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Earnings ResultsFirst Quarter 2020
April 27, 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, 2019 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; the impact that the current COVID-19 pandemic may have on us, our vendors and customers, including our financial position, operating results and ability to obtain future financing;
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.
Executive Summary
The CNX Philosophy and Approach to Making Decisions
4
CNX built a plan that consistently delivers substantial FCF year in and year out for the next seven years,
and current allocation of the FCF will focus on debt paydown
Our Approach:
1. We optimize long term net asset value (NAV) per share above all else
2. The best metric for optimizing NAV per share is consolidated free cash flow (FCF); maximizing consolidated free cash flow
strengthens the balance sheet, allows for opportunistic capital allocation, and protects us from the downside
3. The assumptions for the ‘uncontrollables’ applied when calculating IRRs have changed drastically; we live in reality, and so we
adjust the ‘controllables’ accordingly
4. The best way we optimize NAV per share is to be a great capital allocator who follows risk-adjusted internal rates of return (IRRs)
5. IRR math dictates where we allocate consolidated FCF; in today’s environment, opportunistic debt paydown across various
tranches of the debt stack is compelling
CNX’s Approach in Action
5
2019
Successful execution in
2019 positioned company
for 2020 and beyond
Q1 2020
CNX near-term maturities
were reduced by over
$300MM in Q1 2020
Q2 +2020
Philosophy continues to
drive tactics in Q2 2020
and beyond to navigate
downturn
CNX poised
to deliver
substantial
consolidated
FCF over
next 7 years
Plan
designed to
protect from
downside
risk, while
maintaining
access to
substantial
upside
Consolidated FCF(1) of ~$300 million expected in 2020 and ~$400 million in 2021
under the current strip(2) and protected by hedge book1
Path secured for retirement of 2022 notes2
Cumulative consolidated FCF(1) of $3.0+ billion over 7 year plan
under the current strip(2)3
5
(1) Non-GAAP measure. See appendix for definition.
(2) NYMEX as of 4/21/2020.
Q1 2020 Highlights
$267
$129$14
($152)
Net Cash Providedby Continuing
Operations
CapitalExpenditures
Proceeds from AssetSales
Free Cash Flow
Significant Free Cash Flow (FCF) Generation in Q1 2020
7
▪ During Q1 2020, we restructured a
portion of our 2022 through 2024 hedges
for $55 million
▪ This restructuring reestablished a new
hedge price for those volumes to protect
against downward natural gas price
movements
▪ Strong, efficient operating quarter
$129MM in Consolidated FCF(1)
$ in m
illio
ns
$129MM Consolidated FCF (1) in Q1 2020
(1) Non-GAAP measure. See appendix for definition.
Cardinal States Gathering (CSG) Financing Overview
8
$175 million of the 2-year $200 million original project financing target was completed in Q1
Deal Terms
◼ $175 million loan: $125 million tranche and $50 million tranche
◼ Blended average loan tenor is ~7.8 years
◼ Blended average loan interest rate is ~6.5%
Transaction Highlights
◼ Debt in an Unrestricted Subsidiary (like the CNXM Credit Facility or CNXM 2026 Bonds)
◼ Closed on March 13, 2020; in the face of the current oil price war and COVID-19 pandemic
◼ Proceeds used to pay down RBL in the short-term, and will ultimately be used to pay down our
2022 bonds
‒ Transaction unlocks the value of the CSG asset, which was previously collateral to the CNX
Credit Facility
◼ The financing is underpinned by an Offtake Agreement between CNX and Cardinal States,
providing cash flow to service the debt
‒ Leverage accretive to CNX’s RBL leverage covenants, while also providing additional near-
term liquidity for CNX to proactively repurchase its outstanding unsecured Notes, potentially
at a material discount to par
◼ CNX demonstrated access to capital markets at highly-competitive rates even in the face of
extreme market headwinds
Repurchased ~$79 Million of 2022 Notes at Significant Discount
9
2022 Notes outstanding have been reduced via open market repurchases:
▪ Utilized a portion of the proceeds from the Cardinal States Gathering (CSG) system project financing and hedge monetization executed in
Q1 2020 to repurchase a portion of outstanding 2022 Notes
▪ Opportunistically repurchased at a discount: repurchases have been, on average, at 85% of par value
▪ CNX entered into additional interest rate hedges for its outstanding RBL borrowings to lock-in borrowing rates into Q1 2024; allows
company to realize interest savings in excess of 3% versus the interest on the 2022 Notes
▪ Unlocked value within its existing debt stack via its capital allocation decision to repurchase the 2022 Notes at a discount to par and
prospectively via the ongoing interest savings
(1) As of 3/31/2020, $71 million of notes were repurchased leaving an outstanding amount of 2022 notes of $824 million. In April 2020, the company repurchased $7.6
million of its outstanding 2022 notes.
($ in millions)
Balance @ YE2019
Bonds
Repurchased
Current
Balance
Percent
Reduction
Average
Repurchase
Price Cash Outlay
Savings to
Par
$894 $79(1) $815 8.7% 84.7 $67 ($12)
Recent 2022 bond repurchases highlight optimal capital allocation created by FCF generation
2020 Plan Update
Spring 2020 Borrowing Base Redetermination Completed
11
▪ Borrowing Base and Revolving Credit Commitments redetermined at $1.9
billion
▪ Two significant transactions reduced the engineered value of the company’s
borrowing base:
- CSG project financing of $175 million
- Hedge monetization provided $55 million in cash proceeds
▪ CNX liquidity increased pro forma for the aforementioned transactions and
spring redetermination cycle
▪ Able to maintain significant liquidity despite lower bank commodity price
deck
▪ No amendments to financial or negative covenants were required
▪ CNX maintains $1.3 billion of pro forma liquidity post-redetermination
$2.1 $1.9
Commitments (Old) Commitments (New)
($ in billions)
CSG + Hedges
2020 “Super Contango” Gas Markets
121 4 7
10
13
16
19
22
25
28
31
34
37
40
43
46
49
52
55
58
61
64
67
70
73
76
79
82
85
88
91
94
97
100
103
106
109
112
115
118
Months
Significant portion of a well’s
productivity is in its first year of
production
▪ CNX has the flexibility to modify its production profile allowing
company to save some production to sell during significantly higher
prices this winter and next year
▪ CNX restructured its hedge book to take advantage of this opportunity
by monetizing significantly “in the money” 2020 hedges, giving us the
options to:
‒ Sell more gas into strong prices this winter and next year; or
‒ Increase production into summer if 2020 prices rally due to
associated gas shut-ins
▪ CNX’s ability to do this is unique amongst its peer group and ultimately
creates additional free cash flow and NAV/share without additional
capital expenditures
CNX’s focus on IRR math and identifying opportunities creates additional cash and
NAV/share over the next 2 years without incremental capital expenditures
Typical Production Profile of SWPA Marcellus Well
$1.90
$2.10
$2.30
$2.50
$2.70
$2.90
$3.10
May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21
NYMEX Henry Hub Forward Strip
Current Strip (4/23)
Low end of 2020 production range
assumes production weighted towards
winter and into 2021, while high end of
production guidance assumes
production is moved forward into
summer 2020
▪ CNX has various options at its disposal to adjust its
production profile during 2020 in order to maximize
NAV/share and cashflow
▪ Given current steep profile of the commodity curve,
the IRRs of certain wells are improved by modifying
our production profile to create more gas in the
winter of 2020 and more gas into 2021
▪ CNX has taken steps to modify hedge book to
provide this production flexibility
▪ As always, we will continually monitor the commodity
market and adjust our decisions in order to maximize
NAV/share to retain the flexibility to flow more
aggressively if the market conditions change
Production Profile and Hedge Management
13
(1) Current NYMEX Prices as of 4/23/2020.
