Earnings Results - CNX Resources...

Earnings ResultsFourth Quarter 2019

January 30, 2020

Cautionary Language

2

For purposes of this presentation: (i) “CNX”, “CNX Resources”, “Company”, “we” and “our” refer to CNX Resources Corporation (ii) “CNXM” refers to CNXM Midstream Partners LP; and (iii) “CNXM GP” refers to CNX

Midstream GP LLC

Risk Factors. This presentation, including the oral statements made in connection herewith, contains forward-looking statements, estimates and projections within the meaning of the federal securities laws.

Statements that are not historical are forward-looking and may include our operational and strategic plans; estimates of gas reserves and resources; projected timing and rates of return of future investments; and

projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those

statements, estimates and projections. Investors should not place undue reliance on forward-looking statements as a prediction of future actual results. The forward-looking statements in this presentation speak only

as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly.

Specific factors that could cause future actual results to differ materially from the forward-looking statements are described in detail under the captions "Forward Looking Statements" and "Risk Factors" in our annual

report on Form 10-K for the year ended December 31, 2018 filed with the SEC, as supplemented by our quarterly reports on Form 10-Q. Those risk factors discuss, among other matters, pricing volatility or pricing

decline for natural gas and NGLs; operational risks relating to midstream facilities, pipeline systems, drilling natural gas wells, access to key services and equipment, access to adequate water sources and customer

interactions; the impact of laws and regulations on our business and industry; competitive and economic concerns; risks associated with our debt and hedging strategy; our ability to acquire economically recoverable

natural gas reserves; challenges associated with strategic determinations, including the allocation of capital to strategic opportunities; our development and exploration projects and potential acquisitions or

divestitures, as well as CNXM's midstream system development.

Reserves. Currently, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be

economically and legally producible and deliverable by application of development projects to known accumulations. We may use certain terms in this presentation, such as EUR (estimated ultimate recovery),

unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these

estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC

definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of

certainty associated with each reserve category.

Title. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to the commencement

of natural gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our

expense. As a result of our title review or otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the gas rights we control and third parties

may participate in the wells we drill, thereby reducing our working interest in those wells.

Reconciliation. As it relates to the disclosures within this presentation of projected Adjusted EBITDA, projected EBITDAX, projected free cash flow and other projected non-GAAP metrics for fiscal or quarterly periods

in 2020 or beyond, for CNX or CNXM, CNX is unable to provide a reconciliation of such metrics to projected operating income, the most directly comparable financial measure calculated in accordance with GAAP, due

to its inability to calculate projected operating income due to the unknown effect, timing, and potential significance of certain income statement items for each of CNX and CNXM, respectively.

Data. This presentation has been prepared by CNX and includes market data and other statistical information from sources believed by CNX to be reliable, including independent industry publications, government

publications and other published independent sources. Some data are also based on CNX’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described

above. Although CNX believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy or completeness.

Trademarks. CNX owns or has rights to various trademarks, service marks and trade names that it uses in connection with the operation of its business. This presentation also contains trademarks, service marks

and trade names of third parties, which are the property of their respective owners. CNX’s use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and

does not imply, a relationship with CNX or an endorsement or sponsorship by or of CNX. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appear without the

®, TM or SM symbols, but such references are not intended to indicate, in any way, that CNX will not assert, to the fullest extent under applicable law, its rights or the right of the applicable licensor to these

trademarks, service marks and trade names.

Not an Offer. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CNX Resources Corporation or CNX Midstream Partners LP.

3

CNX Highlights

CNXM Simplified Structure

◼ IDR elimination transaction simplifies capital structure

◼ Reduces CNXM’s cost of capital

◼ Aligns sponsor and public unitholder economic interests

Operational Excellence

◼ Beating guidance

◼ Strong well results

◼ Low operating costs

Proactive Management

◼ Best-in-class hedge book

◼ Significant cost reductions

◼ Flexible business plans drive decision-making and new guidance

Strong Balance Sheet

◼ Low firm transportation (FT) obligations and limited processing commitments

◼ Leverage ratios going down

◼ 2022 debt maturities manageable

Best-in-Class Results and Go-

Forward Strengths

◼ $250 million of currently expected FCF in 2020

◼ $300 million of currently expected EBITDA for CNXM in 2021

◼ Optionality to ramp up production or maintain slower growth profile

Note: CNX is unable to provide a reconciliation of projected financial results contained in presentation, including FCF, EBITDA, adjusted EBITDAX, fully burdened cash costs

and other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP

projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.

