Earnings ResultsFourth Quarter 2019
January 30, 2020
Cautionary Language
2
For purposes of this presentation: (i) “CNX”, “CNX Resources”, “Company”, “we” and “our” refer to CNX Resources Corporation (ii) “CNXM” refers to CNXM Midstream Partners LP; and (iii) “CNXM GP” refers to CNX
Midstream GP LLC
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, 2018 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; operational risks relating to midstream facilities, pipeline systems, drilling natural gas wells, access to key services and equipment, access to adequate water sources 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 and potential acquisitions or
divestitures, 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, projected EBITDAX, projected free cash flow and other projected non-GAAP metrics for fiscal or quarterly periods
in 2020 or beyond, for CNX or CNXM, CNX 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 its inability to calculate projected operating income 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.
Trademarks. CNX owns or has rights to various trademarks, service marks and trade names that it uses in connection with the operation of its business. This presentation also contains trademarks, service marks
and trade names of third parties, which are the property of their respective owners. CNX’s use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and
does not imply, a relationship with CNX or an endorsement or sponsorship by or of CNX. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appear without the
®, TM or SM symbols, but such references are not intended to indicate, in any way, that CNX will not assert, to the fullest extent under applicable law, its rights or the right of the applicable licensor to these
trademarks, service marks and trade names.
Not an Offer. 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.
3
CNX Highlights
CNXM Simplified Structure
◼ IDR elimination transaction simplifies capital structure
◼ Reduces CNXM’s cost of capital
◼ Aligns sponsor and public unitholder economic interests
Operational Excellence
◼ Beating guidance
◼ Strong well results
◼ Low operating costs
Proactive Management
◼ Best-in-class hedge book
◼ Significant cost reductions
◼ Flexible business plans drive decision-making and new guidance
Strong Balance Sheet
◼ Low firm transportation (FT) obligations and limited processing commitments
◼ Leverage ratios going down
◼ 2022 debt maturities manageable
Best-in-Class Results and Go-
Forward Strengths
◼ $250 million of currently expected FCF in 2020
◼ $300 million of currently expected EBITDA for CNXM in 2021
◼ Optionality to ramp up production or maintain slower growth profile
Note: CNX is unable to provide a reconciliation of projected financial results contained in presentation, including FCF, EBITDA, adjusted EBITDAX, fully burdened cash costs
and other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP
projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.
Competitive Advantages and Philosophy Drive Investment Thesis
4
ADVANTAGES
Hedge book
Minimal FT
Large stacked-
pay inventory
Midstream control
Water systems
~100,000 Core
SWPA Marcellus
acres
Marketing
Strategy
Cost
Structure
Asset
Portfolio
Strong cash
margins
Blending
strategy
CREDIBILITY
Doing what we say we’re going to do
Shares
outstandingProduction &
EBITDAX/share
Leverage ratio
Sold Appalachian acreage Spun coal business
CONSISTENT
PHILOSOPHY
Stacked pay
gathering system
CPA/SWPA Utica
Marcellus buildout CNXM
Water infrastructureUtica blending
strategy
Share repurchases
Investments in high rate of return opportunities
(over 20% hurdle rate)
Core SWPA
Marcellus inventory
1
2
3
Long-term NAV per share growth
Disciplined decision making
Flexibility
Capital allocation process drives:
5
Excelling Through the Downturn
IDR Transaction Puts CNXM in Right Capital Structure1
Beat Guidance Across the Board in 20192
Forecasting $250 million in FCF in 20203
Hedge Book Protects the Company for Several Years4
Forecasting $250 million in FCF in 20215
Strong 2020 and 2021 Sets the Company up for an Even Better 20226
✓
✓
✓
✓
✓
✓Note: CNX is unable to provide a reconciliation of projected financial results contained in presentation, including FCF, adjusted EBITDAX, fully burdened cash costs and
other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected
metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.
Milestones
6
2017 2018 2019 2020
▪ CNXM acquires Shirley Penns
assets with significant long term
MVC levels (+$430mm revenue}
▪ Upsize credit facility to $600mm
▪ $400mm 8 year notes offering at
6.5%
▪ Establishes finance platform to de-
risk business plan, and eliminate
capital markets needs for baseline
plan
▪ Significant investment year:
$316mm of capital expenditures
▪ Installing operating leverage for
long term FCF generation
✓ FCF generation and continue growing
returns to unitholders
✓ Organic build out of the next wave of growth
projects
✓ Pursue midstream investments and M&A, on
both an independent basis and jointly with
sponsor
▪ Assisted Noble in two secondary
offerings to relieve overhang
▪ Increases public float 2x
2014 2015 2016
CNNX IPO, September
2014CNNX acquires remaining
25% interest in Anchor System
CNX acquires remaining 50% GP
interest from Noble for ~$300mm
▪ CONE renamed CNX Midstream
Partners
▪ CNX agrees to $385mm in well
commitments and dedicates
63,000 new acres to CNXM.
▪ Eliminates adverse, non-
operational general partner from
MLP
GP Acquisition & Enhanced
Commercial Agreement
Shirley-Penns Drop Down &
Finance Platform Established
HG Asset Exchange Agreement
▪ Additional +$145mm minimum
revenue commitments
▪ CNX negotiates 12 well
commitment from HG Energy
▪ Additional 16,100 Utica acres
dedicated to CNXM
▪ Cash flows from minimum revenue
commitments alone support 15%
distribution growth through 2022
CNXM Secondary Offerings
SWPA System Expansion
IDRs exchanged for common
equity, class B Units, and
deferred cash
▪ Immediately DCF accretive to LP
unitholders
IDR Elimination Transaction
Business Optionality
7
Incentive Distribution Rights (IDR) Transaction Overview
The incentive distribution rights and economic general
partner interest in CNXM owned by CNX were exchanged for
the following:
▪ 26 million common LP Units
▪ 3 million Class B units, will not receive or accrue distributions
until 1/1/22, at which time they convert into common units
▪ $135 million cash payable in three installments:
─ $50M on 12/31/2020
─ $50M on 12/31/2021
─ $35M on 12/31/2022
✓Immediately accretive to DCF per LP
✓Simplifies capital structure
✓Reduces cost of capital
✓Aligns sponsor and public unitholder economic interests
✓CNX owns 53.1%(1) LP interest
Transaction Overview Pro Forma Structure
Public
Common
Units42.1mm Common
Units
46.9% limited
partner interest
Non-economic general
partner interest and 53.1%(1)
limited partner interest
100%
Additional Systems
DevCo III
5% GP
InterestAnchor Systems
DevCo I
(1) Excludes 3 million new CNXM Class B units, which will not receive or accrue distributions until January 1, 2022, at which time they will automatically convert into
CNXM common units.
($ in millions) 2019 2020E 2021E 2022E 2023E
Targeted Distributions $63 $86 $99 $121 $140
IDR Cash Consideration $50 $50 $35
Total $63 $136 $149 $156 $140
$0
$50
$100
$150
$200
$250
$300
2015 2016 2017 2018 2019 2020E 2021E
$ in m
illio
ns
CNXM Net EBITDA
8
CNXM is Crucial to CNX’s Success
CNXM Adjusted EBITDA 2015-2021E
$135 million cash,
payable $50mm on
12/31/20, $50mm on
12/31/21, $35mm
12/31/22
Note: The historical and projected non-GAAP financial measures in the chart above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP
Reconciliation“ in the CNX Midstream Partners Q4 2019 slide presentation, which can be found on the investor relations section of their website:
www.cnxmidstream.com.