0.7
0.8
0.9
1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.7
Bcfe
/d
Option to Defer Extra Production if Deferred Minimum Production
$2.23/MMBtu
Expected Daily Production 2020(1)
2020 TILs
Marcellus: 34
Utica: 12
Option to Time
Production to
Maximize Cash
Flow and NAV
Improved
Summer Prices
Stronger
Winter
and
2021
Prices
$2.90/MMBtu
2020 Wet Gas Markets: Minimal Impact
14
Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020Q2 2020
(Forecast)
Q3 2020
(Forecast)
Q4 2020
(Forecast)
NGLs ($/Bbl) $26.76 $18.36 $13.68 $19.20 $14.04 $4.59 $6.35 $8.54
NGL Revenue ($MM) $29.8 $24.0 $18.3 $32.0 $19.4 $3.5 $3.3 $6.9
Condensate/Oil($/Bbl) $39.27 $45.62 $35.48* $44.80 $39.56 $9.42 $15.63 $18.63
Cond/Oil Revenue ($MM) $2.5 $1.8 $0.9 $4.0 $2.5 $0.2 $0.1 $0.6
Combined Liquids % of Revenue** 7% 8% 7% 11% 9% 2% 2% 2%
▪ COVID-19 response caused an unprecedented collapse in demand for
butanes, C5+ and condensate to the point that wet gas wells may be
forced to shut-in.
▪ Even if not shut-in, prices for these products will be dramatically reduced.
▪ This will likely have a material impact to wet producers.
▪ CNX is protected from this issue due to its focus on dry gas and
CNXM’s flexible gathering system.
0
1
Bcfe
/d
Dry Volumes Damp Volumes with Blending Flexibility Wet Gas
CNX Historical Operated Wellhead Volumes Wet vs. Dry
Guidance assumes conservative
prices for NGLs and condensate
for 2020
CNX is not materially impacted
by lower for longer oil and
condensate prices.
* Represents $/Bbl price before prior period adjustments; $73.12 per Bbl including prior period adjustment.
** % of natural gas, NGL, and oil revenue.
Refund Reconciliation ($ in millions):
AMT Credit $102
Other Prior Year Refunds $11
Prior Year AMT Sequester Refunds $2
Total 2020 Anticipated Refunds $115
March 31, December 31,
2020 2019
Current Assets ($ in 000s)
Cash and Cash Equivalents $31,833 $16,283
Restricted Cash 853 -
Accounts and Notes Receivable
Trade 91,477 133,480
Other Receivables 10,839 13,679
Supplies Inventories 10,266 6,984
Recoverable Income Taxes 115,261 62,425
Derivative Instruments 312,749 247,794
Prepaid Expenses 12,775 17,456
Total Current Assets 586,053 498,101
2020 AMT Credit and Additional Refunds
15
▪ AMT credit refund expected in 2020 of approximately $102 million due
to accelerating the receipt of the AMT refund previously expected in
2021, as a result of the passage of the CARES Act of 2020
- Expected AMT refunds in 2021 are now zero due to acceleration
into 2020
▪ Company continues to expect no cash tax payments for at least 5
years due to NOL utilization
Combined AMT refund and additional prior year tax
refunds to drive total cash tax inflow of ~$115
million in 2020
Updated 2020 Guidance
Note: See appendix for Non-GAAP definition.
(1) Forward market prices are as of 4/21/2020.
(2) Includes approximately $32 million of projected distributions from ownership interests in CNXM and a $50 million payment associated with the IDR Elimination
Transaction.
(3) Includes ~$50M in expected asset sales in 2020. 16
Previous UPDATED
2020E 2020ECapital Expenditures($ millions)
Low High Low High
Drilling & Completions $360 $410 $330 $380
Non-D&C $90 $100 $75 $85
Total E&P Capital $450 $510 $405 $465
CNX Midstream LP Capital $80 $100 $65 $85
Total Consolidated Capital $530 $610 $470 $550
Production Volumes (Bcfe) 525 555 490 530
Prices on Open Volumes
Natural Gas NYMEX ($/MMBtu)(1) $2.27 $2.16
Natural Gas Basis Differential ($/MMBtu)(1) ($0.25)-($0.35) ($0.25)-($0.35)
NGL Realized Price ($/Bbl)(1) $15.50-$17.50 $8.00-$10.00
Adjusted EBITDAX(2) ($ millions)
E&P Standalone + Distributions(2) $765 $810 $715 $755
Consolidated $885 $950 $830 $900
Free Cash Flow (FCF) ($ millions)
Standalone FCF(2)(3) ~$250 ~$300
Consolidated FCF(3) - ~$300
Total consolidated capital expenditures down ~10%
Optimizing the production profile due to a combination of
low NGL, condensate, and gas pricing this summer and
higher pricing this winter, and into 2021
Due to CNXM distribution reduction, standalone adjusted
EBITDAX went down by $50 million while standalone FCF
went up by $50 million
Conservative liquids price assumptions for 2020 protects
downside and provides upside if the situation improves
Business Update
▪ Significant SWPA gas infrastructure build for core Marcellus and Utica is in close-out phase in 2020
▪ Positive operating leverage from the build out results in lower go-forward capital intensity and stable free cash flow
generation from fixed-fee commercial agreements
▪ CNXM following FCF optimization approach of sponsor: reducing equity payout levels, paying down debt, and
building liquidity position
- Reduced distributions increases available cash by $30 million per quarter. Stores value on the balance
sheet to redeploy in highest return options
CNXM Key Information
CNXM Ownership: Valuable Midstream Company
17
✓ Low Leverage: 3.1x, TTM as of 3/31/2020
✓ Strong Liquidity: $258 million
✓ Stable Free Cash Flows: ~$90 million, 2020E
CNX Midstream is a stable free cash flow generating business. Additional cash flow
retention bolsters CNXM’s already strong balance sheet.
✓ Significant Sponsor Ownership: 53% interest
✓ Debt Maturity: No maturities until 2024
✓ Business Lines: Stable natural gas transportation
2022 Bond Retirement Addressed
$140
$300
$175
$200$160
$25
Q1 2020 CNX Debt Reduced Remaining 2020 CNX Debt Reduction Total 2020
CNX Reduces Near-Term Debt by Over $500 Million in 2020
$12MM Bond Buy Back
Savings to Date
E&P Stand-
Alone FCF(1)
Project
Financing
Reduced $300MM+
debt in Q1
~ $200MM Remaining
Over $500MM in
CNX debt reduced
($ in millions)
19
(1) Non-GAAP measure. See appendix for definition.
Free cash flow will be used to pay down the 2022 notes
$500 $500
$661 $700
$895
$350
CNX Net Debt Significantly Reduced & 2022s Addressed
Notes: Net debt excludes $175 million of project financing debt related to the company’s CSG assets. This debt is an un-restricted subsidiary and fully secured by the
CSG system.
(1) 12/31/2019 E&P net debt includes $15 million of cash and $8 million of debt issuance costs.
(2) CNXM market value as of 4/23/2020.
(3) Assumes that CNX draws $700 million on RBL and has $205M in LOC on its $1.9 billion credit facility.20
E&P Net Debt at CNX(1)
$2,033
~$1,550
2022s RBL 2027s
12/31/2019 12/31/2020E 2022 Bond 2021 thru 4/1/2022 FCF
$634M
CNXM LP
Unit
Value(2)
$995M
RBL
Liquidity(3)
~$1,630
E&P FCF
~$350MM
Remaining 2022 Bonds
Paid off with FCF from
the business
CNX will have $1.6B of liquidity
with no debt maturities until 2027
2022 Liquidity
($ in
mill
ion
s)
$350
Balance Sheet is Getting Stronger
21
(1) Non-GAAP measures. See appendix for definition.
