 2% $0.34
TCO Pool 46,899 10% ($0.26)
TETCO ELA & WLA 6,112 1% ($0.09)
TETCO M3 29,235 6% $0.23
TETCO M2 209,567 43% ($0.67)
Michcon 28,315 6% ($0.21)
Physical basis sales 112,945 23% $0.02
Total (000 MMBtu) 487,244 100% ($0.36)
Total (MMcf) 463,000
NYMEX $2.78
Weighted Average Basis (Not considering hedging) ($0.36)
2018E Average Realized Price (per MMBtu) $2.42
Conversion Factor (MMBtu/Mcf) 1.054
2018E Average Realized Price (per Mcf) $2.55
BTU Uplift $0.13
Market
79
Financial Guidance: 2018E NGL Barrel Composition and Pricing
Approximately $200 million in revenue 2018E
▪ 2018E liquids sold:
- NGLs: 7,600 MBbls
- Condensate: 603 MBbls
- Oil: 18 MBbls
▪ 2018E: 9-10% total production expected to be liquids
▪ Total expected price for NGLs in 2018E of $23-$24/Bbl
▪ Total weighted average price of liquids in 2017 was $25.53/Bbl
▪ Contractual obligations to recover ethane (INEOS)
- Those contracts currently yield better pricing for the ethane
than selling it as a natural gas equivalent
Ethane48%
Propane30%
I-Butane5%
N-Butane9%
Natural gasoline
8%
Low High Midpoint
NGL $23.00 $24.00 $23.50
Condensate
(% of WTI)70%
Oil
(% of WTI)100%
Weighted Average NGL ($/Bbl)
“NGL Barrel” Composition
80
Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections
81
Note: Forward market prices are as of 2/16/2018. Hedged volumes and prices are as of 2/20/2018. Anticipated hedging activity is not included in projections.
See Appendix for Q1 2018, 2019, and 2020 hedging gain/loss projections.
(1) January and February are settled prices.
▪ In addition to NYMEX and basis financial
hedges, CNX has physical fixed basis sales and
physical fixed price sales with customers
▪ CY 2018 physical fixed basis sales: 89.6 Bcf
▪ CY 2018 physical fixed price sales: 17.3 Bcf
▪ Physical sales provide additional basis hedge
- Flows through gas sales in financials
(1)
CY2018 CY2019
Hedged Volumes Hedged Forward Forecasted Gain/(Loss)
(000 MMBtu) Price Market ($/MMBtu) ($ in 000's)
($/MMBtu)
NYMEX 377,775 $2.98 $2.78 $0.20 $74,668
Basis:
DOM South (DOM) 30,100 ($0.60) ($0.67) $0.07 $2,030
ETNG Cascade Creek TZ5 0 $0.00 $0.45 $0.00 $0
ETNG Mainline 0 $0.00 $0.23 $0.00 $0
Chicago 0 $0.00 ($0.12) $0.00 $0
TCO Pool (TCO) 36,500 ($0.27) ($0.26) ($0.01) ($239)
Michcon (NMC) 14,448 ($0.03) ($0.21) $0.18 $2,609
TETCO ELA (TEB) 5,475 ($0.09) ($0.09) $0.00 $27
TETCO WLA (TWB) 0 $0.00 ($0.08) $0.00 $0
TETCO M3 (TMT) 19,895 ($0.05) $0.23 ($0.28) ($5,547)
TETCO M2 (BM2) 191,613 ($0.60) ($0.67) $0.07 $13,173
Total Financial basis 298,030 $12,053
Total Projected Gain/(Loss) $86,721
Purchased Gas Sales
Other Operating Income
E&P EBITDAX
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
Total Revenue LOE Production, advalorem
Transportation,gathering,
compression
SG&A Purchased gascosts
Other operatingexpense
Other non-operatingexpense
Total AdjustedEBITDAX
Financial Guidance: 2018E E&P EBITDAX Buildup
82
Note: Based on midpoint of production and financial guidance range.
Base plan assumes NYMEX as of 2/16/2018 of $2.78 per MMBtu + weighted average basis of ($0.36) per MMBtu.
$0.15-$0.18 /
Mcfe$0.06-$0.08 /
Mcfe
$0.80-$0.85 /
Mcfe $85-$95 million
$65-$70 million
$50-$60 million
$15-$20 million
CNXM EBITDA
Attributable to CNX
$60-$65 million
E&P EBITDAX +
Attributable CNXM
EBITDA
$825-$850 million
Realized Hedging
Gain/(Loss)
Natural Gas And
Liquids Revenue
Financial Guidance: 2018E CNXM EBITDA Attributable to CNX
83
$0
$50
$100
$150
$200
$250
Total Revenue(100% of CNXM)
Operating Expense General &Administrative
EBITDA EBITDA Attributableto CNX
$ in
mill
ions
Non-Controlling Interest
$60-$65 million
84
CAPITAL ALLOCATIONOPTIONALITY DRIVING VALUE
Capital Allocation Optionality Drives NAV/Share
85
▪ In late 2015, committed to strengthening the balance sheet through focusing on NAV/share
- Positioned company for significant growth as a premier E&P company in the Appalachian Basin
▪ Transitioned from a defensive posture to an offensive strategy as the strong balance sheet sets the platform for growth
January 2016 Capital Allocation Driven
Buchanan Mine
Sale
Balance Sheet
Stabilization
Marcellus JV
Dissolution
Non-Core Asset
Divestitures
Asset Optimization
& Production
Growth
Coal Spin-Off
Share
Repurchases
CONE GP
Acquisition
Debt
Repurchases
Balance sheet
strength and
financial flexibility
allow CNX to
choose its path
forward via
strategic capital
allocation
86
Drill bitShare count
reduction
Bolt-on
acquisitionsBalance sheet
Target Leverage Ratio Provides Capital Allocation Optionality
IRR ANALYSIS
Capital Allocation Optionality: Drill Bit IRR Opportunities
(1) See appendix slide 115 for full detailed assumptions for both half and full cycle economics.
(2) Excludes sunk capex primarily applicable to OH.