Following IDR
Elimination Transaction,
CNX now owns 47.7
million common units.
The transaction also
includes 3 million Class
B units that will convert
to CNXM common units
on January 1, 2022
Strong Full Year 2019 Financial and Operational Performance
9
Actuals 2019 Guidance Actuals vs.
($ in millions) 2019 Low High Avg. Midpoint Guidance
Production Volumes (Bcfe) 539 530 540 535 4
Adjusted EBITDAX $772 $745 $765 $755 $17
Total E&P Capital $876 $890 $915 $903 ($27)
▪ Finished 2019 with strong operational execution
- Drilled 66 wells, completed 50 wells, and turned-in-line 51 wells
- Included Pennsylvania state record for longest lateral at 19,609 ft for the
RHL71B Marcellus Shale well
- The average lateral length for this 6-well pad was 15,744 feet and D&C capital
of approximately $800 per foot
▪ Nearly free cash flow (FCF) neutral in 2019 when including the $45 million in
assets sales we completed
▪ Constructed critical water infrastructure projects expected to drive water
efficiencies for years to come
Actuals > Guidance
2019
Note: The Non-GAAP financial measures in the table above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation."
2019 Capital and Operations Improvements
10
Capital Continuous Improvements
▪ Completion design optimization
▪ Cycle time efficiencies
▪ Fuel cost savings of frac crews using natural gas vs. diesel
▪ Service cost reductions
▪ Utica well cost improvements
▪ Reduction of pad construction costs through multiple trips to a
pad
One-Time Infrastructure Investments Driving Future
Efficiencies
▪ SWPA water infrastructure projects
- Richhill water line – increased water supply
- Large water storage facilities – increased water storage
capacity
▪ Wadestown initial midstream buildout
Operations Continuous Improvements
▪ Decreased water disposal through increased reuse
▪ Combined midstream and upstream production teams
▪ Increased integrated real time operations center (IRTOC) remote
operations
▪ Reduced repair and maintenance
▪ Gathering optimization improvements
SWPA Marcellus: Increased Results and Efficiencies
11
Ohio River Water Line (to Richhill)
▪ The buildout was completed in Q3 2019 and the water line
is currently in-service
▪ Supplies an uninterruptible water source into the Richhill
operating area within Southwest Pennsylvania that helps
support the Evolution frac crew
▪ Marcellus development is concentrated in the Richhill area
▪ 2019 RHL wells continue to perform above the current type curve and
existing RHL wells
▪ Capital was lowered on 2019 TIL’s as a result of stage
spacing optimization but resulted in increased performance driving
well returns higher
▪ Optimized drawdown continues to be performed with lower production
decline once line pressure is reached
▪ 2020 and 2021 development programs includes 20 RHL Marcellus TIL’s
each year(1) 2018 TILs comprised of 8 wells off the RHL 22 pad
(2) 2019 TILs comprised of 17 wells off the RHL 11, 27, and 28 pads
-
1.0
2.0
3.0
4.0
5.0
6.0
- 50 100 150 200 250 300 350 400 450 500 550
90
00
' Norm
aliz
ed
Cum
ula
tive
(B
cf)
Days
Richhill (RHL) Marcellus - 2018 vs. Now
Current RHL TC 2018 TILs 2019 TILs
SWPA Blending Strategy in Full Swing
12
Damp Marcellus to Dry Outlets
▪ Maximize NAV by drilling high ROR Marcellus pads
with enough Utica to blend into dry outlet
▪ Only completing enough to blend over the next several
years
- 1 SWPA dry Utica pad expected to TIL in both 2020 and
2021
- Blending economics support drilling
▪ Just one dry Utica well needed to blend 3-4 damp Marcellus
wells
▪ Increases Marcellus margins by $0.50 - $0.55/dth vs.
processing
▪ Generates 30% uplift to NPV per Marcellus well
2020 Utica TIL Program:
5-well Switz pad – Monroe County, Ohio
3-well Shaw pad – Westmoreland County,
PA
4-well Richhill “blending” pad – Greene
County, PA
Operational Highlights
13
Highlights
▪ Richhill Area
- Marcellus drilling cost per foot decreased 23% in 2019,
compared to 2018
- Marcellus stimulation lateral footage per day improved 9% in
2019, compared to 2018
Production and Midstream Highlights
▪ In 2019, production increased 6%, when compared to 2018,
while lease operating expense (LOE) declined by $0.07 per
Mcfe, or declined by $30 million
▪ LOE reductions driven in part by remote operations via the real
time operations center for opening and closing producing wells
▪ CNXM commissioned the Dry Ridge Compressor Station to
service the company’s Richhill operating area
- The station currently has the capacity of 200 MMcf per day
with plans to increase capacity in the future
Dry Ridge Compressor Station
$0.78 $0.78
$1.13 $1.13
$1.25 $1.31
$1.69
$2.18
$-
$0.75
$1.50
$2.25
CNXConsolidated
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Lease Operating Expense ($/Mcfe) Production, Ad Valorem, and Other Fees ($/Mcfe) Transportation, Gathering and Compression - E&P ($/Mcfe)
14
Low Production Cash Costs Create Competitive Advantage
(1) TTM as of Q4 2019 end for CNX and TTM as of Q3 2019 for peers. Peers include AR, COG, EQT, GPOR, RRC, SWN. For peers that net transportation costs from
revenue, $0.30 per Mcfe has been added to Transportation, Gathering and Compression to estimate total production costs.
(2) CNX consolidated includes the benefit of $0.35 per Mcf after eliminating intercompany gathering charges between CNX and CNX Midstream.
(3) Does not include firm transportation.
(4) Lease operating expense for this producer includes gathering and processing costs, but not firm transportation.
(5) Average daily production TTM as of Q4 2019 for CNX and TTM as of Q3 2019 for peers.
TTM Q3/Q4 2019 Production Cash Costs per Mcfe(1)
CNX’s top-tier
production cash
costs, substantial
hedge book, and
midstream control
create a significant
advantage in a weak
natural gas pricing
environment
(4)
Avg. Daily
Production(5)
(Bcfe/d)
1.5 2.3 1.5 1.4 4.2 2.2 2.2 3.2
(2)
(3)
15
Proactive Business Management: Cumulative Changes Since Q2 2019 Call
OLD (Q2 2019) NEW (Q4 2019)
Macro Conditions Got Much Worse But
CNX Got Much Stronger
(1) Forward market prices are as of 1/24/2020.
Decreased cumulatively in 2019 and 2020 by ~$144M, based on 2019 Actuals vs. midpoint of 2019 guidance range, and changes to midpoint of 2020
guidance ranges in Q4 2019 vs. Q2 2019
E&P Capex Decreased by ~$144M
Increased cumulatively in 2019 and 2020 by ~$20 million based on 2019 Actuals vs. midpoint of 2019 guidance range, and changes to midpoint of 2020
guidance ranges in Q4 2019 vs. Q2 2019
E&P EBITDAX Increased by ~$20M
Reduced expected cash SG&A spend by $30 million annually since 2018; Annual cash SG&A costs for E&P expected to be
~$70M based on midpoint of 2020 guidance
SG&A Decreased by ~$30M
2020 NYMEX $2.55/MMBtu ($0.46)/MMBtu $2.09/MMBtu(1)
Updated 2020 and 2021 Guidance
Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs and
other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected
metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.