(2) Forecasted net debt excludes debt related to the recent CSG project financing, which is an unrestricted subsidiary.
(3) LP-adjusted leverage assuming CNXM LP ownership is used to offset the debt. CNXM market value as of 4/23/2020.
$ in millions
Stand-AloneStand-Alone E&P Net Debt
and Leverage(1)
March 31, 2020
Total Long-Term Debt (GAAP)(2) $1,757.2
Less: Cash and Cash Equivalents $31.7
Forecasted 2020E E&P Net Debt (Non-GAAP)(1)(3)~$1,550.0
2020 Forecasted Stand-Alone
Leverage Ratio(1) ~2.1x
2020 Stand-Alone Adjusted EBITDAX(1) $735.0
Less: Forecasted Remaining 2020 Total FCF(1) $160.0
LP-Adjusted(3)
~$915.0
~1.2x
$735.0
Less: 50.7M units
x $12.50(2)Less: Additional Project Financing $25.0
Leverage Ratio
Set To Go Lower Each and Every Year
in 7-Year FCF Plan
$1,757.2
$31.7
$160.0
$25.0
1,246
1,882
845
100
3,589
2,977
891
350
2,387
2,505
250
1,706
760
300
1,221
4,746
800694
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Appala
chia
EF
/ H
Y
Perm
ian
Bakken
DJ
Oth
er
App
ala
ch
ia
EF
/ H
Y
Perm
ian
Bakken
DJ
Oth
er
Appala
chia
EF
/ H
Y
Perm
ian
Bakken
DJ
Oth
er
Appala
chia
EF
/ H
Y
Perm
ian
Bakken
DJ
Oth
er
Appala
chia
EF
/ H
Y
Perm
ian
Bakken
DJ
Oth
er
2020 2021 2022 2023 2024
$ in
mill
ion
s
< 70 70-80 80-90 90+
The HY Credit Market Reflects CNX’s Strength
22
Source: Bloomberg
Bid Price
CNX 5.875s of ’22: $97.50
CNX has outperformed on
a relative value basis
High-Yield E&P Maturities
7-Year Free Cash Flow Plan
7-Year Plan Overview
24
2020-2021: 2-Year Bond Paydown Plan
▪ 2020 and 2021 plans developed to maximize FCF and to ensure
CNX paydown of the 2022 notes prior to maturity
▪ Cash flows are protected by hedge book and already completed
projects such as the $175 million CSG financing
▪ Midstream infrastructure buildouts substantially complete and the
business will have fully matured into a higher production profile by
the end of 2021
▪ Completion of the balance sheet and cost transition the company
has been on for some time now
▪ Capability to modify capital and production profiles to react to
natural gas prices change, up or down
▪ By 2022, CNX has a best-in-class balance sheet cost structure
with greatly reduced capital intensity to maintain production level
2022-2026: 5-Year FCF Plan
▪ Major infrastructure and land cost spend behind us for our MOP
development plan areas
▪ Fully burdened costs materially lower, with reduced legacy FT and
firm processing burdens, lower interest costs and more efficient
operations driven by investments in our water systems and
remote operating capabilities
▪ Capex intensity materially lower
▪ Strong free cash flows generated from a MOP plan at the current
$2.40 NYMEX gas strip (while peers struggle to break even)
▪ Significant ability to return capital to shareholders during this time
▪ Significant ability to increase production if conditions warrant due
to our strong balance sheet and deep inventory
2021 is Positioned for Optionality
25
▪ FCF plan produces over $400 million in consolidated FCF(1) in
2021 at the current strip
- Sets 2022 to easily grow ~5% if natural gas prices and
capital markets warrant
▪ Reduces debt and leverage
▪ CNX can grow significantly and still generate substantial FCF
- Could produce ~600 Bcfe in 2021 if pricing strengthens
- Could grow another ~10% in 2022 if pricing strengthens
▪ Reduces debt and leverage
If Commodity Prices
Strengthen
If Commodity Prices
Remain Depressed
(1) Non-GAAP measure. See appendix for definition.
No matter the conditions, in 2021, CNX will produce significant FCF at both CNX and CNXM
and will deploy FCF to grow NAV per share
26
Free Cash Flow Plan Provides Opportunity
Methodically Develop
Assets at High Internal
Rates of Return at Current
Strip Pricing
◼ Drill ~25 wells per year
◼ Average 7-year annual production of approximately 540 Bcfe
◼ Operational flexibility to quickly re-position from maintenance mode to growth mode
Continue to
Programmatically Hedge to
Cover D&C Capital Moving
Forward
◼ Ensuring cashflow visibility and returns
◼ Reduce net Leverage with FCF
◼ Additional FCF generation from derivative contracts provides further de-leveraging capabilities
Generate Significant FCF at
Current Strip
◼ Competitive break-evens and asset returns generate substantial free cash flow at strip pricing
◼ Follow the math on how to allocate FCF
◼ Ability to pay down all debt with substantial FCF generation expected from 7-year plan
Protected base plan also provides the optionality to increase activity as conditions warrant
$0.68 $0.69 $0.68
$1.03 $1.04 $1.03
$2.50 $2.44 $2.43
2022E 2023E 2024E
Operating Fully burdened NYMEX gas strip(3) (1)
FCF Plan Assumptions
27
(1) NYMEX strip pricing per MMBtu and as of 4/21/2020.
(2) Non-GAAP measure. See appendix for definition.
(3) Fully burdened cash costs include production cash costs, selling, general and administrative (SG&A) cash costs, other operating cash expense, other cash (income)
expense, and interest expense.
Capital plan
2022E - 2026E (annual avg.)
TIL Count ~25
Net production (Bcfe) ~560
Capital Expenditures ($ in millions)
Drilling & Completion ~$230
Other ~$40
Total (Standalone CNX) ~$270
CNX Midstream ~$30
Total (Consolidated) ~$300
Consolidated cash costs(2)
2022E - 2026E (annual avg.)
Operating cash cost ~$0.69
Fully burdened cash cost(3) ~$1.04
Estimated 2022E – 2024E cash costs ($ / Mcfe)
2025-2026 operating and fully burdened costs
approximately the same as 2022-2024
$2.50 $2.44 $2.43 $2.44 $2.47
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$0
$100
$200
$300
$400
$500
$600
$700
2022E 2023E 2024E 2025E 2026E
$/M
mbtu
$ in m
illio
ns
CNX FCF & ownership share of CNXM FCF Asset Sales NCI CNXM FCF NYMEX
7-Year Plan Generates Substantial Free Cash Flow
28
Aggregate consolidated FCF of ~$700
million for 2020 and 2021 protected by
hedge book
By 2022, the company’s material cost and
capital efficiencies provide a step change,
and the business generates strong FCF in
the low strip environment that exists in 2022
and beyond
At the current gas strip, over $3 billion of
cumulative consolidated FCF is generated
over next 7 years.
At $2.75/MMBtu: Annual consolidated FCF
for 2022E-2026E averages $630 million
At $3.00/MMBtu: Annual consolidated FCF
for 2022E-2026E averages $730 million
(1) Non-GAAP measures. See appendix for definition.