(3) Includes net CNXM gathering rates. 87
Summary Assumptions
▪ Gas pricing: $2.50/MMBtu
▪ NGL pricing: $25/Bbl
▪ CND pricing: $45/Bbl
Full Cycle Assumptions(1)
▪ Capital Expenditures(2):
- Includes D&C, midstream, water
infrastructure and land
▪ Operating Expenses:
- Includes lifting, gathering(3), utilized FT,
general & administrative and production
taxes
Half Cycle Assumptions(1)
▪ Capital Expenditures(2):
- Includes only D&C and midstream
▪ Operating Expenses:
- Includes only lifting, gathering(3) and
production taxes
Transaction Volume
38%
73%
36%
67%
138%
300%
25%36% 38%
75%
0%
20%
40%
60%
80%
100%
120%
140%
Full Cycle HalfCycle
Full Cycle HalfCycle
Full Cycle HalfCycle
Full Cycle HalfCycle
Full Cycle HalfCycle
SWPA CPA OH WV CNX WeightedAverage
IRR
Portfolio IRR Summary: Five Year Plan
Five-Year Plan Capital Allocation by Region
SWPA82%
CPA10%
OH2%
WV6%
-
50
100
150
200
250
2017 2018E 2019E 2020E 2021E 2022E
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
$10,000
Sh
are
s O
uts
tan
din
g (
mill
ion
s)
Ma
rket C
ap
($
in m
illio
ns)
Market Cap
Shares Outstanding - Including Drop Proceeds
Shares Outstanding - No Additional Sales/Drops
Capital Allocation Optionality: Share Buybacks
88
Share Reduction230.1 million 223.8 million
Additional
90+ million share
reduction(2)
Q3 2017 End Year-End 20172018E-2022E
Buyback PotentialAs of:
S/O: 219.8 million
As of 3/6/2018
Potential share count reduction of ~60%
by year-end 2022 including additional drop proceeds
▪ Prior to spin:
- 6.4 million shares repurchased at average price of $16.08(3)
- Accounting for value of associated CEIX shares, repurchased shares have appreciated 36% compared to recent market prices(3)
▪ Since spin:
- 4.0 million shares repurchased at an average price of $13.95 appreciated 28% compared to recent market prices(3)
▪ Approximately $300 million remaining on share repurchase authorization for 2018
▪ CNX refused to issue equity during the downturn when most of its peers did
- As a result, longer term shareholders are seeing the benefit of the discipline compounded by the share repurchases happening now
(1) Stock repurchase price assumes static year-forward EV/EBITDAX multiple of 5.9x on guided adjusted EBITDAX and net debt levels. Market cap estimate includes
deployment of ~$1.8 billion related to potential drop proceeds and tax refunds..
(2) Not including deployment of ~$1.8 billion of potential drop proceeds and tax refunds.
(3) Shares repurchased as of market close 3/8/2018. Return calculation based on CNX and CEIX closing prices on 3/8/2018.
~$110/share
with drop
proceeds(1)
$0
$100
$200
$300
$400
$500
$0
$1,000
$2,000
$3,000
$4,000
$5,000
2012 2013 2014 2015 2016 2017 2018EA
nn
ua
l C
ash
Se
rvic
ing
Co
sts
($
in
mill
ion
s)
Lo
ng
-Te
rm L
iab
ilities (
$ in
mill
ion
s)
Long-Term Liabilities Total Annual Cash Servicing Cost
Rehabilitated Balance Sheet Sets New Beginning
89
Long-term liabilities now <$60 million with
annual cash servicing costs of <$5 million
Long-Term Liabilities Reduced by More than
$4 Billion Over last Six Years
2018E hedge book and production
ramp sets clear path to
<2.5x net debt / EBITDAX
Capital Allocation: Balance Sheet
90
Total Debt
YE 2017 YE 2018EBalance Sheet Highlights(1)
Cash
Net Debt
Leverage Ratio(2)(4) – LQA
Leverage Ratio(3) - TTM
$2,232 $1,980
$509 $25
$1,723 $1,960
2.5x -
3.6x 2.4x
(1) Debt balances exclude portions attributable to CNXM.
(2) Based on midpoint of financial guidance.
(3) Based on guided EBITDAX for next twelve month period and current period net debt.
(4) Last quarter annualized demonstrates EBITDA ramp in Q42017 impact on leverage ratio. Not shown for YE 2018E as CNX does not give quarterly guidance.
CNX EBITDAX Less Sensitive to Commodity Swings
$-
$200
$400
$600
$800
$1,000
$1,200
$1,400
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$3.00 $2.75 $2.50 $2.25
EB
ITD
AX
Sensitiv
ity (
$ in m
illio
ns)
Henry
Hub
Henry Hub EBITDA
Each $0.25 decline in HH
price yields only a $35 million
decline in 2018E EBITDAX
2018E EBITDAX at $2.85 per MMBtu HH
Total Liquidity $1,770 $1,700
$ in millions
Leverage Ratio(2)(3) – NTM 2.1x 2.1x
Tax Reform and NOLs Create Tailwind
Note: Deferred tax liability table from 2017 10-K p. 92.
91
▪ Tax reform law states that Alternative Minimum Tax (AMT) amounts can be refunded at 50% in first year
- Expect to receive first proceeds in 2019: ~$95 million
- Remainder of $188 million AMT refund expected over subsequent years
- Total figure is an estimate and could increase
▪ Following the spin transaction, CNX retained the corporate tax attributes
- Approximately $475 million in federal net operating losses (NOLs) with a cash value of about $95 million
- NOLs prior to 2018 can be used to offset 100% of future taxable income
- As a result, expect to pay no cash taxes for roughly 4-5 years
▪ Additional NOLs projected with sale of SOG that are likely to further delay cash tax obligation
▪ Intangible drilling costs (IDCs) will be 100% deductible in year one or can be amortized over five years
- In conjunction with NOLs, IDCs create flexibility to minimize cash tax burden for many years
December 31,
2017 2016
Deferred Tax Assets:
Alternative minimum tax $ 188,080 $ 219,872
Net operating loss - State 107,756 74,310
Net operating loss - Federal 99,524 144,450
Foreign tax credit 44,402 39,850
Gas well closing 16,648 20,512
Salary retirement 9,404 16,928
Capital lease 2,020 3,210
Gas derivatives — 72,105
Other 33,697 48,961
Total Deferred Tax Assets 501,531 640,198
Valuation Allowance (136,576) (282,778)
Net Deferred Tax Assets 364,955 357,420
Deferred Tax Liabilities:
Property, plant and equipment (385,366) (450,695)
Gas derivatives (15,248) —
Advance gas royalties (3,648) (5,824)
Equity Partnerships (1,251) (2,237)
Other (3,815) (3,760)
Total Deferred Tax Liabilities (409,328) (462,516)
Net Deferred Tax Liability $ (44,373) $ (105,096)
Finance Summary: 2014-2018+
92
Company Transformation
and Balance Sheet Repair
Share
Repurchases
Begin
Drilling
Program
Expanded
2017
2014-
2017Growing EBITDAX
Balance Sheet
Optionality
Continued
Share
Repurchases
Bolt-On
Acquisitions
Drill Bit
2018+
Gro
win
g N
AV
/Share
Ongoin
g H
edge P
rogra
m
Lo
ckin
g in
Re
ve
nu
e a
nd
Re
turn
s
IRR
An
aly
sis
CNX is Designed and Managed Differently
93
Strategy is reinforced by management philosophy, company values, incentive plans, and ownership
What about CNX’s distinctive strategy drives value?