(1) Forward market prices are as of 1/8/2020.
(2) Includes approximately $80 million of projected distributions from ownership interests in CNXM and a $50 million payment associated with the IDR Elimination
Transaction. Per share calculation uses 186.6 million shares outstanding as of 1/20/2020..
(3) Includes distributions from CNX Midstream plus $62 million in tax refund expected in 2020. Excludes ~$50M in expected asset sales in 2020 and 2021. 16
Previous UPDATED
2020E 2020ECapital Expenditures($ millions)
Low High Low High
Drilling & Completions $400 $450 $360 $410
Non-D&C $90 $100 $90 $100
Total E&P Capital $490 $550 $450 $510
CNX Midstream LP Capital $80 $100 $80 $100
Total Consolidated Capital $570 $650 $530 $610
Production Volumes (Bcfe) 535 565 525 555
Prices on Open Volumes
Natural Gas NYMEX ($/MMBtu)(1) $2.40 $2.27
Natural Gas Basis Differential ($/MMBtu)(1) ($0.25)-($0.35) ($0.25)-($0.35)
Adjusted EBITDAX(2)
($ millions)
E&P Standalone + Distributions(2) $710 $755 $765 $810
E&P Standalone + Distributions(2)
per Share$3.81 $4.05 $4.10 $4.34
Consolidated $885 $950 $885 $950
Organic Free Cash Flow (FCF)(3) $146 ~$200
Expect ~5% Production Growth in 2021,
compared to 2020
Expect to Generate >$200M in
Organic Free Cash Flow in 2021
▪ 2021E
Pro
du
cti
on
FC
F
Five-year average all-in maintenance capital (D&C + non-D&C):
~$400 million to hold flat production of 540 Bcfe
For 2019 and 2020 combined, Total E&P capital is anticipated to be reduced
by ~$67 million, resulting in 6 Bcfe less production in 2020, compared to
previous update, after accounting for the 4 Bcfe accelerated from 2020 into
2019
Maintaining non-D&C capital in 2020 and expect this to be lower in 2021
-
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
Jan-2020 Feb-2020 Mar-2020 Apr-2020 May-2020 Jun-2020 Jul-2020 Aug-2020 Sep-2020 Oct-2020 Nov-2020 Dec-2020
Pro
ductio
n (
Bcfe
/d)
Legacy PDP Marcellus PUD Utica PUD
Production
Growth
~5%
Production Cadence and Hedge Advantage in 2020
(1) Assumes midpoint of guided 2020 production ranges.
17
Expected Daily Production 2020(1)
Average Hedged Volumes: 498 Bcf or 98% of gas production hedged at NYMEX $2.96 in 2020
TIL
s
2020
Marcellus: 33
Utica: 12 2020 S
ets
Up
2021 W
ell
% of Gas
Hedged
83%NYMEX
Hedge Price
$2.91
2021 Due to
minimum well
commitments
(MWC’s)
expect at a
minimum
modest
production
growth in
2022, and
potentially
more
depending on
gas prices
83%
81%
23%21%
3%0% 0%
$2.91
$2.80
$2.40
$2.56
$2.62
$ 2.00
$ 2.10
$ 2.20
$ 2.30
$ 2.40
$ 2.50
$ 2.60
$ 2.70
$ 2.80
$ 2.90
$ 3.00
0 %
20 %
40 %
60 %
80 %
100 %
CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
% o
f C
on
sen
su
s P
rod
. H
ed
ged
2021 % of Production Hedged 2021 Average NYMEX Price Floor
Pri
ce F
loo
r
98%
92%
90%
63%
57%
42%
0%
$ 2.96
$ 2.87
$ 2.71
$ 2.64 $ 2.63
$ 2.88
$2.00
$2.10
$2.20
$2.30
$2.40
$2.50
$2.60
$2.70
$2.80
$2.90
$3.00
0%
20%
40%
60%
80%
100%
CNX Peer 1 Peer 2 Peer 4 Peer 3 Peer 5 Peer 6
% o
f C
on
sen
su
s P
rod
. H
ed
ged
2020 % of Production Hedged 2020 Average NYMEX Price Floor
Pri
ce F
loo
r
Substantial Hedges with Strongest Prices in 2020 and 2021
Note: Peers include AR, COG, EQT, GPOR, RRC, SWN. As of Q4 2019 for CNX and as of Q3 2019 for peers. NYMEX as of 1/8/2020. CNX hedge price per Mcf and per
MMBtu for peers.
(1) Based on Bloomberg consensus estimates as of 1/3/2020 for 2020E and 2021E annual gas production. CNX 2020 % of production hedged based on the midpoint of
natural gas guidance. CNX 2021 % of production hedged based on 5% annual production growth. CNX 2022 and 2023 % of gas production hedged based on flat
scenario with 2021 production of 535.5 Bcf. 18
2020E(1) Hedged Gas Production 2021E(1) Hedged Gas Production
~57% of 2022(1) production
hedged under maintenance
scenario at $2.99 NYMEX
vs.
~4% for peers at $2.67
NYMEX
NYMEX Strip $2.27 in 2020
NYMEX Strip $2.43 in 2021~33% of 2023(1) production
hedged under maintenance
scenario at $2.85 NYMEX
vs.
~1% for peers at $2.66
NYMEX
Balance Sheet is Getting Stronger
19
Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs
and other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP
projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items..
(1) LP-adjusted leverage assuming CNXM LP ownership is used to offset the debt. CNXM market value as of 1/24/2020.
$ in millions
Stand-AloneStand-Alone Net Debt and Leverage
December 31, 2019
Total Long-Term Debt (GAAP) $2,048.5
Less: Cash and Cash Equivalents $15.3
Forecasted Net Debt (Non-GAAP) $~1,783.2
2020 Forecasted Stand-Alone Leverage Ratio ~2.25x
2020 Stand-Alone Adjusted EBITDAX $787.5
2021 Leverage Ratio
Set To Go Even Lower
Less: Forecasted 2020 Total FCF $250.0
LP-Adjusted(1)
$2,048.5
$15.3
$~1,005.5
~1.3x
$787.5
$250.0
Less: 50.7M units
x $15.34(1)
0.6 x2.0 x
3.3 x 3.2 x 2.8 x4.0 x 3.7 x
1.4 x
2.3 x
5.5 x
10.6 x12.9 x
12.8 x
18.3 x
2.0 x
4.3 x
8.8 x
13.8 x
15.7 x16.8 x
22.0 x
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
0.6x
2.0x
2.8x
3.2x3.3x
3.7x4.0x
Peer 1 CNX Peer 4 Peer 3 Peer 2 Peer 6 Peer 5
Highly Resilient Balance Sheet
20
Note: Peers include AR, COG, EQT, GPOR, RRC, SWN.