Annual 2022E-2026E Consolidated FCF(1) at Current Strip Pricing
Annual consolidated FCF for 2022E-
2026E averages $500 million
CNX is Uniquely Differentiated
30
Large, High Quality Inventory in the Core Marcellus and Utica Supports Low Maintenance Capital
Low Operating Cash Costs Matter Even More in a Low Price Environment
Strong Hedge Position Protects Future Cash Flows and Ensures Capital Returns
Reducing Net Debt and Leverage Ratio with Free Cash Flow at Current Strip pricing
Substantial Free Cash Flow Each Year Across 7-Year Plan at Current Strip Pricing
Operational Advantages with High NRIs and Control of Midstream and Water Systems
Strong Balance Sheet and Minimal Firm Transportation (FT) and Off-Balance Sheet Obligations
Proactive Management with Focus on Optimizing NAV per Share
30
Differentiating Highlights
97%
89%
40%
22%
3%0% 0%
$2.79
$2.90
$2.53
$2.40
$2.62
$ 1.90
$ 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 %
Peer 1 CNX Peer 3 Peer 2 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
95%
94%
89%
77%
64%
49%
5%
$ 2.95
$ 2.87
$ 2.70
$ 2.57
$ 2.64
$ 2.88
$ 2.22
$1.90
$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
2020 % of Production Hedged 2020 Average NYMEX Price Floor
Pri
ce F
loo
r
Best Downside Protection in the E&P Space
Note: Peers include AR, COG, EQT, GPOR, RRC, SWN. As of Q1 2020 for CNX and as of Q4 2019 for peers. NYMEX as of 4/21/2020. CNX hedge price per Mcf and
per MMBtu for peers.
(1) Based on Bloomberg consensus estimates 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. 31
2020E(1) Hedged Gas Production 2021E(1) Hedged Gas Production
~60% of 2022(1) production
hedged under maintenance
scenario at $2.83 NYMEX
vs.
~4% for peers at $2.42
NYMEX
NYMEX Strip $2.16 in 2020
NYMEX Strip
$2.73 in 2021
~34% of 2023(1) production
hedged under maintenance
scenario at $2.80 NYMEX
vs.
~2% for peers at $2.57
NYMEX
$0.70 $0.77
$1.10 $1.13
$1.26 $1.30
$1.65
$2.15
$-
$0.75
$1.50
$2.25
CNXConsolidated
Peer 1 Peer 2 CNX Peer 3 Peer 4 Peer 5 Peer 6
Lease Operating Expense ($/Mcfe) Production, Ad Valorem, and Other Fees ($/Mcfe) Transportation, Gathering and Compression - E&P ($/Mcfe)
32
E&P Leading Consolidated Cash Costs
(1) TTM as of Q1 2020 end for CNX and TTM as of Q4 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 eliminates intercompany gathering charges between CNX and CNX Midstream. $0.70 per Mcfe is forecasted consolidated cash costs in 7-year plan.
(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 Q1 2020 for CNX and TTM as of Q4 2019 for peers.
TTM Q1 2020/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 2.4 1.4 1.5 4.1 2.1 2.3 3.2
(2)
(3)
0.7 x 2.1 x 3.0 x5.5 x
2.8 x 4.2 x5.9 x
1.2 x
2.5 x
11.1 x9.5 x 14.6 x
13.3 x
17.0 x
2.0 x
4.6 x
14.2 x15.0 x
17.4 x 17.5 x
22.8 x
Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
0.7 x
2.1 x
2.8 x3.0 x
4.2 x
5.5 x5.9 x
Peer 1 CNX Peer 4 Peer 2 Peer 5 Peer 3 Peer 6
Highly Resilient Balance Sheet
33
Note: Peers include AR, COG, EQT, GPOR, RRC, SWN.
(1) For peers based on FactSet consensus estimates for 2021E EBITDA and 2021E net debt as of 4/22/2020. CNX 2021E based on forecast. Off-balance sheet
obligations based on the respective 2019 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
▪ 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
395%
301%
281%272%
244%
85%
29%
Peer 2 Peer 4 Peer 3 Peer 5 Peer 1 CNX Peer 6
88%86%
71%
61%
57%
39%
13%
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 CNX Peer 6
309%
240%
215% 211%
157%
46%
16%
Peer 2 Peer 4 Peer 5 Peer 3 Peer 1 CNX Peer 6
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 4/22/2020. Peers include AR, COG, EQT, GPOR, RRC, SWN.
(1) CNX total debt is E&P stand-alone and as of Q1 2020 and as of Q4 2019 for peers, excludes lease obligations; per latest company filings. Off-balance sheet obligations
based on respective 2019 10-Ks of CNX and peer companies. 34
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
CNX Acreage Position Remains Top-Tier in Appalachia
Source: Company reports. Peers include AR, COG, EQT, GPOR, RRC, SWN.
Note: 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).
Any incremental leasing and associated land leasing capital spend would increase the number of undeveloped locations.
(1) Includes 6,000 acres that CNX expects to acquire in 2020. 35
Appalachian Peer Group Net Acres CNX SWPA Central Marcellus Locations(1) Assuming a run rate of 25
SWPA Central Marcellus TILs
per year:
SWPA Marcellus inventory to
stay at MOP production for 15
years
CNX maintains ~12 years of
additional inventory in
Shirley/Pens WVa., assuming 1
pad per year
CNX maintains ~25 years of
additional Marcellus inventory in
CPA South, along with 20 years
of Utica inventory
2022 and beyond MOP plan
only needs 25 TIL’s per year on
average going forward
CNX’s controlled acres are:
▪ 87% NRI vs. 80% peer avg.
▪ 91% HBP
▪ 6% developed
SWPA Tier 1 Undeveloped Acres 53,700
Divided by
Acres per well 164
Equals
Total Undrilled Locations(1) 365
Average wells TIL 25
Years Inventory remaining ~15
▪ 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
▪ Last SWPA Utica D&C costs at ~$1,420 per ft, well below
$1,800 per ft target
0
5
10
15
20
25
30
35
40
45
50
0 100 200 300 400 500 600 700
Daily
Pro
duction (
mm
cf)
Days
BP6 AIKENS5J AIKENS5M GAUT4 CPA Dry Utica Type Curve
CPA Dry Utica Results Remain Consistent and Strong
36
CPA Dry Utica Results
Daily Production Normalized to 7000’
CPA Dry Utica Cumulative Production
Normalized to 7000’
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0 100 200 300 400 500 600 700
Cum
ula
tive P
roduction (
MM
cf)
Days
BP6 AIKENS5J AIKENS5M GAUT4
BP6
outperforming
type curve
▪ CNX maintains ~20 years of Utica inventory in CPA region
▪ CPA Utica IRRs are competitive with SWPA Marcellus
37
18% 14% 10% 7% 6% 6% 5%
(1%) (4%) (5%) (13%)
(45%)
CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11
2021E Free Cash Flow Yield(1)CNX Appalachia peers Other E&P Mid-caps
Source: Public filings, FactSet as of 4/24/2020.
(1) Free Cash Flow Yield is a non-GAAP measure and defined as (Operating Cash flow – Capex) / Current Market Capitalization; CNX 2021E is based on company
projections; CNX 2021E EBITDAX assumes $82 million from CNXM distributions and IDR buyout payment; CNXM 2021E used for deconsolidation based on
broker consensus estimates; all other figures based on broker consensus estimates; Appalachia includes: AR, COG, EQT, GPOR, RRC, and SWN; Other E&P
Mid-caps includes: CRK, MGY, PE, WPX, and XEC.
Appalachia peers median: (5%)
Other E&P Mid-caps median: 6%
CNX is a Compelling Investment Opportunity with Best in Class FCF Generation, In-line Leverage, and a Discounted Valuation
8.7x 7.8x 6.4x 5.8x 5.8x 5.4x 5.1x 5.0x 4.8x 4.8x 4.6x 4.0x
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11
Enterprise value / 2021E EBITDAX
(E&P only)
Appalachia peers median: 6.1x
Other E&P Mid-caps median: 5.0x
0.3x 0.7x 1.4x 1.6x 2.2x 2.3x 2.3x 2.4x 2.5x 3.0x 3.5x 4.0x
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11
Current net debt / LTM EBITDAX
(E&P only)
Appalachia peers median: 2.4x
Other E&P Mid-caps median: 1.6x
We are Well Positioned for Substantial FCF Generation
38
Strong Balance Sheet
✓ Easily manageable debt and leverage
metrics relative to Appalachian peers
✓ Leverage ratio and net debt steadily
declining
CNX’s downside protection and upside potential is unique and provides
undervalued investment opportunity with bright future
More than Adequate Liquidity✓ Current E&P liquidity of ~$1.3 billion and
consolidated liquidity over $1.5 billion
✓ Unique hedging position ($370 million
fair value) provides downside protection
Peer-leading Results
✓ Cumulative consolidated FCF(1) of $3.0+
billion over 7 years plan under strip
✓ Tremendous FCF upside over next 7
years if commodity prices increase
Upside Potential
✓ Currently trading near peer average
multiples, despite tremendous growth
opportunity and consistent future cash
flow generation
(1) Non-GAAP measures. See appendix for definition.