Growing IRRs based on steady and reliable execution
Early movers on stacked pay development
Target 2.5x leverage ratio and balance sheet optionality
Continued commitment to share count reduction
CNXM growth opportunity beyond de-risked15%
94
Q&A
Appendix
Stacked Pay: Pad Level Benefits
96
▪ SWPA Central stacked pay development of Utica and Marcellus
yields the highest NAV/share
▪ Pay zone specific drilling & completion assignment reduces
capital and increase efficiencies
▪ Pay zone development timing flexibility
▪ Increased pad utilization & efficiency
- Planning work-flow delivers safe and efficient pad designs for
high value stacked pay development
- 6-10 wells per visit demonstrates the highest NAV/share
▪ Value loss mitigation utilizing refined development strategy
- Sequential corridor development prevents subsurface reservoir
interruption
▪ Reduces surface footprint of development by ~1000 acres
Stacked Pay: What are the Main Advantages?
97
(1) Assumes six Marcellus laterals at 9,500’ and six Utica laterals at 8,500’.
Marcellus Utica
Unstacked Stacked Unstacked Stacked
LOE ($/Mcf) 0.10 0.05 0.04 0.04
Gath. Rate ($/Mcf) 0.96 0.38 0.37 0.24
CapEx ($ in millions) 8.4 8.3 14.6 14.3
0%
20%
40%
60%
80%
100%
120%
140%
$0
$50
$100
$150
$200
$250
$300
$350
IRR
(%
)
NP
V (
$ in m
illio
ns)
Gas Price
Stacked Pay Pad Economics Example
Unstacked NPV Stacked NPV Unstacked IRR % Stacked IRR %
▪ Reduces capital
- Pre-spud capital nearly eliminated for second formation
- Use existing fuel gas to power D&C operations
▪ Reduces cycle times
- Pad & facilities already constructed
- Midstream and water infrastructure already in place
▪ Reduces LOE
- Driven by higher well count & concentrated volume
- Maintenance efficiency on infrastructure
▪ Reduces gathering fees
- Dry and wet gas can be blended to avoid processing fees
- Combining formations reduces gathering rate on Utica
- Processing flexibility to capture NGL upside in market
▪ 3D seismic de-risks & optimizes D&C across all pay zones
$2.00 $2.50 $3.00
Stacked Pay: Gas Blending Driving NAV/Share
98
▪ Midstream pipeline tariffs require Marcellus gas
above 1110 BTU be processed
▪ Processing damp gas between 1100-1150 BTU
range is NPV destructive
▪ Solution: Develop dry Utica concurrent to damp
Marcellus and blend to avoid processing
- Avoids processing & increases gathering
efficiency
- Allows capture of BTU value of damp gas
- Blending solutions drive long term synergies
with CNXM
Unstacked Stacked Delta
Well Count 240 240 -
CapEx ($ in millions) $2,761 $2,700 ($61)
NPV ($ in millions) $1,306 $1,616 +$310
BTAX IRR 48.4% 59.4% +11.0%
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
1110 1120 1130 1140 1150
Late
ral Length
(ft
)
Marcellus BTU
Lateral Feet to Blend by BTU to Equal 1100
Utica Lateral Length Marcellus Lateral Length
Stacked Pay: Marcellus/Utica vs. Marcellus/Upper Devonian
99
▪ Stacked Pay with Marcellus and Utica
yields a higher NPV than stacking
Marcellus with Upper Devonian wells
▪ Stacking wet gas Marcellus wells with dry
gas Utica wells gives the optionality to
blend or process the gas depending on
NGL market conditions
▪ An Upper Devonian well yields ~60% of
the production of a Marcellus well for
similar capital
Stacked Pay
CNX Marcellus/Utica Stack Company A Marcellus/Upper Devonian Stack
LL 9500'/8500' 12000'/15000'
EUR/Ft 2.8 / 3.2 2.4 / 1.5
LOE ($/Mcf) 0.10 0.10
CapEx ($ in millions) 8.3/14.1 11.0/10.8
Gathering Rate ($/Mcf) 0.46 0.46
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
$2.00 $2.50 $3.00
PV
10 (
$ in m
illio
ns/F
t)
Gas Price
Normalized NPV (NPV/Foot)
CNX Marcellus/Utica Stack Company A Marcellus/Upper Devonian Stack
Detailed IDR Model: Assuming 15% Distribution Growth
100
Note: Distribution targets found on page 79 of CNX Midstream 2017 10-K.