(1) For peers based on Capital IQ consensus estimates for 2021E EBITDA and 2021E net debt as of 1/24/2020. CNX 2021E based on forecast. Off-balance sheet
obligations based on the respective 2018 10-Ks of CNX and the peer companies.
Net Debt + Off-Balance Sheet Obligations /
2021E EBITDA(1)
▪ Under current strip, CNX expects to generate FCF and reduce
leverage in 2020 and 2021
▪ Flexibility through low total liability positioning in Appalachia
▪ Deliberate, strategic decision by management to avoid expensive
FT contracts that are now underwater
▪ Instead, relies on hedges (NYMEX + Basis) to mitigate pricing risk
▪ Selected, thoughtful firm transportation commitments, limiting the
need to “drill to fill”
▪ Most peers expected to increase leverage in 2021
Net Debt / 2021E EBITDA(1)
~
Net Debt
Off-Balance Sheet Obligations
81% 80%
73%
66% 65%
54%
15%
Peer 1 Peer 5 Peer 4 Peer 2 Peer 3 CNX Peer 6
403%
302%
251% 246%
150%
41%
20%
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 CNX Peer 6
484%
368%
319% 316%
231%
95%
35%
Peer 1 Peer 2 Peer 4 Peer 3 Peer 5 CNX Peer 6
21
CNX Screens Well on All-In Debt Metrics vs. Appalachian Peers
Total Debt(1) as % of EV FT Commitments as % of EV Total Debt(1) + FT Commitments as a % of EV
Source: Public filings; Market cap as of 1/3/2020. Peers include AR, COG, EQT, GPOR, RRC, SWN.
(1) CNX total debt is consolidated and as of Q4 2019 and as of Q3 2019 for peers, excludes lease obligations; per latest company filings. Off-balance sheet obligations
based on respective 2018 10-Ks of CNX and peer companies. 21
2022 Senior Notes Maturities Easily Addressed
22
$ in m
illio
ns
Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs
and other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP
projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items..
Total FCF includes approximately $50 million in assets sales in 2020E and 2021E.
(1) CNXM market value as of 1/24/2020.
~$780M
CNXM
Units(1)
$1.2B
Revolver
Liquidity
Ability to
payoff or
refinance
2022 FCF also expected to be additional source of funds
23
CNX Under the Current
NYMEX Strip
◼ Expect to generate approximately $250 million in total FCF in each 2020 and 2021
◼ Leverage ratio decreases to approximately 2.0x
◼ Modest production growth in 2021 expected, based on the midpoint of the 2020 guidance range
◼ Sets up for a strong ramp of activity into 2022 and beyond
◼ Or will have the optionality to stay in a slow-and-steady mode if macro conditions warrant
Peers?
◼ Production flat to decreasing
◼ FCF neutral to negative
◼ Leverage ratios increasing with some expected to increase significantly
CNX has taken a deliberate approach, focusing on flexibility to appropriately manage through the commodity cycle
What Lies Ahead in 2021?
23
Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs
and other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP
projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.
Total FCF includes approximately $50 million in assets sales in 2020E and 2021E.
Appendix
Financial Guidance
25
PREVIOUS (10/30/2019) UPDATE (1/30/2020)
2020E 2020E
Revenue and Other Operating Income E&P Consolidated E&P Consolidated
Production Volumes:
Natural Gas (Bcf) 505-535 495-525
NGLs (MBbls) 4,490-4,715 4,535-4,760
Condensate (MBbls) 245-265 245-265
Total Production (Bcfe) 535-565 525-555
% Liquids ~5% ~5%-6%
Natural Gas NYMEX Price ($/MMBtu)(1) $2.40 $2.27
Natural Gas Basis Differential to NYMEX ($/MMBtu)(1) ($0.25)-($0.35) ($0.25)-($0.35)
NGL Realized Price ($/Bbl)(1) $14.00-$16.00 $15.50-$17.50
Condensate Realized Price % of WTI(1) 70% 70%
Realized Hedging Gain/(Loss) ($ in millions)(2) $145-$155 $210-$220
Other Operating Income (3rd party water income and resold FT) ($ in millions) $10-$20 $10-$20
CNXM 3rd Party Gathering Revenue $65-$70 $70-$75
Costs
Average per unit operating expenses ($/Mcfe):
Lease Operating Expense
Production, Ad Valorem, and Other Fees
Transportation, Gathering and Compression
Total Cash Production and Gathering Costs $1.06-$1.14 $0.67-$0.75 $1.06-$1.14 $0.67-$0.75
($ in millions)
Selling, General, and Administrative Costs(3) $65-$75 $80-$90 $65-$75 $80-$90
Exploration Expense $0-$10 $0-$10
Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$75 $65-$75
Other Non-Operating Expense (Income) $0-$10 $0-$10
CNX Resources Corporation is unable to provide a reconciliation of projected stand-alone or consolidated adjusted EBITDAX to projected operating income, the most
comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate GAAP projected operating income given the unknown effect,
timing, and potential significance of certain income statement items.
(1) Forward market prices are as of 1/8/2020.
(2) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing as of 1/8/2020. Anticipated hedging activity is not included in projections.
(3) Excludes stock-based compensation.
$80$88 $103
$124
$170 $171 $175
$306
$-
$0.02
$0.04
$0.06
$0.08
$0.10
$0.12
$0.14
$0.16
$0.18
$0.20
$0
$50
$100
$150
$200
$250
$300
$350
CNX - 2020EStand-Alone
Guidance
Peer 1 Peer 2 CNX -Stand-Alone
Peer 3 Peer 4 Peer 5 Peer 6
Tota
l S
G&
A (
$/M
cfe
)
Tota
l S
G&
A A
bsolu
te D
olla
rs (
$M
)
Cash SG&A (ex. stock comp) - ($M) Non-cash stock comp Cash SG&A (ex. stock comp) - ($/Mcfe)
Realignment Driving Expected Best-In-Class SG&A
26
Expect ~$30 million in total expected
consolidated cash SG&A savings
since 2018
▪ Combined upstream and midstream
teams
▪ Streamlined to one monitoring
system
Total 2020E SG&A (cash + non-cash)
is expected to be over 50% less than
peer average
Integrated Real-Time Operations
Center (IRTOC)
▪ Efficient cross-functional cooperation
Note: Cash SG&A excludes non-cash stock compensation expense.
(1) TTM as of Q4 2019 end for CNX and TTM as of Q3 2019 for peers. Peers include AR, COG, EQT, GPOR, RRC, SWN.
TTM Q3/Q4 2019 SG&A(1)
Q4 2019 Financial Results Summary
27
Note: The Non-GAAP financial measures in the tables above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation."
(1) For the quarter ended December 31, 2019, total shares outstanding of 186,642,962 (Non-GAAP) are as of 1/20/2020. For the quarter ended December 31, 2018, total
shares outstanding of 198,335,252 (Non-GAAP) are as of 1/18/2019.
(2) Capital expenditures exclude $72 million and $56 million of total capital investment net to CNXM in the fourth quarter of 2019 and 2018, respectively, as reported in
CNXM Fourth Quarter Results.
(3) See the "Price and Cost Data Per Mcfe" in the appendix for a reconciliation to total Production Costs.
(4) Fully burdened cash costs include production cash costs, selling, general and administrative (SG&A) cash costs, other operating cash expense, other cash (income)
expense, and interest expense.