Appendix
Operational Highlights
40
Drilling
▪ Improved efficiencies in lateral feet per day leading to capital expenditure reductions in West Virginia Marcellus and Ohio Utica of $50 per foot and $150 per foot, respectively
Completions
▪ Capital expenditure reductions due to supply chain saving and increased efficiencies of ~$25 million in 2020
▪ Remote operations implemented for stimulation operations to mitigate the risk of COVID-19
▪ Increased automation for water transfer leading to lower labor costs
Production and Midstream Highlights
▪ 6-well RHL 71 pad peak rate of 157 MMcf per day
▪ Decreased capital expenditures by flowing back stimulated wells through production equipment
▪ Decreased lease operating expense (LOE) by $50,000 per month by decommissioning compressor facility
CNX Drilling Operations
COVID-19 Response Plan
41 41
▪ Mandatory Work From Home for all office-based employees and contractors, except for Gas Control Personnel
- Gas Control Personnel have been separated to different floors and locations
- Multiple back up locations established for gas control
▪ Suspension of all business travel out of operating area
▪ Established disinfecting protocol – specialist contractor retained to perform routine disinfecting of all of our locations
▪ Established social distancing protocols for all field locations
- Do not enter indoor spaces unless you have a specific business purpose to be there
- Do not car pool to field locations
- Do not work together on tasks unless necessary for safety
- For any exceptions to the above rules, “buddy up” – e.g. if you have to car pool, ride with the same people everyday and for
jobs that require a team, do not mix teams
- No entry for any person who is ill
▪ Established Response Protocol for all field locations in the event of a suspected case of COVID-19
▪ Continually refining and adjusting response plan to stay in line with recommendations from the CDC
451.1 433.5
279.8
162.9 149.7
0
50
100
150
200
250
300
350
400
450
500
2020 2021 2022 2023 2024
Gas V
olu
mes H
edged (
Bcf)
NYMEX + Basis (2)
Natural Gas Hedging and Basis Protection
42
(2)
Hedge Volumes and Pricing Q2 2020 2020 2021 2022 2023 2024
NYMEX Hedges
Volumes (Bcf) 110.7 439.2 411.7 265.5 135.1 138.7
Average Prices ($/Mcf) $2.98 $2.95 $2.90 $2.83 $2.80 $2.91
Physical Fixed Price Sales and Index Hedges
Volumes (Bcf) 2.8 11.9 21.8 14.3 27.8 11.0
Average Prices ($/Mcf) $2.43 $2.44 $2.47 $2.59 $2.15 $2.28
Total Volumes Hedged (Bcf)(1) 113.5 451.1 433.5 279.8 162.9 149.7
NYMEX + Basis (fully-covered volumes)(2)
Volumes (Bcf) 113.5 451.1 433.5 279.8 162.9 149.7
Average Prices ($/Mcf) $2.53 $2.55 $2.41 $2.29 $2.25 $2.32
NYMEX Hedges Exposed to Basis
Volumes (Bcf) - - - - - -
Average Prices ($/Mcf) - - - - - -
Total Volumes Hedged (Bcf)(1) 113.5 451.1 433.5 279.8 162.9 149.7
Fully-covered hedges represent
~93% 2020E base dry gas
volumes(3)
NYMEX hedges added during Q1:
28.9 Bcf (2024 and 2025)
Index hedges added during Q1:
13.6 Bcf for 2025
Basis hedges added during Q1:
39.1 Bcf (2020, 2021, and 2025)
Despite cashing in
$55M of value and
resetting 2022-2024
hedges, still
maintain strong
average hedge
prices
(1) Hedge positions as of 4/21/2020. Excludes basis hedges in excess of NYMEX hedges of 1.0 Bcf, 8.1 Bcf, 15.7 Bcf, 25.0 Bcf, 9.3 Bcf, and 0.4 Bcf for Q2 2020, 2020,
2021, 2022, 2023, and 2024, respectively.
(2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements.
(3) Assuming midpoint of total dry gas production guidance for 2020E.
Financial Guidance
43
PREVIOUS (1/30/2020) UPDATE (4/27/2020)
2020E 2020E
Revenue and Other Operating Income E&P Consolidated E&P Consolidated
Production Volumes:
Natural Gas (Bcf) 495-525 465-500
NGLs (MBbls) 4,535-4,760 3,485-4,400
Condensate (MBbls) 245-265 110-170
Total Production (Bcfe) 525-555 490-530
% Liquids ~5%-6% ~5%-6%
Natural Gas NYMEX Price ($/MMBtu)(1) $2.27 $2.16
Natural Gas Basis Differential to NYMEX ($/MMBtu)(1) ($0.25)-($0.35) ($0.25)-($0.35)
NGL Realized Price ($/Bbl)(1) $15.50-$17.50 $8.00-$10.00
Condensate Realized Price % of WTI(1) 70% 70%
Realized Hedging Gain/(Loss) ($ in millions)(2) $210-$220 $255-$265
Other Operating Income (3rd party water income and resold FT) ($ in millions) $10-$20 $10-$20
CNXM 3rd Party Gathering Revenue $70-$75 $40-$50
Costs
Average per unit operating expenses ($/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 $5-$15
Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$75 $80-$95
Other Non-Operating Expense (Income) $0-$10 ($5)-$0
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 4/21/2020.
(2) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing as of 4/21/2020. Anticipated hedging activity is not included in projections.
(3) Excludes stock-based compensation.
$78 $80
$95
$118
$160$170
$181
$253
$-
$0.05
$0.10
$0.15
$0.20
$0.25
$0
$50
$100
$150
$200
$250
$300
$350
Peer 1 CNX - 2020EStand-Alone
Guidance
Peer 2 CNX -Stand-Alone
Peer 4 Peer 3 Peer 5 Peer 6
To
tal S
G&
A (
$/M
cfe
)
To
tal S
G&
A A
bso
lute
Dolla
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
44
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 approximately 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 Q1 2020 end for CNX and TTM as of Q4 2019 for peers. Peers include AR, COG, EQT, GPOR, RRC, SWN.
TTM Q1 2020/Q4 2019 SG&A(1)
Q1 2020 Financial Results Summary
45
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) Capital expenditures exclude $31 million and $76 million of total capital investment net to CNXM in the first quarter of 2020 and 2019, respectively, as reported in CNXM
First Quarter Results.
(2) See the "Price and Cost Data Per Mcfe" in the appendix for a reconciliation to total Production Costs.