GP +
Floor Ceiling LP Share IDR Share IDR Share
Minimum Quarterly Distribution (MQD) 0.212500 98% 2% 0%
First Target Distribution 0.212500 0.244375 98% 2% 0%
Second Target Distribution 0.244375 0.265625 85% 15% 13%
Third Target Distribution 0.265625 0.318750 75% 25% 23%
Thereafter 0.318750 50% 50% 48%
Total LP Units 21.7 million
1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22
Distribution Per LP Unit 0.2450 0.2540 0.2630 0.2724 0.2821 0.2921 0.3025 0.3133 0.3245 0.3360 0.3480 0.3604 0.3732 0.3865 0.4003 0.4145 0.4293 0.4446 0.4604 0.4768 0.4938 0.5114 0.5296 0.5484 0.5680 0.5882 0.6091 0.6308
Distribution Growth % 3.7% 3.5% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6%
LP Take by Tier
Minimum Quarterly Distribution (MQD) 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125
First Target Distribution 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319
Second Target Distribution 0.0006 0.0096 0.0186 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213
Third Target Distribution 0.0000 0.0000 0.0000 0.0068 0.0165 0.0265 0.0369 0.0477 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531
Thereafter 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0057 0.0173 0.0292 0.0416 0.0545 0.0678 0.0815 0.0958 0.1105 0.1258 0.1417 0.1581 0.1750 0.1926 0.2108 0.2297 0.2492 0.2694 0.2904 0.3121
Total 0.2450 0.2540 0.2630 0.2724 0.2821 0.2921 0.3025 0.3133 0.3245 0.3360 0.3480 0.3604 0.3732 0.3865 0.4003 0.4145 0.4293 0.4446 0.4604 0.4768 0.4938 0.5114 0.5296 0.5484 0.5680 0.5882 0.6091 0.6308
GP Take by Tier
Minimum Quarterly Distribution (MQD) 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043
Tier 1 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007
Tier 2 0.0001 0.0017 0.0033 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038
Tier 3 0.0000 0.0000 0.0000 0.0023 0.0055 0.0088 0.0123 0.0159 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177
Tier 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0057 0.0173 0.0292 0.0416 0.0545 0.0678 0.0815 0.0958 0.1105 0.1258 0.1417 0.1581 0.1750 0.1926 0.2108 0.2297 0.2492 0.2694 0.2904 0.3121
Total 0.0051 0.0067 0.0083 0.0110 0.0142 0.0176 0.0210 0.0246 0.0322 0.0437 0.0557 0.0681 0.0809 0.0942 0.1080 0.1222 0.1370 0.1523 0.1681 0.1845 0.2015 0.2191 0.2373 0.2561 0.2757 0.2959 0.3168 0.3385
Total Distributions 0.2501 0.2607 0.2713 0.2834 0.2963 0.3097 0.3236 0.3380 0.3567 0.3798 0.4037 0.4285 0.4541 0.4807 0.5083 0.5368 0.5663 0.5969 0.6285 0.6613 0.6953 0.7304 0.7669 0.8046 0.8436 0.8841 0.9260 0.9694
GP Take 2.0% 2.6% 3.1% 3.9% 4.8% 5.7% 6.5% 7.3% 9.0% 11.5% 13.8% 15.9% 17.8% 19.6% 21.2% 22.8% 24.2% 25.5% 26.7% 27.9% 29.0% 30.0% 30.9% 31.8% 32.7% 33.5% 34.2% 34.9%
LP Take 98.0% 97.4% 96.9% 96.1% 95.2% 94.3% 93.5% 92.7% 91.0% 88.5% 86.2% 84.1% 82.2% 80.4% 78.8% 77.2% 75.8% 74.5% 73.3% 72.1% 71.0% 70.0% 69.1% 68.2% 67.3% 66.5% 65.8% 65.1%
LP Units O/S 58.34 58.34 58.34 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53
GP + IDR Distributions ($MM) 0.30 0.39 0.48 0.70 0.90 1.12 1.34 1.57 2.04 2.78 3.54 4.33 5.14 5.98 6.86 7.76 8.70 9.67 10.68 11.72 12.80 13.92 15.07 16.27 17.51 18.80 20.13 21.51
Annual GP+IDR Distribution ($MM) $1.87 $4.92 $12.69 $25.75 $40.78 $58.06 $77.94
Annual LP Distribution ($MM) $29.71 $34.17 $39.30 $45.20 $52.00
Total Distributions to CNX $42.39 $59.92 $80.08 $103.27 $129.94
Guidance: Natural Gas Hedging – Gain/Loss Projections
101
Note: Forward market prices are as of 2/16/2018. Hedged volumes and prices are as of 2/20/2018. Anticipated hedging activity is not included in projections.
(1) January and February are settled prices.
(1) (1)
Q1 2018 CY2018 CY2019
Hedged Volumes Hedged Forward Forecasted Gain/(Loss) Hedged Volumes Hedged Forward Forecasted Gain/(Loss)
(000 MMBtu) Price Market ($/MMBtu) ($ in 000's) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's)
($/MMBtu)
NYMEX 93,150 $2.98 $2.98 ($0.00) ($274) 377,775 $2.98 $2.78 $0.20 $74,668
Basis:
DOM South (DOM) 8,100 ($0.61) ($0.57) ($0.04) ($351) 30,100 ($0.60) ($0.67) $0.07 $2,030
ETNG Cascade Creek TZ5 0 $0.00 $1.10 $0.00 $0 0 $0.00 $0.45 $0.00 $0
ETNG Mainline 0 $0.00 $0.55 $0.00 $0 0 $0.00 $0.23 $0.00 $0
Chicago 0 $0.00 $0.28 $0.00 $0 0 $0.00 ($0.12) $0.00 $0
TCO Pool (TCO) 9,000 ($0.27) ($0.25) ($0.02) ($164) 36,500 ($0.27) ($0.26) ($0.01) ($239)
Michcon (NMC) 3,600 ($0.03) ($0.11) $0.08 $282 14,448 ($0.03) ($0.21) $0.18 $2,609
TETCO ELA (TEB) 1,350 ($0.09) ($0.09) ($0.00) ($2) 5,475 ($0.09) ($0.09) $0.00 $27
TETCO WLA (TWB) 0 $0.00 ($0.06) $0.06 $0 0 $0.00 ($0.08) $0.00 $0
TETCO M3 (TMT) 6,145 $0.09 $2.33 ($2.24) ($13,762) 19,895 ($0.05) $0.23 ($0.28) ($5,547)
TETCO M2 (BM2) 47,925 ($0.60) ($0.52) ($0.08) ($3,827) 191,613 ($0.60) ($0.67) $0.07 $13,173
Total Financial basis 76,120 ($17,824) 298,030 $12,053
Total Projected Gain/(Loss) ($18,098) $86,721
CY2019 CY2020
Hedged Volumes Hedged Forward Forecasted Gain/(Loss) Hedged Volumes Hedged Forward Forecasted Gain/(Loss)
(000 MMBtu) Price Market ($/MMBtu) ($ in 000's) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's)
($/MMBtu)
NYMEX 341,275 $2.84 $2.76 $0.09 $29,256 231,495 $2.87 $2.77 $0.10 $22,455
Basis:
DOM South (DOM) 32,850 ($0.58) ($0.59) $0.00 $71 16,470 ($0.59) ($0.60) $0.01 $105
ETNG Cascade Creek TZ5 0 $0.00 $0.45 $0.00 $0 0 $0.00 $0.45 $0.00 $0
ETNG Mainline 0 $0.00 $0.23 $0.00 $0 0 $0.00 $0.23 $0.00 $0
Chicago 0 $0.00 ($0.27) $0.00 $0 0 $0.00 ($0.20) $0.00 $0
TCO Pool (TCO) 43,800 ($0.33) ($0.37) $0.04 $1,911 32,940 ($0.35) ($0.43) $0.08 $2,530
Michcon (NMC) 20,683 ($0.13) ($0.31) $0.18 $3,622 24,553 ($0.13) ($0.25) $0.13 $3,075
TETCO ELA (TEB) 7,300 ($0.09) ($0.09) $0.00 $0 7,320 ($0.09) ($0.08) ($0.01) ($49)
TETCO WLA (TWB) 7,300 ($0.08) ($0.09) $0.01 $61 7,320 ($0.08) ($0.09) $0.00 $32
TETCO M3 (TMT) 4,563 $0.07 $0.03 $0.04 $187 0 $0.00 ($0.02) $0.00 $0
TETCO M2 (BM2) 83,950 ($0.59) ($0.59) ($0.01) ($431) 42,090 ($0.58) ($0.61) $0.03 $1,297
Total Financial basis 200,445 $5,421 130,693 $6,990
Total Projected Gain/(Loss) $34,676 $29,444
Asset Portfolio Overview
102
Marcellus Utica
SWPA WV CPA OH Total SWPA WV CPA OH Total
Total Net Acres 117,000 95,000 303,000 16,000 531,000 157,000 135,000 235,000 125,000 652,000
Net Developed Acres 21,600 5,900 6,100 200 33,800 100 0 400 20,000 20,500
Net Undeveloped Locations 582 190 1,249 102 2,123 669 511 1,011 161 2,394
PDP 194 42 56 1 293 1 0 3 114 118
2017 Exit Rate (Bcfe/d) 0.494 0.178 0.039 0 0.711 0.004 0 0.046 0.399 0.449
Note: 2017 Exit Rate is the average production per day for the month of December
Virginia CBM
▪ ~270,000 contiguous acres, 100% WI
▪ 88% HBP, 87.5% NRI
▪ ~4,000 PDPs at 165 MMcf/d
0
1
2
3
4
Capital E
ffic
iency (
Mcfe
/$)(
1)
Shirley-Pennsboro Wells
Shirley-Pennsboro: Asset and Development Overview
(1) Assumes ethane extraction for forecasts and type curves.