Competitive Advantages and Philosophy Drive Investment Thesis

4

ADVANTAGES

Hedge book

Minimal FT

Large stacked-

pay inventory

Midstream control

Water systems

~100,000 Core

SWPA Marcellus

acres

Marketing

Strategy

Cost

Structure

Asset

Portfolio

Strong cash

margins

Blending

strategy

CREDIBILITY

Doing what we say we’re going to do

Shares

outstandingProduction &

EBITDAX/share

Leverage ratio

Sold Appalachian acreage Spun coal business

CONSISTENT

PHILOSOPHY

Stacked pay

gathering system

CPA/SWPA Utica

Marcellus buildout CNXM

Water infrastructureUtica blending

strategy

Share repurchases

Investments in high rate of return opportunities

(over 20% hurdle rate)

Core SWPA

Marcellus inventory

1

2

3

Long-term NAV per share growth

Disciplined decision making

Flexibility

Capital allocation process drives:

5

Excelling Through the Downturn

IDR Transaction Puts CNXM in Right Capital Structure1

Beat Guidance Across the Board in 20192

Forecasting $250 million in FCF in 20203

Hedge Book Protects the Company for Several Years4

Forecasting $250 million in FCF in 20215

Strong 2020 and 2021 Sets the Company up for an Even Better 20226

✓

✓

✓

✓

✓

✓Note: CNX is unable to provide a reconciliation of projected financial results contained in presentation, including FCF, adjusted EBITDAX, fully burdened cash costs and

other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected

metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.

Milestones

6

2017 2018 2019 2020

▪ CNXM acquires Shirley Penns

assets with significant long term

MVC levels (+$430mm revenue}

▪ Upsize credit facility to $600mm

▪ $400mm 8 year notes offering at

6.5%

▪ Establishes finance platform to de-

risk business plan, and eliminate

capital markets needs for baseline

plan

▪ Significant investment year:

$316mm of capital expenditures

▪ Installing operating leverage for

long term FCF generation

✓ FCF generation and continue growing

returns to unitholders

✓ Organic build out of the next wave of growth

projects

✓ Pursue midstream investments and M&A, on

both an independent basis and jointly with

sponsor

▪ Assisted Noble in two secondary

offerings to relieve overhang

▪ Increases public float 2x

2014 2015 2016

CNNX IPO, September

2014CNNX acquires remaining

25% interest in Anchor System

CNX acquires remaining 50% GP

interest from Noble for ~$300mm

▪ CONE renamed CNX Midstream

Partners

▪ CNX agrees to $385mm in well

commitments and dedicates

63,000 new acres to CNXM.

▪ Eliminates adverse, non-

operational general partner from

MLP

GP Acquisition & Enhanced

Commercial Agreement

Shirley-Penns Drop Down &

Finance Platform Established

HG Asset Exchange Agreement

▪ Additional +$145mm minimum

revenue commitments

▪ CNX negotiates 12 well

commitment from HG Energy

▪ Additional 16,100 Utica acres

dedicated to CNXM

▪ Cash flows from minimum revenue

commitments alone support 15%

distribution growth through 2022

CNXM Secondary Offerings

SWPA System Expansion

IDRs exchanged for common

equity, class B Units, and

deferred cash

▪ Immediately DCF accretive to LP

unitholders

IDR Elimination Transaction

Business Optionality

7

Incentive Distribution Rights (IDR) Transaction Overview

The incentive distribution rights and economic general

partner interest in CNXM owned by CNX were exchanged for

the following:

▪ 26 million common LP Units

▪ 3 million Class B units, will not receive or accrue distributions

until 1/1/22, at which time they convert into common units

▪ $135 million cash payable in three installments:

─ $50M on 12/31/2020

─ $50M on 12/31/2021

─ $35M on 12/31/2022

✓Immediately accretive to DCF per LP

✓Simplifies capital structure

✓Reduces cost of capital

✓Aligns sponsor and public unitholder economic interests

✓CNX owns 53.1%(1) LP interest

Transaction Overview Pro Forma Structure

Public

Common

Units42.1mm Common

Units

46.9% limited

partner interest

Non-economic general

partner interest and 53.1%(1)

limited partner interest

100%

Additional Systems

DevCo III

5% GP

InterestAnchor Systems

DevCo I

(1) Excludes 3 million new CNXM Class B units, which will not receive or accrue distributions until January 1, 2022, at which time they will automatically convert into

CNXM common units.