(3) 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
March 31, March 31,
(Per Mcfe) 2020 2019
Average Sales Price - Total Company $2.59 $2.97
Total Production Cash Costs(2)
$1.11 $1.11
Operating Cash Margin $1.48 $1.86
Operating Cash Margin (%) 57% 63%
Total Fully Burdened Cash Costs(3)
$1.66 $1.61
Fully Burdened Cash Margin $0.93 $1.36
Fully Burdened Cash Margin (%) 36% 46%
Quarter
Ended
Quarter
Ended
Quarter
Ended
Quarter
Ended
March 31, March 31, March 31, March 31,
2020 2019 2020 2019
($ in millions, except per share data) Stand-alone% Increase/
(Decrease)Consolidated
% Increase/
(Decrease)
Adjusted Net Income $193 $28 589.3% $113 $67 68.7%
Adjusted EBITDAX $248 $224 10.7% $291 $268 8.6%
Capital Expenditures(1)
$121 $223 -45.7% - - -
$1.70 $1.69 $1.63 $1.66
$0.93 $0.82
$0.91 $0.93
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
Q2 2019 Q3 2019 Q4 2019 Q1 2020
Total Fully-Burdened Cash Costs Total Fully-Burdened Cash Margin
$1.18 $1.13 $1.11 $1.11
$1.45 $1.38 $1.43 $1.48
$0.00
$0.50
$1.00
$1.50
$2.00
Q2 2019 Q3 2019 Q4 2019 Q1 2020
Total Production Cash Costs Total Production Cash Margin
Margin 55% 55% 56% 57%
Q1 2020 Operational Results Summary
46
▪ Marcellus Shale cash production costs were $1.27 per Mcfe in Q1
2020, down $0.06 from $1.33 per Mcfe in Q1 2019, or a 5% decrease
▪ Utica Shale cash production costs were $0.49 per Mcfe in Q1 2020, an
increase of $0.02, from $0.47 per Mcfe in Q1 2019
- The increase in Utica cash costs was mainly a result of higher
gathering costs due primarily to a change in production mix
▪ E&P stand-alone capital expenditures decreased 46% Y/Y to $121
million in Q1 2020 from $223 million spent in Q1 2019
(1) Average sales prices for 1Q2020, 1Q2019, and 4Q2019 include gain (loss) on commodity derivative instruments
(cash settlements) of $0.77, ($0.33), and $0.33 per Mcf, respectively.
(2) Total Production Costs for 1Q2020, 1Q2019, and 4Q2019 include DD&A of $0.87, $0.88, 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. Q1 2020, Q4 2019, Q3 2019, and Q2 2019 total fully burdened cash costs exclude a gain on asset sales of $0.09, $0.25 per Mcfe,
$0.03 per Mcfe, and $0.00 per Mcfe, respectively. Q1 2020 excludes unrealized loss on interest rate swap of $0.08 per Mcfe and hedge monetization gain.
Production Cash Costs(3) and Margins 2Q19-1Q20 Fully-Burdened Cash Costs(4) and Margins 2Q19-1Q20
$/M
cfe
$/M
cfe
Margin 35% 33% 36% 36%
($/Mcfe) 1Q 2020 1Q 2019
Y/Y
Change 1Q 2020 4Q 2019
Q/Q
Change
Average Sales Price(1)
$2.59 $2.97 ($0.38) $2.59 $2.54 $0.05
Total Production Costs(2)
$1.98 $1.99 ($0.01) $1.98 $1.97 $0.01
Sales Volumes (Bcfe) 134.4 133.0 1.4 134.4 143.4 (9.0)
Sales Volumes by Category (Bcfe)
Marcellus 96.3 88.7 7.6 96.3 101.3 (5.0)
Utica 24.8 30.6 (5.8) 24.8 28.3 (3.5)
CBM 13.2 13.7 (0.5) 13.2 13.7 (0.5)
Other 0.1 0.0 0.1 0.1 0.1 0.0
Q1 2020 Activity Summary
47
(1) Measured in lateral feet from perforation to perforation.
Q1 2020
($ in millions) TD FRAC TIL
Average
Lateral
Length(1)
Rigs at
Period
End
SWPA
Central
Marcellus - 10 10 13,730 1
Utica 1 3 4 9,050 1
WV
Shirley-Penns
Marcellus 7 - - - -
Utica - - - - -
CPA South Utica - - - - -
OH Dry Utica 2 - - - -
Total 10 13 14 2
Expect to run 1-2 rigs and 1 frac crew in 2020
Natural Gas and Liquids Realizations
48
2020 2019
Q1 Q1
NYMEX Natural Gas ($/MMBtu) $1.95 $3.15
Average Differential (0.26) (0.17)
BTU Conversion (MMBtu/Mcf)* 0.14 0.23
Gain on Commodity Derivative
Instruments-Cash Settlement**0.77 (0.33)
Realized Gas Price per Mcf $2.60 $2.88
* Conversion factor 1.08 1.07
Natural Gas Price Reconciliation
Average Price Realization ($ per Bbl)
2020 2019
Q1 Q1
NGLs $14.04 $26.76
Oil $47.22 $43.56
Condensate $37.68 $39.00
** Excludes gain from hedge restructuring.
Natural Gas Liquids, Oil and Condensate
▪ Q1 2020 liquids sold: 8.7 Bcfe
▪ Total weighted average price of all liquids decreased 45% to $15.14
per Bbl in Q1 2020 from $27.41 per Bbl in Q1 2019 and decreased
26% from $20.49 per Bbl in Q4 2019.
▪ In Q1 2020, liquids comprised 6% of production volumes and 9% of
natural gas, NGLs, and oil revenue.
2020E CY 2020
Gas Sold (%) Basis
DOM South 7% ($0.47)
ETNG Mainline 5% $0.13
TCO Pool 17% ($0.34)
TETCO ELA & WLA 6% ($0.08)
TETCO M3 7% ($0.07)
TETCO M2 29% ($0.48)
Michcon 11% ($0.18)
Physical basis sales 18% ($0.21)
Weighted Average Basis 100% ($0.29)
NYMEX $2.16
Weighted Average Basis (Not considering hedging) ($0.29)
2020E Realized Price (per MMBtu) $1.87
Conversion Factor (MMBtu/Mcf) 1.079
2020E Realized Price (per Mcf) $2.02
Market
Financial Guidance: 2020E Natural Gas Marketing Mix and Basis
49
Northeast Pipeline Projects
Southeast Pipeline Projects
ETNG
2020E Gas: 10%
CY20 Basis: $0.13
TCO Pool
2020E Gas: 22%
CY20 Basis: ($0.34)
TETCO ELA & WLA
2020E Gas: 6%
CY20 Basis: ($0.08)
Dawn Pipeline Projects
Gulf Market Pipelines
Michcon
2020E Gas: 11%
CY20 Basis: ($0.18)
DOM South
2020E Gas: 10%
CY20 Basis: ($0.47)
TETCO M2
2020E Gas: 34%
CY20 Basis: ($0.48)
TETCO M3
2020E Gas: 7%
CY20 Basis: ($0.07)
Percentages include physical sales
Note: Forward market prices are as of 4/21/2020.
Q2 2020 and 2020 Gas Hedging Gain/Loss Projections
50
▪ 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: 94.1 Bcf
▪ Physical sales provide additional basis hedge
- Flows through gas sales in financials
▪ Excludes 39 million MMBtus of hedges CNX monetized for $29 million that would have otherwise matured later in 2020
Q2 2020 CY2020
Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted
Hedged Volumes Hedged Forward Gain/(Loss)(2)
Hedged Volumes Hedged Forward Gain/(Loss)(2)
(000 MMBtu) Price Market(1)
($ in 000s) (000 MMBtu) Price Market(1)
($ in 000s)
($/MMBtu)
NYMEX 119,265 $2.76 $1.81 $114,155 473,353 $2.74 $2.16 $272,804
Basis:
DOM South (DOM) 9,830 ($0.71) ($0.40) ($2,826) 54,200 ($0.59) ($0.47) ($6,659)
TCO Pool (TCO) 13,175 ($0.40) ($0.26) ($1,742) 55,160 ($0.39) ($0.34) ($3,217)
Michcon (NMC) 8,873 ($0.18) ($0.12) ($555) 34,013 ($0.17) ($0.18) $271
TETCO ELA (TEB) 1,820 ($0.09) ($0.08) ($17) 7,320 ($0.09) ($0.10) $115
TETCO WLA (TWB) 3,640 ($0.08) ($0.02) ($189) 14,640 ($0.08) ($0.06) ($284)
TETCO M3 (TMT) 4,550 ($0.35) ($0.33) ($99) 17,840 $0.27 ($0.07) $6,168
TETCO M2 (BM2) 54,010 ($0.54) ($0.42) ($6,674) 198,795 ($0.54) ($0.48) ($12,844)
Transco Zone 5 South (DKR) 4,550 ($0.01) $0.10 ($530) 12,530 $0.16 $0.19 $1,458
Total Financial Basis Hedges 100,448 ($12,632) 394,498 ($14,992)
Total Projected Realized Gain $101,523 $257,812
Note: Forward market prices, hedged volumes, and hedge prices are as of 4/21/2020. Anticipated hedging activity is not included in projections.
