Earnings Results - CNX Resources...

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


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


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

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EF

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Bakken

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Bakken

DJ

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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


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.


(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


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


0.7 x

2.1 x

2.8 x3.0 x

4.2 x

5.5 x5.9 x


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%


309%

240%

215% 211%

157%

46%

16%


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


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


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


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.


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.


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




CPA South North TOTAL CPA

Total Net Acres 103,000 94,800 300,200

Net Developed Acres 5,100 900 6,000




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



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 - - -




CPA South North TOTAL CPA

Total Net Acres 106,900 95,000 240,600

Net Developed Acres 700 200 900




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


(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.


55


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


56


Organic Free Cash Flow

Free Cash Flow


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$


58



Three Months Ended

March 31,

2020 2020 2020



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


59



Twelve Months Ended

March 31,

2020 2020 2020



Net Income (Loss) $86,852 ($295,475) ($208,623)


Interest Income (1,307) (12) (1,319)


Earnings Before Interest & Taxes (EBIT) 105,066 (263,692) (158,626)


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)




Stand-alone EBITDAX $792,520 N/A N/A


60



Three Months Ended

March 31,

2019 2019 2019



Net (Loss) Income ($97,235) $32,584 ($64,651)


Interest Income (722) - (722)


Earnings Before Interest & Taxes (EBIT) (81,084) 39,923 (41,161)


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




Stand-alone EBITDAX $223,856 N/A N/A


61


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

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