($ in millions) 2019 2020E 2021E 2022E 2023E

Targeted Distributions $63 $86 $99 $121 $140

IDR Cash Consideration $50 $50 $35

Total $63 $136 $149 $156 $140

$0

$50

$100

$150

$200

$250

$300

2015 2016 2017 2018 2019 2020E 2021E

$ in m

illio

ns

CNXM Net EBITDA

8

CNXM is Crucial to CNX’s Success

CNXM Adjusted EBITDA 2015-2021E

$135 million cash,

payable $50mm on

12/31/20, $50mm on

12/31/21, $35mm

12/31/22

Note: The historical and projected non-GAAP financial measures in the chart above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP

Reconciliation“ in the CNX Midstream Partners Q4 2019 slide presentation, which can be found on the investor relations section of their website:

www.cnxmidstream.com.

Following IDR

Elimination Transaction,

CNX now owns 47.7

million common units.

The transaction also

includes 3 million Class

B units that will convert

to CNXM common units

on January 1, 2022

http://www.cnxmidstream.com/

Strong Full Year 2019 Financial and Operational Performance

9

Actuals 2019 Guidance Actuals vs.

($ in millions) 2019 Low High Avg. Midpoint Guidance

Production Volumes (Bcfe) 539 530 540 535 4

Adjusted EBITDAX $772 $745 $765 $755 $17

Total E&P Capital $876 $890 $915 $903 ($27)

▪ Finished 2019 with strong operational execution

- Drilled 66 wells, completed 50 wells, and turned-in-line 51 wells

- Included Pennsylvania state record for longest lateral at 19,609 ft for the

RHL71B Marcellus Shale well

- The average lateral length for this 6-well pad was 15,744 feet and D&C capital

of approximately $800 per foot

▪ Nearly free cash flow (FCF) neutral in 2019 when including the $45 million in

assets sales we completed

▪ Constructed critical water infrastructure projects expected to drive water

efficiencies for years to come

Actuals > Guidance

2019

Note: The Non-GAAP financial measures in the table above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation."

2019 Capital and Operations Improvements

10

Capital Continuous Improvements

▪ Completion design optimization

▪ Cycle time efficiencies

▪ Fuel cost savings of frac crews using natural gas vs. diesel

▪ Service cost reductions

▪ Utica well cost improvements

▪ Reduction of pad construction costs through multiple trips to a

pad

One-Time Infrastructure Investments Driving Future

Efficiencies

▪ SWPA water infrastructure projects

- Richhill water line – increased water supply

- Large water storage facilities – increased water storage

capacity

▪ Wadestown initial midstream buildout

Operations Continuous Improvements

▪ Decreased water disposal through increased reuse

▪ Combined midstream and upstream production teams

▪ Increased integrated real time operations center (IRTOC) remote

operations

▪ Reduced repair and maintenance

▪ Gathering optimization improvements

SWPA Marcellus: Increased Results and Efficiencies

11

Ohio River Water Line (to Richhill)

▪ The buildout was completed in Q3 2019 and the water line

is currently in-service

▪ Supplies an uninterruptible water source into the Richhill

operating area within Southwest Pennsylvania that helps

support the Evolution frac crew

▪ Marcellus development is concentrated in the Richhill area

▪ 2019 RHL wells continue to perform above the current type curve and

existing RHL wells

▪ Capital was lowered on 2019 TIL’s as a result of stage

spacing optimization but resulted in increased performance driving

well returns higher

▪ Optimized drawdown continues to be performed with lower production

decline once line pressure is reached

▪ 2020 and 2021 development programs includes 20 RHL Marcellus TIL’s

each year(1) 2018 TILs comprised of 8 wells off the RHL 22 pad

(2) 2019 TILs comprised of 17 wells off the RHL 11, 27, and 28 pads

-

1.0

2.0

3.0

4.0

5.0

6.0

- 50 100 150 200 250 300 350 400 450 500 550

90

00

' Norm

aliz

ed

Cum

ula

tive

(B

cf)

Days

Richhill (RHL) Marcellus - 2018 vs. Now

Current RHL TC 2018 TILs 2019 TILs

SWPA Blending Strategy in Full Swing

12

Damp Marcellus to Dry Outlets

▪ Maximize NAV by drilling high ROR Marcellus pads

with enough Utica to blend into dry outlet

▪ Only completing enough to blend over the next several

years

- 1 SWPA dry Utica pad expected to TIL in both 2020 and

2021

- Blending economics support drilling

▪ Just one dry Utica well needed to blend 3-4 damp Marcellus

wells

▪ Increases Marcellus margins by $0.50 - $0.55/dth vs.