(1) January through April prices are settled.
(2) Amounts based on sum of current monthly hedge positions vs. strip. Excludes monetization gains.
YE2019 Type Curve Area and Acreage Update
Note: As of year-end 2019 as identified in 2019 10-K filed February 10, 2020.
51
YE2019 Acreage and Undeveloped Location Update
Note: As of year-end 2019 as identified in 2019 10-K filed February 10, 2020.
Acres by type curve area do not equal total acres because some CNX-controlled acres fall outside of identified type curve areas. Average lateral lengths and inter-lateral
spacing assumptions unchanged from 2018 Analyst Day.
Totals may not foot due to rounding.
Locations calculated by dividing total controlled acreage in type curve region divided by area of a well (9,500’ lateral leng th * 750’ inter-lateral spacing).
Grossing up locations to include prospective units requiring additional capital, as is common in the industry, would yield significantly more locations.52
MARCELLUS UTICATYPE CURVE AREAS
SWPA Central Greater TOTAL SWPA
Total Net Acres 88,300 30,600 118,900
Net Developed Acres 34,600 2,400 37,000
Net Undeveloped Locations 328 172
Average Lateral Length (ft) 9,500 9,500
Inter-Lateral Spacing (ft) 750 750
WV SHR/PENS East TOTAL WV
Total Net Acres 15,600 11,000 87,700
Net Developed Acres 7,600 100 7,700
Net Undeveloped Locations 58 79
Average Lateral Length (ft) 8,000 8,000
Inter-Lateral Spacing (ft) 750 750
CPA South North TOTAL CPA
Total Net Acres 103,000 94,800 300,200
Net Developed Acres 5,100 900 6,000
Net Undeveloped Locations 632 606
Average Lateral Length (ft) 9,000 9,000
Inter-Lateral Spacing (ft) 750 750
OH TOTAL OH
Total Net Acres 12,500
Net Developed Acres 200
Net Undeveloped Locations
Average Lateral Length (ft)
Inter-Lateral Spacing (ft)
COMPANY Total Net Acres 519,300
TYPE CURVE AREAS
SWPA Central Greater TOTAL SWPA
Total Net Acres 114,800 57,100 171,900
Net Developed Acres 3,400 - 3,400
Net Undeveloped Locations 439 225
Average Lateral Length (ft) 8,500 8,500
Inter-Lateral Spacing (ft) 1,300 1,300
WV SHR/PENS East TOTAL WV
Total Net Acres 12,900 84,000 133,600
Net Developed Acres - - -
Net Undeveloped Locations 62 402
Average Lateral Length (ft) 7,000 7,000
Inter-Lateral Spacing (ft) 1,300 1,300
CPA South North TOTAL CPA
Total Net Acres 106,900 95,000 240,600
Net Developed Acres 700 200 900
Net Undeveloped Locations 508 454
Average Lateral Length (ft) 7,000 7,000
Inter-Lateral Spacing (ft) 1,300 1,300
OH Dry TOTAL OH
Total Net Acres 15,600 62,200
Net Developed Acres 11,600 11,600
Net Undeveloped Locations 14
Average Lateral Length (ft) 9,500
Inter-Lateral Spacing (ft) 1,350
COMPANY Total Net Acres 608,300
Non-GAAP Definition
53
Non-GAAP Financial Measures Definitions: EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes.
EBITDAX is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes, depreciation, depletion and amortization,
and exploration. Adjusted EBITDAX consolidated is defined as EBITDAX after adjusting for the discrete items listed below. Stand-alone EBITDAX is defined as the
adjusted EBITDAX related to both CNX's E&P and Unallocated segments (See Note 24 - Segment Information in CNX's Annual Report on Form 10-K as filed with the
Securities and Exchange Commission for more information) plus the distributions CNX receives during the current period from CNXM related to its limited partnership
units (including general partner units, and incentive distribution rights (IDRs) prior to the IDR elimination transaction in the first quarter of 2020). Although EBIT, EBITDAX,
Stand-alone EBITDAX and adjusted EBITDAX consolidated are not measures of performance calculated in accordance with generally accepted accounting principles,
management believes that they are useful to an investor in evaluating CNX Resources because they are widely used to evaluate a company's operating performance.
We exclude stock-based compensation from adjusted EBITDAX because we do not believe it accurately reflects the actual operating expense incurred during the
relevant period and may vary widely from period to period irrespective of operating results. Investors should not view these metrics as a substitute for measures of
performance that are calculated in accordance with generally accepted accounting principles. In addition, because all companies do not calculate EBIT, EBITDAX,
Stand-alone EBITDAX or adjusted EBITDAX consolidated identically, the presentation here may not be comparable to similarly titled measures of other companies.
Adjusted EBITDAX per outstanding share, adjusted net income per outstanding share, Stand-alone EBITDAX and adjusted EBITDAX consolidated, with shares
measured as of April 15, 2020, are not measures of performance calculated in accordance with generally accepted accounting principles. Management believes that
these financial measures are useful to an investor in evaluating CNX Resources because (i) analysts utilize these metrics when evaluating company performance and, (ii)
given that we have an active share repurchase program, analysts have requested this information as of a recent practicable date, and we want to provide updated
information to investors.
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.
Non-GAAP Reconciliation
54
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
Q1 2020 was 96.0% and 4.0%, respectively. Consolidated cash flow from operations for CNX Midstream for Q1 2020 was $40.1 million.
Three Months Ended
March 31,
2020 2019 2020 2019
($ in thousands)Stand-alone
(1)Stand-alone
(1) Total Company Total Company
Net Income (Loss) from EBITDAX Reconciliation $124,322 ($97,235) ($305,222) ($64,651)
Adjustments
Total Pre-tax Adjustments from EBITDAX Reconciliation 93,046 172,462 566,595 180,303
Tax Effect of Adjustments (24,315) (46,810) (148,063) (48,899)
Adjusted Net Income $193,053 $28,417 $113,310 $66,753
March 31, 2020
($ in thousands)Stand-alone
(1) Midstream Total Company
Total Long-Term Debt (GAAP)(1)
$1,919,200 $741,399 $2,660,599
Less Cash and Cash Equivalents 31,692 6,334 $38,026
Net Debt (Non-GAAP) $1,887,508 $735,065 $2,622,573
(1) Includes current portion.
Non-GAAP Reconciliation
55
Source: Company filings.
Note: Standalone Free Cash Flow defined as Cash from Operations, less Capital Expenditures, plus proceeds from Asset Sales, plus the distributions CNX receives from
CNXM.
(1) 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
Q1 2020 was 96.0% and 4.0%, respectively. Consolidated cash flow from operations for CNX Midstream for Q1 2020 was $40.1 million.