(2) CNX operated wells, legacy JV construction and drilling capital included in capital efficiency.
103
▪ CNX’s future development represents a 47% increase in capital efficiency (Mcfe/$)
compared to legacy wells
- 28% increase in EUR/1000’ driven by enhanced stimulated reservoir design and
optimization of inter-lateral spacing
- EUR/1,000’: Shirley 3.0 Bcfe; Pennsboro 2.6 Bcfe
- BTAX IRR at $2.50 realized price: Shirley 38%; Pennsboro 35%
- 18% decrease in fully-loaded D&C capital per lateral foot compared to the
legacy JV wells
▪ Reduced capital driven by operational excellence:
- Achieved record completion speed of 2,250 ft/day or 10+ stages in a 24 hour
period
- Achieved record drill-out speed of 8,400 ft/day
▪ The Shirley-Pennsboro field contains 50+ future wells that will be part of the core
development plan
▪ Expected to add $22-$24 million of pro forma 2018 EBITDA for CNXM growing to
$40-$50 million in 2020E
Shirley-Pennsboro – Capital Efficiency
Legacy JV CNX(2) CNX Future Development
System Operating Area
1.90 Mcfe/$
2.33 Mcfe/$
2.79 Mcfe/$
Shirley
Pennsboro
Leading Capital Efficiency in SWPA Marcellus
Note: Peer data from company filings.
104
-
0.500
1.000
1.500
2.000
2.500
3.000
3.500
CNX EQTC
apital E
ffic
iency (
Mcfe
/$)
SWPA Capital Efficiency
CompanyEUR
(Bcf/1000’)Well Capital
Lateral
LengthTotal EUR
Capital
Efficiency
(Mcfe/$)
CNX 2.8 $8,300,000 9,500 26.79 3.23
Peer 1 2.4 $9,050,000 9,500 22.80 2.52
Peer 1
WV Region Overview: Shirley-Pennsboro and East
105
▪ Strong well results from enhanced completion techniques
▪ High BTU area that supplies liquids to portfolio
WV Shirley-Penns Marcellus Utica
Undeveloped Net Locations 85 77
EUR (Bcfe/1000’) 3.0 2.8
Total NRI 85% 87%
Total PDPs 42 -
Net Current Production (Bcfe/d) 0.178 -
WV East Marcellus Utica
Undeveloped Net Locations 105 434
EUR (Bcfe/1000’) 2.4 2.8
Total NRI 90% 88%
Total PDPs - -
Net Current Production (Bcfe/d) - -
▪ Utica delineation can unlock tremendous value based
on acreage held
Asset Region 4: Ohio Overview
106
▪ Joint Venture with Hess
OH Wet Marcellus Utica
Undeveloped Net Locations - 135
EUR (Bcfe/1000’) - 2.1
Total NRI - 42%
Total PDPs -59 (Hess)
31 (CNX)
Net Current Production (Bcfe/d) - 0.086
OH Dry Marcellus Utica
Undeveloped Net Locations 100 26
EUR (Bcf/1000’) - 3.2
Total NRI 85% 85%
Total PDPs 1 24
Net Current Production (Bcfe/d) - 0.313
▪ Fueling current growth with four pads remaining
▪ Increased type curves and returns driven by wider spacing
▪ OH Dry Utica Locations decreased due to Jefferson County
sale in Q1 2017, increased spacing assumptions, and
increased activity in 2017
Peer Benchmarking: Ohio Region - Dry
Note: Peer data from company filings.