processing

▪ Generates 30% uplift to NPV per Marcellus well

2020 Utica TIL Program:

5-well Switz pad – Monroe County, Ohio

3-well Shaw pad – Westmoreland County,

PA

4-well Richhill “blending” pad – Greene

County, PA

Operational Highlights

13

Highlights

▪ Richhill Area

- Marcellus drilling cost per foot decreased 23% in 2019,

compared to 2018

- Marcellus stimulation lateral footage per day improved 9% in

2019, compared to 2018

Production and Midstream Highlights

▪ In 2019, production increased 6%, when compared to 2018,

while lease operating expense (LOE) declined by $0.07 per

Mcfe, or declined by $30 million

▪ LOE reductions driven in part by remote operations via the real

time operations center for opening and closing producing wells

▪ CNXM commissioned the Dry Ridge Compressor Station to

service the company’s Richhill operating area

- The station currently has the capacity of 200 MMcf per day

with plans to increase capacity in the future

Dry Ridge Compressor Station

$0.78 $0.78

$1.13 $1.13

$1.25 $1.31

$1.69

$2.18

$-

$0.75

$1.50

$2.25

CNXConsolidated

Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6

Lease Operating Expense ($/Mcfe) Production, Ad Valorem, and Other Fees ($/Mcfe) Transportation, Gathering and Compression - E&P ($/Mcfe)

14

Low Production Cash Costs Create Competitive Advantage

(1) TTM as of Q4 2019 end for CNX and TTM as of Q3 2019 for peers. Peers include AR, COG, EQT, GPOR, RRC, SWN. For peers that net transportation costs from

revenue, $0.30 per Mcfe has been added to Transportation, Gathering and Compression to estimate total production costs.

(2) CNX consolidated includes the benefit of $0.35 per Mcf after eliminating intercompany gathering charges between CNX and CNX Midstream.

(3) Does not include firm transportation.

(4) Lease operating expense for this producer includes gathering and processing costs, but not firm transportation.

(5) Average daily production TTM as of Q4 2019 for CNX and TTM as of Q3 2019 for peers.

TTM Q3/Q4 2019 Production Cash Costs per Mcfe(1)

CNX’s top-tier

production cash

costs, substantial

hedge book, and

midstream control

create a significant

advantage in a weak

natural gas pricing

environment

(4)

Avg. Daily

Production(5)

(Bcfe/d)

1.5 2.3 1.5 1.4 4.2 2.2 2.2 3.2

(2)

(3)

15

Proactive Business Management: Cumulative Changes Since Q2 2019 Call

OLD (Q2 2019) NEW (Q4 2019)

Macro Conditions Got Much Worse But

CNX Got Much Stronger

(1) Forward market prices are as of 1/24/2020.

Decreased cumulatively in 2019 and 2020 by ~$144M, based on 2019 Actuals vs. midpoint of 2019 guidance range, and changes to midpoint of 2020

guidance ranges in Q4 2019 vs. Q2 2019

E&P Capex Decreased by ~$144M

Increased cumulatively in 2019 and 2020 by ~$20 million based on 2019 Actuals vs. midpoint of 2019 guidance range, and changes to midpoint of 2020

guidance ranges in Q4 2019 vs. Q2 2019

E&P EBITDAX Increased by ~$20M

Reduced expected cash SG&A spend by $30 million annually since 2018; Annual cash SG&A costs for E&P expected to be

~$70M based on midpoint of 2020 guidance

SG&A Decreased by ~$30M

2020 NYMEX $2.55/MMBtu ($0.46)/MMBtu $2.09/MMBtu(1)

Updated 2020 and 2021 Guidance

Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs and

other metrics to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected

metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.


(2) Includes approximately $80 million of projected distributions from ownership interests in CNXM and a $50 million payment associated with the IDR Elimination

Transaction. Per share calculation uses 186.6 million shares outstanding as of 1/20/2020..