Strong operating cash
margins despite weaker gas
prices vs. last year
Quarter
Ended
Quarter
Ended
Quarter
Ended
Quarter
Ended
December 31, December 31, December 31, December 31,
2019 2018 2019 2018
($ in millions, except per share data) Stand-alone% Increase/
(Decrease)Consolidated
% Increase/
(Decrease)
Adjusted Net (Loss) Income ($27) $120 -122.5% $22 $160 -86.3%
Total Shares Outstanding (in millions)(1)
186.6 198.3 -5.9% - - -
Adjusted Net (Loss) Income per Outstanding Share (1)
($0.14) $0.61 -123.0% - - -
Adjusted EBITDAX $214 $270 -20.7% $264 $314 -15.9%
Adjusted EBITDAX per Outstanding Share(1)
$1.15 $1.36 -15.4% $1.41 $1.58 -10.8%
Capital Expenditures(2)
$156 $266 -41.4% - - -
Quarter
Ended
Quarter
Ended
December 31, December 31,
(Per Mcfe) 2019 2018
Average Sales Price - Total Company $2.54 $3.09
Total Production Cash Costs(3)
$1.11 $1.00
Operating Cash Margin $1.43 $2.09
Operating Cash Margin (%) 56% 68%
Total Fully Burdened Cash Costs(4)
$1.63 $1.47
Fully Burdened Cash Margin $0.91 $1.62
$1.64 $1.70 $1.69 $1.63
$1.33
$0.93 $0.82
$0.91
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
Q1 2019 Q2 2019 Q3 2019 Q4 2019
Total Fully-Burdened Cash Costs Total Fully-Burdened Cash Margin
$1.11 $1.18 $1.13 $1.11
$1.86
$1.45 $1.38 $1.43
$0.00
$0.50
$1.00
$1.50
$2.00
Q1 2019 Q2 2019 Q3 2019 Q4 2019
Total Production Cash Costs Total Production Cash Margin
($/Mcfe) 4Q 2019 4Q 2018
Y/Y
Change 4Q 2019 3Q 2019
Q/Q
Change
Average Sales Price(1)
$2.54 $3.09 ($0.55) $2.54 $2.51 $0.03
Total Production Costs(2)
$1.97 $1.89 $0.08 $1.97 $1.99 ($0.02)
Sales Volumes (Bcfe) 143.4 136.1 7.3 143.4 128.3 15.1
Sales Volumes by Category (Bcfe)
Marcellus 101.3 87.0 14.3 101.3 87.3 14.0
Utica 28.3 34.1 (5.8) 28.3 26.8 1.5
CBM 13.7 14.9 (1.2) 13.7 14.1 (0.4)
Other 0.1 0.1 0.0 0.1 0.1 0.0
Margin 63% 55% 55% 56%
Q4 2019 Operational Results Summary
28
▪ Marcellus Shale cash production costs were $1.28 per Mcfe in Q4
2019, up $0.08 from $1.20 per Mcfe in Q4 2018, or a 7% increase
▪ Utica Shale cash production costs were $0.47 per Mcfe in Q4 2019, an
increase of $0.05, from $0.42 per Mcfe in Q4 2018
- The increase in both Marcellus and Utica cash costs was mainly a
result of higher firm transportation costs and CNXM fees
▪ E&P stand-alone capital expenditures decreased 41% Y/Y to $156
million in Q4 2019 from $266 million spent in Q4 2018
(1) Average sales prices for 4Q2019, 4Q2018, and 3Q2019 include gain (loss) on commodity derivative instruments
(cash settlements) of $0.33, ($0.56), and $0.47 per Mcf, respectively.
(2) Total Production Costs for 4Q2019, 4Q2018, and 3Q2019 include DD&A of $0.86, $0.89, and $0.86 per Mcfe,
respectively.
(3) Includes per unit Lease Operating Expense; Transportation, Gathering and Compression; and Production, Ad Valorem and Other Fees. See non-GAAP reconciliation
table in appendix.
(4) Fully burdened cash costs include production cash costs, selling, general and administrative (SG&A) cash costs, other operating cash expense, other cash (income)
expense, and interest expense. Q4 2019, Q3 2019, Q2 2019, and Q1 2019 total fully burdened cash costs exclude a gain on asset sales of $0.25 per Mcfe, $0.03
per Mcfe, $0.00 per Mcfe, and $0.03 per Mcfe, respectively.
Production Cash Costs(3) and Margins 1Q19-4Q19 Fully-Burdened Cash Costs(4) and Margins 1Q19-4Q19
$/M
cfe
$/M
cfe
Margin 45% 35% 33% 36%
Q4 2019 Activity Summary
29
(1) Measured in lateral feet from perforation to perforation.
Q4 2019 2019
($ in millions) TD FRAC TIL
Average
Lateral
Length(1)
Rigs at
Period
End TD FRAC TIL
SWPA
Central
Marcellus 4 6 4 9,850 - 38 34 36
Utica 1 1 1 5,925 - 13 9 8
WV
Shirley-Penns
Marcellus 4 - - - 1 9 5 5
Utica - - - - - - - -
CPA South Utica - - - - - 1 - -
OH Dry Utica 3 - - - 1 5 2 2
Total 12 7 5 2 66 50 51
Expect to run 2 rigs and 1 frac crew in 2020
Executive Summary
30
Q4 2019 EXPECTATION
STRATEGIC INITIATIVE
Substantial Hedge Position▪ ~98% of 2020 gas volumes hedged at NYMEX $2.96
per Mcf; ~83% of 2021 gas volumes hedged at
NYMEX $2.91 per Mcf
▪ Hedge book protects our returns and margins for the
majority of 2020 and 2021 activity
Low Production Cash Costs▪ Production cash costs improved in the fourth quarter
to $1.11 per Mcfe, compared to the third quarter
▪ 2020 production cash costs expectations are in-line
with 2019, while SG&A and other operating expenses
are down meaningfully in 2020, compared to 2019
Significant Expected SG&A Savings▪ Continue to integrate and optimize combined
upstream and midstream teams to streamline
operations and capitalize on efficiencies
▪ Significant expected consolidated cash SG&A
savings of ~$25M in 2020, compared to 2019
Balance Sheet & Leverage Ratio ▪ 2022 senior notes maturities easily addressed ▪ 2021 leverage ratio set to go lower than 2020
EBITDAX, Capital, and FCF
Guidance
▪ Increasing FY2020 E&P EBITDAX guidance to $765-
$810M from $710-$755M; decreasing FY2020 E&P
capital expenditure guidance to $450-$510M from
$490-$550M
▪ Continue to make all capital allocation decisions on a
strict rate of return basis and look for opportunities to
increase efficiencies
SWPA Utica and Stacked Pay▪ One 4-well pad in 2020 plan to execute blending
strategy in Richhill development field
▪ SWPA Utica continues to serve an integral economic
purpose in our investment portfolio (primarily
blending), and that purpose will continue to provide
opportunity for continual reservoir productivity
optimization in 2020
Note: The Non-GAAP financial measures in the table above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation.“
CNX Resources Corporation is unable to provide a reconciliation of projected stand-alone or consolidated adjusted EBITDAX to projected operating income, the most
comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate GAAP projected operating income given the unknown effect,
timing, and potential significance of certain income statement items.