107
CompanyEUR
(Bcf/1000’)Well Capital
Lateral
Length
Total EUR
(BCF)
Capital
Efficiency
(Mcfe/$)
CNX 3.2 $10,500,000 9,000 28.71 2.73
Peer 1 2.2 $9,056,250 9,000 19.80 2.19
Peer 2 2.6 $9,990,000 9,000 23.40 2.34
Peer 3 2.1 $10,832,000 9,000 18.90 1.75
-
0.500
1.000
1.500
2.000
2.500
3.000
CNX Eclipse Gulfport EQTC
apital E
ffic
iency (
$/M
cfe
)
Ohio Dry Utica Capital Efficiency
Peer 1 Peer 2 Peer 3
SWPA Central Modeling Inputs and Economics
108
Gross EUR (bcfe) 26.8
Inlet BTU 1075
Outlet BTU N/A
WI / NRI (%) 100% / 87%
Net Locations ~391
Wells Online (12/31/17) 182
Reserves Detail
Interest / Net Locations
IP (MMcf/d) (3 mo. flat) 15.9
Decline 57%
B-factor 1.5
EUR/1000' (Bcfe) 2.8
Lateral Length 9500'
Wells Per Pad 6
NGL Yield (Bbl/MMcf) -
CND Yield (Bbl/MMcf) -
Well Capital ($MM) $8.3
CNXM Sponsor Capital ($MM) $0.87
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Net Gathering ($/Mcf) $0.24
NGL OpEx ($/Bbl) -
CND OpEx ($/Bbl) -
Assumptions
Gross EUR (bcfe) 26.8
Inlet BTU 1020
Outlet BTU N/A
WI / NRI (%) 100% / 89%
Net Locations ~438
Wells Online (12/31/17) 1
Reserves Detail
Interest / Net Locations
IP (MMcf/d) (11 mo. flat) 17.9
Decline 60%
B-factor 1.2
EUR/1000' (Bcfe) 3.2
Lateral Length 8,500'
Wells Per Pad 6
Well Capital ($MM) $14.3
CNXM Sponsor Capital ($MM) $0.58
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.16
Assumptions
Price 9,500'
$2.00 45%
$2.50 75%
$3.00 113%
BTAX IRR%
Price 8,500'
$2.00 37%
$2.50 64%
$3.00 95%
BTAX IRR%
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
SWPA Central Marcellus Type Curve (2.8 Bcf/1000')
9500' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
SWPA Central Utica Type Curve (3.2 Bcf/1000')
8500' LL
(1) Assuming 9,500 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 8,500 ft lateral @ 1,200 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
(4) Escalation of 2.5%/year applied to gathering and compressor fees per contract
(5) Tier I Net Comp. fee of $0.040 applied after 1 year (Marcellus) (18 mo. for Utica) & Tier II (Marcellus only) additional fee of $0.040 applied after 3 years
(6) Assuming NGL & CND pricing at $25/bbl & $45/bbl
(7) See NGL and CND assumptions on type curve data file located at http://investors.cnx.com/events-and-presentations/events/2018.
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
SWPA Central Marcellus Type Curve (2.8 Bcf/1000’)
SWPA Central Utica Type Curve (3.2 Bcf/1000’)
SWPA Greater Modeling Inputs and Economics
109
Gross EUR (bcfe) 25.8
Inlet BTU 1144
Outlet BTU 1081
WI / NRI (%) 100% / 91%
Net Locations ~191
Wells Online (12/31/17) 12
Reserves Detail
Interest / Net Locations
IP (MMcf/d) (3 mo. flat) 11.8
Decline 52%
B-factor 1.59
EUR/1000' (Bcfe) 2.7
Lateral Length 9500'
Wells Per Pad 6
NGL Yield (Bbl/MMcf) 23.6
CND Yield (Bbl/MMcf) -
Well Capital ($MM) $8.3
CNXM Sponsor Capital ($MM) $0.22
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.07
Net Gathering ($/Mcf) $0.28
Processing ($/Mcf) $0.58
NGL OpEx ($/Bbl) $6.25
CND OpEx ($/Bbl) -
Assumptions
Gross EUR (bcfe) 25.1
Inlet BTU 1023
Outlet BTU N/A
WI / NRI (%) 100% / 91%
Net Locations ~231
Wells Online (12/31/17) 0
Reserves Detail
Interest / Net Locations
IP (MMcf/d)(7 mo. @7.5% exp de.) 18.1
Decline 61%
B-factor 1.2
EUR/1000' (Bcfe) 3.0
Lateral Length 8,500'
Wells Per Pad 6
Well Capital ($MM) $14.3
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.23
Assumptions
Price 9,500'
$2.00 26%
$2.50 47%
$3.00 72%
BTAX IRR%
Price 8,500'
$2.00 33%
$2.50 59%
$3.00 91%
BTAX IRR%
0
100,000
200,000
300,000
400,000
500,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
SWPA Greater Marcellus Type Curve (2.7 Bcfe/1000')
9500' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
SWPA Greater Utica Type Curve (3.0 Bcf/1000')
8500' LL
(1) Assuming 9,500 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 8,500 ft lateral @ 1,200 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
(4) Escalation of 2.5%/year applied to gathering fees per contract
(5) Assuming NGL & CND pricing at $25/bbl & $45/bbl
(6) See NGL and CND assumptions on type curve data file located at http://investors.cnx.com/events-and-presentations/events/2018.
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
SWPA Greater Marcellus Type Curve (2.7 Bcfe/1000’)
SWPA Greater Utica Type Curve (3.0 Bcf/1000’)
WV SHR/PENS Modeling Inputs and Economics
110
Gross EUR (bcfe) 22.2
Inlet BTU 1260
Outlet BTU 1126
WI / NRI (%) 100% / 85%
Net Locations ~85
Wells Online (12/31/17) 42
Reserves Detail
Interest / Net Locations
IP (MMcf/d) 14.5
Decline 69%
B-factor 1.65
EUR/1000' (Bcfe) 2.8
Lateral Length 8,000'
Wells Per Pad 6
NGL Yield (Bbl/MMcf) 62.6
CND Yield (Bbl/MMcf) 25-7
Well Capital ($MM) $7.9
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.10
Net Gathering ($/Mcf) $0.61
Processing ($/Mcf) $0.51
NGL OpEx ($/Bbl) $4.75
CND OpEx ($/Bbl) $5.25
Assumptions
Gross EUR (bcfe) 19.7
Inlet BTU 1030
Outlet BTU N/A
WI / NRI (%) 100% / 87%
Net Locations ~77
Wells Online (12/31/17) 0
Reserves Detail
Interest / Net Locations
IP (MMcf/d)(10 mo. @25% exp de.) 17.8
Decline 63%
B-factor 1.2
EUR/1000' (Bcfe) 2.8
Lateral Length 7,000'
Wells Per Pad 6
Well Capital ($MM) $14.4
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.23
Assumptions
Price 8,000'
$2.00 29%
$2.50 46%
$3.00 65%
BTAX IRR%
Price 7,000'
$2.00 14%
$2.50 30%
$3.00 50%
BTAX IRR%
0
10,000
20,000
30,000
40,000
50,000
0
100,000
200,000
300,000
400,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Ga
s P
rod
uctio
n (
Mcf/
m
Months After TIL
WV SHR/PENS Marcellus Type Curve (2.8 Bcfe/1000')
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
WV SHR/PENS Utica Type Curve (2.8 Bcf/1000')
7000' LL
(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
(4) Escalation of 2.5%/year applied to gathering fees per contract
(5) Assuming NGL & CND pricing at $25/bbl & $45/bbl
(6) See NGL and CND assumptions on type curve data file located at http://investors.cnx.com/events-and-presentations/events/2018.