Cash from Operations and Capital Expenditures by Segment
($ in millions)
Q1 2020
E&P
Standalone +
CNX
Gathering(1)
= CNX + MLP(1)
=
Total
Consolidated
Cash from Operations $227.3 $1.4 $228.7 $38.7 $267.4
Capital Expenditures $119.3 $1.3 $120.6 $31.4 $152.0
Proceeds from Asset Sales $14.0 $0.0 $14.0 $0.0 $14.0
Free Cash Flow $122.0 N/A $122.1 N/A $129.4
Distributions $19.8 N/A $19.8 N/A N/A
Free Cash Flow plus Distributions $141.8 N/A $141.9 N/A N/A
Three Months Ended Three Months Ended
March 31, March 31,
($ in thousands) 2020 2019
Net Cash provided by Operating Activities $267,387 $308,652
Capital Expenditures (152,049) (299,138)
Organic Free Cash Flow $115,338 $9,514
Net Cash Provided By Operating Activities $267,387 $308,652
Capital Expenditures (152,049) ($299,138)
Proceeds from Sales of Assets 13,975 5,806
Free Cash Flow $129,313 $15,320
Non-GAAP Reconciliation
56
Source: Company filings.
Organic Free Cash Flow
Free Cash Flow
Non-GAAP Reconciliation
57
Price and Cost Data per Mcfe
($/Mcfe) Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020
Average Sales Price - Total Company 2.97$ 2.63$ 2.51$ 2.54$ 2.59$
Lease Operating Expense 0.14$ 0.15$ 0.11$ 0.09$ 0.07$
Transportation, Gathering and Compression 0.92$ 0.98$ 0.97$ 0.97$ 0.99$
Production, Ad Valorem, and Other Fees 0.05$ 0.05$ 0.05$ 0.05$ 0.05$
Depreciation, Depletion and Amortization 0.88$ 0.89$ 0.86$ 0.86$ 0.87$
Total Production Costs 1.99$ 2.07$ 1.99$ 1.97$ 1.98$
Less: Depreciation, Depletion and Amortization 0.88$ 0.89$ 0.86$ 0.86$ 0.87$
Total Cash Production Costs 1.11$ 1.18$ 1.13$ 1.11$ 1.11$
Operating Cash Margin 1.86$ 1.45$ 1.38$ 1.43$ 1.48$
Non-GAAP Reconciliation
58
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
Three Months Ended
March 31,
2020 2020 2020
($ in thousands)Stand-alone
(1) Midstream Total Company
Net Income (Loss) $124,322 ($429,544) ($305,222)
Interest Expense 40,186 8,809 48,995
Interest Income (92) - (92)
Income Tax Benefit (152,582) - (152,582)
Earnings Before Interest & Taxes (EBIT) 11,834 (420,735) (408,901)
Depreciation, Depletion & Amortization 119,152 10,012 129,164
Exploration Expense 3,818 70 3,888
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $134,804 ($410,653) ($275,849)
Adjustments:
Unrealized Loss on Commodity Derivative Instruments 36,019 - 36,019
Impairment of Goodwill - 473,045 473,045
Impairment of Exploration and Production Properties 61,849 - 61,849
Gain on Debt Extinguishment (11,263) - (11,263)
Stock-Based Compensation 6,336 504 6,840
Severance Expense 105 - 105
Total Pre-tax Adjustments $93,046 $473,549 $566,595
Adjusted EBITDAX Consolidated $227,850 $62,896 $290,746
Midstream Distributions 19,759 N/A N/A
Non-GAAP Reconciliation
59
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
Twelve Months Ended
March 31,
2020 2020 2020
($ in thousands)Stand-alone
(1) Midstream Total Company
Net Income (Loss) $86,852 ($295,475) ($208,623)
Interest Expense 132,808 31,795 164,603
Interest Income (1,307) (12) (1,319)
Income Tax Benefit (113,287) - (113,287)
Earnings Before Interest & Taxes (EBIT) 105,066 (263,692) (158,626)
Depreciation, Depletion & Amortization 476,428 36,038 512,466
Exploration Expense 44,897 113 45,010
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $626,391 ($227,541) $398,850
Adjustments:
Unrealized Gain on Commodity Derivative Instruments (424,300) - (424,300)
Impairment of Exploration and Production Properties 389,249 - 389,249
Impairment of Unproved Properties and Expirations 119,429 - 119,429
Impairment of Goodwill - 473,045 473,045
Severance Expense 2,963 436 3,399
Stock Based Compensation 32,590 1,772 34,362
Gain on Debt Extinguishment (11,186) - (11,186)
Shaw Insurance Recovery (2,159) - (2,159)
Total Pre-tax Adjustments $106,586 $475,253 $581,839
Adjusted EBITDAX Consolidated $732,977 $247,712 $980,689
Midstream Distributions 59,543 N/A N/A
Stand-alone EBITDAX $792,520 N/A N/A
Non-GAAP Reconciliation
60
Source: Company filings.
(1) Stand-alone includes both CNX’s E&P and Unallocated segments.
Three Months Ended
March 31,
2019 2019 2019
($ in thousands)Stand-alone
(1) Midstream Total Company
Net (Loss) Income ($97,235) $32,584 ($64,651)
Interest Expense 28,432 7,339 35,771
Interest Income (722) - (722)
Income Tax Benefit (11,559) - (11,559)
Earnings Before Interest & Taxes (EBIT) (81,084) 39,923 (41,161)
Depreciation, Depletion & Amortization 117,075 8,086 125,161
Exploration Expense 3,258 - 3,258
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $39,249 $48,009 $87,258
Adjustments:
Unrealized Loss on Commodity Derivative Instruments 153,994 - 153,994
(Gain) Loss on Certain Asset Sales (3,665) 7,229 3,564
Loss on Debt Extinguishment 7,537 - 7,537
Stock-Based Compensation 10,291 612 10,903
Shaw Event 4,305 - 4,305
Total Pre-tax Adjustments $172,462 $7,841 $180,303
Adjusted EBITDAX Consolidated $211,711 $55,850 $267,561
Midstream Distributions 12,145 N/A N/A
Stand-alone EBITDAX $223,856 N/A N/A
Non-GAAP Reconciliation
61
Source: Company filings.
Three Months
Ended
Three Months
Ended
Three Months
Ended
Three Months
Ended
Twelve Months
Ended
June 30, September 30, December 31, March 31, March 31,
($ in thousands) 2019 2019 2019 2020 2020
Net Income (Loss) $192,694 $143,960 ($240,055) ($305,222) ($208,623)
Interest Expense 40,152 38,405 37,051 48,995 $164,603
Interest Income (71) (1,078) (78) (92) ($1,319)
Income Tax Expense (Benefit) 40,791 48,902 (50,398) (152,582) ($113,287)
Earnings Before Interest & Taxes (EBIT) 273,566 230,189 (253,480) (408,901) (158,626)
Depreciation, Depletion & Amortization 128,999 120,459 133,844 129,164 512,466
Exploration Expense 5,567 6,075 29,480 3,888 45,0100
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $408,132 $356,723 ($90,156) ($275,849) $398,850
Adjustments:
Unrealized (Gain) Loss on Commodity Derivative Instruments (210,909) (156,872) (92,538) 36,019 ($424,300)
Impairment of Exploration and Production Properties - - 327,400 61,849 $389,249
Impairment of Unproved Properties and Expirations - - 119,429 - $119,429
Impairment Goodwill - - - 473,045 $473,045
Severance Expense 1,182 1,999 113 105 $3,399
Stock Based Compensation 23,873 1,781 1,868 6,840 $34,362
Loss (Gain) on Debt Extinguishment 77 - - (11,263) ($11,186)
Shaw Insurance Recovery - - (2,159) - ($2,159)
Total Pre-tax Adjustments ($185,777) ($153,092) $354,113 $566,595 $581,839
Adjusted EBITDAX Consolidated TTM $222,355 $203,631 $263,957 $290,746 $980,689