Midpoints of Guidance Ranges 2019 Actuals/Midpoints of 2020 Guidance Total Changes
($ in millions) 2019 2020E Total 2019A 2020E Total Since Q2 2019
Production (Bcfe) 520 583 1,103 539 540 1,079 (24)
Total E&P Capital $920 $580 $1,500 $876 $480 $1,356 ($144)
Stand-Alone EBITDAX $750 $793 $1,543 $772 $788 $1,560 $17
Natural Gas 2020 NYMEX ($/MMBtu) $2.55 $2.09(1)
($0.46)
Cumulative Changes Since Q2 2019 Call
31
~$30M in
SG&A
removed
from system
since 2018
Plan Flexibility Based on Macro and Market Conditions
Disciplined Capital Allocators
Plan Based on Risk-Adjusted Returns, Supported by
Best-in-Class Hedge Book
Q2 2019 Earnings Call (7/30/2019) Q4 2019 Earnings Call (1/30/2020)
Note: The 2019 Non-GAAP financial measures in the table above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation.“ CNX is
unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs and other metrics
to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected metrics,
including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items..
(1) Forward market price as of 1/24/2020.
Marketing Highlights and Liquids Realizations
32
Marketing Highlights
▪ Directly-marketed ethane volumes were 273,000
barrels in Q4 and, on an equivalent basis, yielded a
$0.06 per MMBtu premium over CNX’s residue
natural gas alternative.
2019 2018
Q4 Q4
NYMEX Natural Gas ($/MMBtu) $2.50 $3.64
Average Differential (0.51) (0.29)
BTU Conversion (MMBtu/Mcf)(1) 0.15 0.24
Gain on Commodity Derivative
Instruments-Cash Settlement0.33 (0.56)
Realized Gas Price per Mcf $2.47 $3.03
(1) Conversion factor 1.08 1.07
Natural Gas Price Reconciliation
Natural Gas Liquids, Oil and Condensate
▪ Q4 2019 liquids sold: 10.5 Bcfe
▪ Total weighted average price of all liquids decreased 20% to $20.49
per Bbl in Q4 2019 from $25.61 per Bbl in Q4 2018 and increased 44%
from $14.26(1) per Bbl in Q3 2019.
▪ In Q4 2019, liquids comprised 7% of production volumes and 11% of
natural gas, NGLs, and oil revenue.
Average Price Realization ($ per Bbl)
2019 2018
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
NGLs $19.20 $13.68 $18.36 $26.76 $24.54 $28.08 $28.38 $27.48
Oil $51.72 $56.64 $50.52 $43.56 $60.54 $63.00 $58.32 $56.46
Condensate $44.68 $75.54(2) $45.36 $39.00 $38.34 $58.56 $56.82 $49.32
(1) $14.11 per Bbl excluding prior period adjustment.
(2) $34.09 per Bbl excluding prior period adjustment.
Financial Guidance: 2020E Natural Gas Marketing Mix and Basis
Note: Forward market prices are as of 1/8/2020.
33
Northeast Pipeline Projects
Southeast Pipeline Projects
ETNG
2020E Gas: 9%
CY20 Basis: $0.20
TCO Pool
2020E Gas: 20%
CY20 Basis: ($0.33)
TETCO ELA & WLA
2020E Gas: 5%
CY20 Basis: ($0.17)
Dawn Pipeline Projects
Gulf Market Pipelines
Michcon
2020E Gas: 10%
CY20 Basis: ($0.18)
DOM South
2020E Gas: 10%
CY20 Basis: ($0.44)
TETCO M2
2020E Gas: 40%
CY20 Basis: ($0.45)
TETCO M3
2020E Gas: 6%
CY20 Basis: $0.06
Percentages include physical sales
Volumes 2020E CY 2020
(000 MMBtu) Gas Sold (%) Basis
DOM South 42,496 8% ($0.44)
ETNG Mainline 21,656 4% $0.20
TCO Pool 79,382 14% ($0.33)
TETCO ELA & WLA 26,828 5% ($0.17)
TETCO M3 33,536 6% $0.06
TETCO M2 192,302 35% ($0.45)
Michcon 54,430 10% ($0.18)
Physical basis sales 101,333 18% ($0.21)
Total (000 MMBtu) 551,963 100% ($0.29)
Total (MMcf) 510,000
NYMEX $2.27
Weighted Average Basis (Not considering hedging) ($0.29)
2020E Average Realized Price (per MMBtu) $1.98
Conversion Factor (MMBtu/Mcf) 1.082
2020E Average Realized Price (per Mcf) $2.14
Market
490.8 417.0
281.0
164.7 147.7
0
50
100
150
200
250
300
350
400
450
500
550
2020 2021 2022 2023 2024
Gas V
olu
mes H
edged (
Bcf)
NYMEX + Basis (2)
Natural Gas Hedging and Basis Protection
34
(2)
Hedge Volumes and Pricing Q1 2020 2020 2021 2022 2023 2024
NYMEX Hedges
Volumes (Bcf) 115.6 479.4 395.4 266.6 136.5 136.6
Average Prices ($/Mcf) $3.00 $2.96 $2.91 $2.99 $2.85 $2.90
Physical Fixed Price Sales and Index Hedges
Volumes (Bcf) 2.8 11.4 21.6 14.4 28.2 11.1
Average Prices ($/Mcf) $2.44 $2.44 $2.49 $2.58 $2.13 $2.26
Total Volumes Hedged (Bcf)(1) 118.4 490.8 417.0 281.0 164.7 147.7
NYMEX + Basis (fully-covered volumes)(2)
Volumes (Bcf) 118.4 490.8 417.0 281.0 164.7 147.7
Average Prices ($/Mcf) $2.67 $2.55 $2.42 $2.44 $2.29 $2.32
NYMEX Hedges Exposed to Basis
Volumes (Bcf) - - - - - -
Average Prices ($/Mcf) - - - - - -
Total Volumes Hedged (Bcf)(1) 118.4 490.8 417.0 281.0 164.7 147.7
CNX’s substantial
hedge book de-risks
rates of return and
creates time to adjust
development plans
and protect the
balance sheet in the
face of weaker prices
Fully-covered hedges represent
~96% of 2020 dry gas volumes(3)
NYMEX hedges added during Q4:
42.8 Bcf (2023 and 2024)
Basis hedges added during Q4:
149.7 Bcf (2020, 2021, 2022, 2023,
and 2024)
(1) Hedge positions as of 1/8/2020. Excludes basis hedges in excess of NYMEX hedges of 3.3 Bcf, 6.8 Bcf, 26.3 Bcf, 24.3 Bcf, 9.4 Bcf, and 3.8 Bcf for Q1 2020, 2020,
2021, 2022, 2023, and 2024, respectively.
(2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements.
(3) Assuming midpoint of total dry gas production guidance for 2020E.
Q1 2020 and 2020 Gas Hedging Gain/Loss Projections
35
Note: Forward market prices, hedged volumes, and hedge prices are as of 1/8/2020. Anticipated hedging activity is not included in projections.
(1) January prices are settled.
(2) Q1 and annual amounts based on sum of monthly hedge positions vs. strip.