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
WV SHR/PENS Marcellus Type Curve (2.8 Bcfe/1000’)
WV SHR/PENS Utica Type Curve (2.8 Bcf/1000’)
WV East Modeling Inputs and Economics
111
Gross EUR (bcfe) 19.4
Inlet BTU 1230
Outlet BTU 1113
WI / NRI (%) 100% / 90%
Net Locations ~105
Wells Online (12/31/17) 0
Reserves Detail
Interest / Net Locations
IP (MMcf/d) 13.5
Decline 69%
B-factor 1.65
EUR/1000' (Bcfe) 2.5
Lateral Length 8,000'
Wells Per Pad 6
NGL Yield (Bbl/MMcf) 54
CND Yield (Bbl/MMcf) 7-2
Well Capital ($MM) $7.9
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.10
Net Gathering ($/Mcf) $0.61
Processing ($/Mcf) $0.51
NGL OpEx ($/Bbl) $4.75
CND OpEx ($/Bbl) $5.25
Assumptions
Gross EUR (bcfe) 19.7
Inlet BTU 1030
Outlet BTU N/A
WI / NRI (%) 100% / 88%
Net Locations ~434
Wells Online (12/31/17) 0
Reserves Detail
Interest / Net Locations
IP (MMcf/d)(10 mo. @25% exp de.) 17.8
Decline 63%
B-factor 1.2
EUR/1000' (Bcfe) 2.8
Lateral Length 7,000'
Wells Per Pad 6
Well Capital ($MM) $14.4
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.23
Assumptions
Price 8,000'
$2.00 18%
$2.50 30%
$3.00 46%
BTAX IRR%
Price 7,000'
$2.00 15%
$2.50 31%
$3.00 52%
BTAX IRR%
0
10,000
20,000
30,000
40,000
50,000
0
100,000
200,000
300,000
400,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
WV East Marcellus Type Curve (2.5 Bcfe/1000')
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
WV East Utica Type Curve (2.8 Bcf/1000')
7000' LL
(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
(4) Escalation of 2.5%/year applied to gathering fees per contract
(5) Assuming NGL & CND pricing at $25/bbl & $45/bbl
(6) See NGL and CND assumptions on type curve data file located at file located at http://investors.cnx.com/events-and-presentations/events/2018.
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
WV East Marcellus Type Curve (2.5 Bcfe/1000’)
WV East Utica Type Curve (2.8 Bcf/1000’)
CPA South Modeling Inputs and Economics
112
Gross EUR (bcfe) 16.1
Inlet BTU 1040
Outlet BTU N/A
WI / NRI (%) 100% / 87%
Net Locations ~634
Wells Online (12/31/17) 47
Reserves Detail
Interest / Net Locations
IP (MMcf/d) 13.6
Decline 69%
B-factor 1.65
EUR/1000' (Bcfe) 1.8
Lateral Length 9,000'
Wells Per Pad 6
NGL Yield (Bbl/MMcf) -
CND Yield (Bbl/MMcf) -
Well Capital ($MM) $7.4
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Net Gathering ($/Mcf) $0.37
NGL OpEx ($/Bbl) -
CND OpEx ($/Bbl) -
Assumptions
Gross EUR (bcfe) 24.5
Inlet BTU 1010
Outlet BTU N/A
WI / NRI (%) 100% / 87%
Net Locations ~513
Wells Online (12/31/17) 3
Reserves Detail
Interest / Net Locations
IP (MMcf/d)(14 mo. flat) 21.5
Decline 74%
B-factor 1.2
EUR/1000' (Bcfe) 3.5
Lateral Length 7,000'
Wells Per Pad 4
Well Capital ($MM) $13.1
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.23
Assumptions
Price 9,000'
$2.00 18%
$2.50 33%
$3.00 50%
BTAX IRR%
Price 7,000'
$2.00 58%
$2.50 104%
$3.00 157%
BTAX IRR%
0
100,000
200,000
300,000
400,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
CPA South Marcellus Type Curve (1.8 Bcf/1000')
9000' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
CPA South Utica Type Curve (3.5 Bcf/1000')
7000' LL
(1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
(4) Escalation of 2.5%/year applied to gathering fees per contract
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
CPA South Marcellus Type Curve (1.8 Bcf/1000’)
CPA South Utica Type Curve (3.5 Bcf/1000’)
CPA North Modeling Inputs and Economics
113
Gross EUR (bcfe) 13.1
Inlet BTU 1012
Outlet BTU N/A
WI / NRI (%) 100% / 86%
Net Locations ~615
Wells Online (12/31/17) 9
Reserves Detail
Interest / Net Locations
IP (MMcf/d) 11.1
Decline 69%
B-factor 1.65
EUR/1000' (Bcfe) 1.5
Lateral Length 9,000'
Wells Per Pad 6
NGL Yield (Bbl/MMcf) -
CND Yield (Bbl/MMcf) -
Well Capital ($MM) $7.4
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.05
Net Gathering ($/Mcf) $0.36
NGL OpEx ($/Bbl) -
CND OpEx ($/Bbl) -
Assumptions
Gross EUR (bcfe) 24.5
Inlet BTU 1010
Outlet BTU N/A
WI / NRI (%) 100% / 86%
Net Locations ~498
Wells Online (12/31/17) 0
Reserves Detail
Interest / Net Locations
IP (MMcf/d)(14 mo. flat) 21.5
Decline 74%
B-factor 1.2
EUR/1000' (Bcfe) 3.5
Lateral Length 7,000'
Wells Per Pad 4
Well Capital ($MM) $13.1
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.23
Assumptions
Price 9,000'
$2.00 10%
$2.50 19%
$3.00 31%
BTAX IRR%
Price 7,000'
$2.00 56%
$2.50 100%
$3.00 151%
BTAX IRR%
0
100,000
200,000
300,000
400,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
CPA North Marcellus Type Curve (1.5 Bcf/1000')
9000' LL
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
CPA North Utica Type Curve (3.5 Bcf/1000')
7000' LL
(1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
(4) Escalation of 2.5%/year applied to gathering fees per contract
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
CPA North Utica Type Curve (3.5 Bcf/1000’)
CPA North Marcellus Type Curve (1.5 Bcf/1000’)
Ohio Modeling Inputs and Economics
114
Gross EUR (bcfe) 17.1
Inlet BTU 1170
Outlet BTU 1098
WI / NRI (%) 50% / 42%
Net Locations ~135
Wells Online (12/31/17) 90
Reserves Detail
Interest / Net Locations
IP (MMcf/d) 11.9
Decline 62%
B-factor 1.38
EUR/1000' (Bcfe) 2.1
Lateral Length 8,000'
Wells Per Pad 4
NGL Yield (Bbl/MMcf) 36.8
CND Yield (Bbl/MMcf) 14-3
Well Capital ($MM) $8.0
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $1,000
LOE ($/Mcf) $0.19
Net Gathering/Processing ($/Mcf) $0.94
NGL OpEx ($/Bbl) $5.00
CND OpEx ($/Bbl) $5.75
Assumptions
Gross EUR (bcfe) 28.8
Inlet BTU 1030
Outlet BTU N/A
WI / NRI (%) 100% / 85%
Net Locations ~26
Wells Online (12/31/17) 24
Reserves Detail
Interest / Net Locations
IP (MMcf/d)(10 mo. @25% exp. de.) 22.5
Decline 60%
B-factor 1.37
EUR/1000' (Bcfe) 3.2
Lateral Length 9,000'
Wells Per Pad 4
Well Capital ($MM) $10.5
CNXM Sponsor Capital ($MM) -
Fixed Cost ($/mo./well) $500
LOE ($/Mcf) $0.04
Net Gathering ($/Mcf) $0.22
Assumptions
Price 8,000'
$2.00 19%
$2.50 33%
$3.00 50%
BTAX IRR%
Price 9,000'
$2.00 74%
$2.50 126%
$3.00 189%
BTAX IRR%
0
10,000
20,000
30,000
0
100,000
200,000
300,000
400,000
0 12 24 36 48
NG
L/C
ND
Pro
du
ctio
n (
BB
L/m
on
th)
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
OH Wet Type Curve (2.1 Bcfe/1000')
Gas
NGL
CND
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
0 12 24 36 48
Ga
s P
rod
uctio
n (
Mcf/
m)
Months After TIL
OH Dry Utica Type Curve (3.2 Bcf/1000')
9000' LL
(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing
(2) Assuming 9,000 ft lateral @ 1,350 ft inter-lateral spacing
(3) Escalation not applied to gas pricing, capex, and LOE
Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units.
OH Wet Utica Type Curve (2.1 Bcfe/1000’)
OH Dry Utica Type Curve (3.2 Bcf/1000’)
Half Cycle and Full Cycle Modeling Assumptions
115
Assumption Half Cycle Full Cycle Half Cycle
Gas Price - $/MMBtu $2.50 Flat $2.50 Flat See Regional Detail
NGL Price - $/Bbl $25.00 Flat $25.00 Flat See Regional Detail
Condensate Price - $/Bbl $45.00 Flat $45.00 Flat See Regional Detail
Hedging Excluded Excluded Excluded
Working Interest See Regional Detail See Regional Detail See Regional Detail
Net Revenue Interest See Regional Detail See Regional Detail See Regional Detail
Well Capital See Regional Detail See Regional Detail See Regional Detail
Midstream See Regional Detail See Regional Detail See Regional Detail
Water Infrastructure Excluded $525,000 Per Well Excluded
Land Excluded $700,000 Per Well Excluded
Fixed Cost ($/mo./well) See Regional Detail See Regional Detail See Regional Detail
LOE $/Mcf See Regional Detail See Regional Detail See Regional Detail
Net Gathering ($/Mcf) - Adjusted for CNXM
See Regional Detail See Regional Detail See Regional Detail
NGL OpEx ($/Bbl) See Regional Detail See Regional Detail See Regional Detail
CND OpEx ($/Bbl) See Regional Detail See Regional Detail See Regional Detail
Utilized Firm Transportation Excluded$0.19/Mcf
5 yr weighted Avg.Excluded
General and Administrative Costs Excluded $975,000 Per Well Excluded
Production Taxes
(Severance & Ad Valorem, PA
Impact Fee)
Applied Per State Applied Per State Applied Per State
Ow
ners
hip
Opera
ting E
xpense
CapE
x P
er
Well
Portfolio Single Well
Realiz
ed P
ricin
g
CNX Midstream Partners Governance
116
Public41.9mm Common
Units
CNX Midstream GP LLC
The “General Partner”
Incentive Distribution Rights
CNX Gathering LLC
100%
NYSE: CNX
64.6% LP Interest
2% GP Interest
Anchor Systems
(Development Co. 1)
Growth Systems
(Development Co. 2)
Additional Systems
(Development Co. 3)
33.4% LP Interest
100% 5% GP Interest 5% GP Interest
95% LP Interest
NYSE: CNXM
100%
Post-Spin Company Names and Stock Trading Symbols
117
Effective November 28, 2017, the company known as CONSOL Energy Inc. (NYSE: CNX) separated its gas business (GasCo or
RemainCo) and its coal business (CoalCo or SpinCo) into two independent, publicly traded companies by means of a separation
of CoalCo from RemainCo.
▪ The gas business, CNX Resources Corporation (RemainCo, GasCo or CNX), continues to be listed on the NYSE, retaining the ticker
symbol "CNX". Information regarding CNX and its natural gas business is available at www.cnx.com.
▪ Following the closing of CNX’s purchase of Noble Energy’s 50% interest in CNX Gathering LLC, which occurred on January 3, 2018, the
master limited partnership that was named CONE Midstream Partners, LP has changed its name to CNX Midstream Partners LP and
now trades under a new ticker symbol: “CNXM”. CNX indirectly owns 100% of the general partnership interests of CNX Midstream
Partners LP as well as all of its incentive distribution rights. Information regarding CNX Midstream Partners LP is available at
www.cnxmidstream.com.
▪ The coal business, CONSOL Energy Inc. (SpinCo, CoalCo or CONSOL), is listed on the NYSE under the ticker symbol: "CEIX".
CoalCo owns, operates and develops coal assets, including the Pennsylvania Mining Complex, the Baltimore Marine Terminal, and
approximately one billion tons of greenfield coal reserves. Information regarding the new CONSOL Energy and its coal business is
available at www.consolenergy.com.
▪ The master limited partnership that was named CNX Coal Resources LP (NYSE: CNXC) has changed its name to CONSOL Coal
Resources LP and trades on the NYSE under a new ticker symbol: "CCR". CONSOL owns 100% of the general partner of CONSOL
Coal Resources LP (representing a 1.7% general partner interest), as well as all of the incentive distribution rights and the common and
subordinated interests in CNX Coal Resources LP that were owned by CNX prior to the spin-off. Information regarding CONSOL Coal
Resources LP is available at www.ccrlp.com.