▪ In addition to NYMEX and basis financial hedges, CNX has physical fixed basis sales and physical fixed price sales with customers
▪ 2020E physical fixed basis sales and physical fixed price sales: 93.6 Bcf
▪ Physical sales provide additional basis hedge
- Flows through gas sales in financials
Q1 2020 CY2020
Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted
Hedged Volumes Hedged Forward Gain/(Loss)(2)
Hedged Volumes Hedged Forward Gain/(Loss)(2)
(000 MMBtu) Price Market(1)
($ in 000s) (000 MMBtu) Price Market(1)
($ in 000s)
($/MMBtu)
NYMEX 124,840 $2.78 $2.14 $78,787 518,000 $2.74 $2.27 $240,655
Basis:
DOM South (DOM) 18,655 ($0.57) ($0.39) ($3,326) 75,030 ($0.57) ($0.44) ($9,457)
TCO Pool (TCO) 15,925 ($0.39) ($0.32) ($1,065) 65,580 ($0.39) ($0.33) ($3,627)
Michcon (NMC) 7,963 ($0.16) ($0.11) ($381) 34,013 ($0.17) ($0.18) $252
TETCO ELA (TEB) 1,820 ($0.09) ($0.10) $27 7,320 ($0.09) ($0.11) $128
TETCO WLA (TWB) 3,640 ($0.08) ($0.07) ($8) 14,640 ($0.08) ($0.06) ($175)
TETCO M3 (TMT) 5,005 $1.39 $0.85 $2,744 16,315 $0.20 $0.06 $2,506
TETCO M2 (BM2) 47,320 ($0.55) ($0.37) ($8,522) 210,810 ($0.54) ($0.45) ($19,189)
Transco Zone 5 South (DKR) - - - - 12,530 $0.16 $0.27 $1,461
Total Financial Basis Hedges 100,328 ($10,531) 436,238 ($28,101)
Total Projected Realized Gain $68,256 $212,554
December 31,
2019 2018
Deferred Tax Assets:
Alternative Minimum Tax $ 51,241 $ 102,482
Net Operating Loss - Federal 202,913 124,341
Net Operating Loss - State 130,430 110,339
Foreign Tax Credit 43,194 43,194
Interest Limitation 25,734 32,147
Equity Compensation 9,308 13,096
Gas Well Closing 17,888 10,140
Salary Retirement 9,236 9,434
Capital Lease 1,209 1,624
Other 10,030 13,714
Total Deferred Tax Assets 501,183 460,511
Valuation Allowance (125,054) (94,455)
Net Deferred Tax Assets 376,129 366,056
December 31, December 31,
2019 2018
Current Assets
Cash and Cash Equivalents $ 16,283 $ 17,198
Accounts and Notes Receivable
Trade 133,480 252,424
Other Receivables 13,679 11,077
Supplies Inventories 6,984 9,715
Recoverable Income Taxes 62,425 149,481
Prepaid Expenses 265,250 61,791
Total Current Assets 498,101 501,686
2020 AMT Credit and Additional Refunds
Note: Current Assets and Deferred Tax tables from the 2019 and 2018 10-K respectively.
36
▪ Combined AMT refund and additional tax refunds to drive total
cash tax inflow of ~$62 million in 2020
▪ Incremental AMT refund expected in 2020 and 2021 of approximately
$51 million each year
▪ Company continues to expect no cash tax payments for 4-5 years due
to NOL utilization
$138 million of AMT and other tax refunds
received in 2019
CPA Dry Utica Results Remain Consistent and Strong
37
CPA Dry Utica Results
Pressure Drawdown vs 7,000’ Norm. Cumulative Production
CPA Dry Utica Cumulative Production
Normalized to 7000’
▪ BP6 TIL Q4- 2018 performing in-line with other wells in area
▪ Strong, consistent, and repeatable performance is increasing
confidence in the production and economics of CPA Utica
▪ Combined with recent D&C efficiencies in SWPA Utica at
below $1,800/ft D&C yields high returns
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
- 2,000 4,000 6,000 8,000 10,000
% o
f In
itia
l R
ese
rvo
ir P
ressu
re
Cumulative Production (MMcf)
BP6 AIKENS5J AIKENS5M GAUT4
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0 100 200 300 400 500 600
Cum
ula
tive
Pro
du
ctio
n (
MM
cf)
Days
BP6 AIKENS5J AIKENS5M GAUT4
CNX Acreage Position Remains Top-Tier in Appalachia
Source: Company reports. Peers include AR, COG, EQT, GPOR, RRC, SWN.
(1) Locations calculated by dividing total controlled acreage in type curve region by the area of a well (9,500’ lateral length * 750’ inter-lateral spacing).
(2) Any incremental leasing and associated land leasing capital spend would increase the number of undeveloped locations. 38
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Appalachian Peer Group Net Acres CNX SWPA Central Marcellus Locations(1)
Assuming a run rate of 36
SWPA Central Marcellus TILs
per year:
CNX maintains ~12 years of
core inventory after YE2020
CNX maintains approximately
12 years of additional
inventory in Shirley/Pens
WVa., assuming 1 pad per year
CNX’s production grows with
only 40 wells per year
CNX’s controlled acres are only
~6% developed
SWPA Tier 1 Undeveloped Acres 69,800
Divided by
Acres per well 163
Equals
Total Undrilled Locations 427
Average wells TIL (2018-2020E) 36
Years Inventory remaining 12
Non-GAAP Reconciliation
39
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
(2) MLP cash flow from operations and CNX Gathering calculated using same percentage mix of gross adjusted EBITDA and adjusted EBITDA net to the MLP, which in
Q4 2019 was 95.0% and 5.0%, respectively. Consolidated cash flow from operations for CNX Midstream for Q4 2019 was $41.4 million.
Cash from Operations and Capital Expenditures by Segment
Three Months Ended
December 31,
2019 2018 2019 2018
($ in thousands)Stand-alone
(1)Stand-alone
(1) Total Company Total Company
Net (Loss) Income from EBITDAX Reconciliation ($287,970) $90,106 ($240,055) $129,415
Adjustments
Total Pre-tax Adjustments from EBITDAX Reconciliation 353,715 41,297 354,113 41,933
Tax Effect of Adjustments (92,433) (11,199) (92,537) (11,371)
Adjusted Net (Loss) Income ($26,688) $120,204 $21,521 $159,977
December 31, 2019
($ in thousands)Stand-alone
(1) Midstream Total Company
Total Long-Term Debt (GAAP) $2,048,531 $705,912 $2,754,443
Less Cash and Cash Equivalents 15,328 955 $16,283
Net Debt (Non-GAAP) $2,033,203 $704,957 $2,738,160
($ in millions)
Q4 2019
E&P
Standalone +
CNX
Gathering(2)
= CNX + MLP(2)
=
Total
Consolidated
Cash from Operations $73.1 $2.1 $75.1 $39.3 $114.5
Capital Expenditures $151.6 $4.1 $155.7 $72.4 $228.1
Non-GAAP Reconciliation
40
Price and Cost Data per Mcfe
($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019
Average Sales Price - Total Company 2.85$ 2.47$ 2.50$ $ 2.80 3.00$ 2.87$ 2.92$ $ 3.09 2.97$ 2.63$ 2.51$ 2.54$
Lease Operating Expense 0.23$ 0.23$ 0.22$ 0.21$ 0.28$ 0.21$ 0.14$ 0.12$ 0.14$ 0.15$ 0.11$ 0.09$
Transportation, Gathering and Compression 0.99$ 0.94$ 0.98$ 0.87$ 0.86$ 0.82$ 0.84$ 0.82$ 0.92$ 0.98$ 0.97$ 0.97$
Production, Ad Valorem, and Other Fees 0.09$ 0.05$ 0.06$ 0.08$ 0.07$ 0.06$ 0.06$ 0.06$ 0.05$ 0.05$ 0.05$ 0.05$
Depreciation, Depletion and Amortization 1.01$ 0.98$ 1.00$ 1.01$ 0.89$ 0.91$ 0.93$ 0.89$ 0.88$ 0.89$ 0.86$ 0.86$
Total Production Costs 2.32$ 2.20$ 2.26$ 2.17$ 2.10$ 2.00$ 1.97$ 1.89$ 1.99$ 2.07$ 1.99$ 1.97$
Less: Depreciation, Depletion and Amortization 1.01$ 0.98$ 1.00$ 1.01$ 0.89$ 0.91$ 0.93$ 0.89$ 0.88$ 0.89$ 0.86$ 0.86$
Total Cash Production Costs 1.31$ 1.22$ 1.26$ 1.16$ 1.21$ 1.09$ 1.04$ 1.00$ 1.11$ 1.18$ 1.13$ 1.11$
Operating Cash Margin 1.54$ 1.25$ 1.24$ 1.64$ 1.79$ 1.78$ 1.88$ 2.09$ 1.86$ 1.45$ 1.38$ 1.43$
Non-GAAP Reconciliation
41
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
Twelve Months Ended
December 31,
2019 2019 2019
($ in thousands)Stand-alone
(1) Midstream Total Company
Net (Loss) Income ($134,706) $166,654 $31,948
Interest Expense 121,054 30,325 151,379
Interest Income (1,915) (34) (1,949)
Income Tax Expense 27,736 - 27,736
Earnings Before Interest & Taxes (EBIT) 12,169 196,945 209,114
Depreciation, Depletion & Amortization 474,351 34,112 508,463
Exploration Expense 44,337 43 44,380
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $530,857 $231,100 $761,957
Adjustments:
Unrealized Gain on Commodity Derivative Instruments (306,325) - (306,325)
Impairment of Exploration and Production Properties 327,400 - 327,400
Impairment of Unproved Properties and Expirations 119,429 - 119,429
(Gain) Loss on Certain Asset Sales and Abandonments (3,665) 7,229 3,564
Severance Expense 2,881 436 3,317
Stock-Based Compensation 36,545 1,880 38,425
Loss on Debt Extinguishment 7,614 - 7,614
Shaw Event 4,305 - 4,305
Shaw Insurance Recovery (2,159) - (2,159)
Total Pre-tax Adjustments $186,025 $9,545 $195,570
Adjusted EBITDAX Consolidated $716,882 $240,645 $957,527
Midstream Distributions 55,333 N/A N/A
Stand-alone EBITDAX $772,215 N/A N/A
Non-GAAP Reconciliation
42
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
Three Months Ended
December 31,
2019 2019 2019
($ in thousands)Stand-alone
(1) Midstream Total Company
Net (Loss) Income ($287,970) $47,915 ($240,055)
Interest Expense 29,372 7,679 37,051
Interest Income (66) (12) (78)
Income Tax Benefit (50,398) - (50,398)
Earnings Before Interest & Taxes (EBIT) (309,062) 55,582 (253,480)
Depreciation, Depletion & Amortization 124,732 9,112 133,844
Exploration Expense 29,437 43 29,480
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) ($154,893) $64,737 ($90,156)
Adjustments:
Unrealized Gain on Commodity Derivative Instruments (92,538) - (92,538)
Impairment of Exploration and Production Properties 327,400 - 327,400
Impairment of Unproved Properties and Expirations 119,429 - 119,429
Severance Expense 113 - 113
Stock-Based Compensation 1,470 398 1,868
Shaw Insurance Recovery (2,159) - (2,159)
Total Pre-tax Adjustments $353,715 $398 $354,113
Adjusted EBITDAX Consolidated $198,822 $65,135 $263,957
Midstream Distributions 15,549 N/A N/A
Stand-alone EBITDAX $214,371 N/A N/A
Non-GAAP Reconciliation
43
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
Three Months Ended
December 31,
2018 2018 2018
($ in thousands)Stand-alone
(1) Midstream Total Company
Net Income $90,106 $39,309 $129,415
Interest Expense 26,471 6,751 33,222
Interest Income 1 - 1
Income Tax Expense (23,713) - (23,713)
Earnings Before Interest & Taxes (EBIT) 92,865 46,060 138,925
Depreciation, Depletion & Amortization 122,314 7,770 130,084
Exploration Expense 2,633 - 2,633
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $217,812 $53,830 $271,642
Adjustments:
Unrealized Loss on Commodity Derivative Instruments 36,727 - 36,727
Loss on Certain Asset Sales 96 - 96
Severance Expense (55) - (55)
Stock-Based Compensation 4,844 636 5,480
Loss on Debt Extinguishment (315) - (315)
Total Pre-tax Adjustments $41,297 $636 $41,933
Adjusted EBITDAX Consolidated $259,109 $54,466 $313,575
Midstream Distributions 11,085 N/A N/A
Stand-alone EBITDAX $270,194 N/A N/A
Non-GAAP Reconciliation
44
Source: Company filings.
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Twelve Months
Ended
March 31, June 30, September 30, December 31, December 31,
($ in thousands) 2019 2019 2019 2019 2019
Net (Loss) Income ($64,651) $192,694 $143,960 ($240,055) $31,948
Interest Expense 35,771 40,152 38,405 37,051 151,379
Interest Income (722) (71) (1,078) (78) (1,949)
Income Tax (Benefit) Expense (11,559) 40,791 48,902 (50,398) 27,736
Earnings Before Interest & Taxes (EBIT) (41,161) 273,566 230,189 (253,480) 209,114
Depreciation, Depletion & Amortization 125,161 128,999 120,459 133,844 508,463
Exploration Expense 3,258 5,567 6,075 29,480 44,380
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $87,258 $408,132 $356,723 ($90,156) $761,957
Adjustments:
Unrealized Loss (Gain) on Commodity Derivative Instruments 153,994 (210,909) (156,872) (92,538) (306,325)
Impairment of Exploration and Production Properties - - - 327,400 327,400
Impairment of Unproved Properties and Expirations - - - 119,429 119,429
Loss on Certain Asset Sales and Abandonments 3,564 - - - 3,564
Severance Expense 23 1,182 1,999 113 3,317
Stock Based Compensation 10,903 23,873 1,781 1,868 38,425
Loss on Debt Extinguishment 7,537 77 - - 7,614
Shaw Event 4,305 - - - 4,305
Shaw Insurance Recovery - - - (2,159) (2,159)
Total Pre-tax Adjustments $180,326 ($185,777) ($153,092) $354,113 $195,570
Adjusted EBITDAX Consolidated TTM $267,584 $222,355 $203,631 $263,957 $957,527