(3) Includes distributions from CNX Midstream plus $62 million in tax refund expected in 2020. Excludes ~$50M in expected asset sales in 2020 and 2021. 16

Previous UPDATED

2020E 2020ECapital Expenditures($ millions)

Low High Low High

Drilling & Completions $400 $450 $360 $410

Non-D&C $90 $100 $90 $100

Total E&P Capital $490 $550 $450 $510

CNX Midstream LP Capital $80 $100 $80 $100

Total Consolidated Capital $570 $650 $530 $610

Production Volumes (Bcfe) 535 565 525 555

Prices on Open Volumes

Natural Gas NYMEX ($/MMBtu)(1) $2.40 $2.27

Natural Gas Basis Differential ($/MMBtu)(1) ($0.25)-($0.35) ($0.25)-($0.35)

Adjusted EBITDAX(2)

($ millions)

E&P Standalone + Distributions(2) $710 $755 $765 $810

E&P Standalone + Distributions(2)

per Share$3.81 $4.05 $4.10 $4.34

Consolidated $885 $950 $885 $950

Organic Free Cash Flow (FCF)(3) $146 ~$200

Expect ~5% Production Growth in 2021,

compared to 2020

Expect to Generate >$200M in

Organic Free Cash Flow in 2021

▪ 2021E

Pro

du

cti

on

FC

F

Five-year average all-in maintenance capital (D&C + non-D&C):

~$400 million to hold flat production of 540 Bcfe

For 2019 and 2020 combined, Total E&P capital is anticipated to be reduced

by ~$67 million, resulting in 6 Bcfe less production in 2020, compared to

previous update, after accounting for the 4 Bcfe accelerated from 2020 into

2019

Maintaining non-D&C capital in 2020 and expect this to be lower in 2021

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Jan-2020 Feb-2020 Mar-2020 Apr-2020 May-2020 Jun-2020 Jul-2020 Aug-2020 Sep-2020 Oct-2020 Nov-2020 Dec-2020

Pro

ductio

n (

Bcfe

/d)

Legacy PDP Marcellus PUD Utica PUD

Production

Growth

~5%

Production Cadence and Hedge Advantage in 2020

(1) Assumes midpoint of guided 2020 production ranges.

17

Expected Daily Production 2020(1)

Average Hedged Volumes: 498 Bcf or 98% of gas production hedged at NYMEX $2.96 in 2020

TIL

s

2020

Marcellus: 33

Utica: 12 2020 S

ets

Up

2021 W

ell

% of Gas

Hedged

83%NYMEX

Hedge Price

$2.91

2021 Due to

minimum well

commitments

(MWC’s)

expect at a

minimum

modest

production

growth in

2022, and

potentially

more

depending on

gas prices

83%

81%

23%21%

3%0% 0%

$2.91

$2.80

$2.40

$2.56

$2.62

$ 2.00

$ 2.10

$ 2.20

$ 2.30

$ 2.40

$ 2.50

$ 2.60

$ 2.70

$ 2.80

$ 2.90

$ 3.00

0 %

20 %

40 %

60 %

80 %

100 %

CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6

% o

f C

on

sen

su

s P

rod

. H

ed

ged

2021 % of Production Hedged 2021 Average NYMEX Price Floor

Pri

ce F

loo

r

98%

92%

90%

63%

57%

42%

0%

$ 2.96

$ 2.87

$ 2.71

$ 2.64 $ 2.63

$ 2.88

$2.00

$2.10

$2.20

$2.30

$2.40

$2.50

$2.60

$2.70

$2.80

$2.90

$3.00

0%

20%

40%

60%

80%

100%

CNX Peer 1 Peer 2 Peer 4 Peer 3 Peer 5 Peer 6

% o

f C

on

sen

su

s P

rod

. H

ed

ged

2020 % of Production Hedged 2020 Average NYMEX Price Floor

Pri

ce F

loo

r

Substantial Hedges with Strongest Prices in 2020 and 2021

Note: Peers include AR, COG, EQT, GPOR, RRC, SWN. As of Q4 2019 for CNX and as of Q3 2019 for peers. NYMEX as of 1/8/2020. CNX hedge price per Mcf and per

MMBtu for peers.

(1) Based on Bloomberg consensus estimates as of 1/3/2020 for 2020E and 2021E annual gas production. CNX 2020 % of production hedged based on the midpoint of

natural gas guidance. CNX 2021 % of production hedged based on 5% annual production growth. CNX 2022 and 2023 % of gas production hedged based on flat

scenario with 2021 production of 535.5 Bcf. 18

2020E(1) Hedged Gas Production 2021E(1) Hedged Gas Production

~57% of 2022(1) production

hedged under maintenance

scenario at $2.99 NYMEX

vs.

~4% for peers at $2.67

NYMEX

NYMEX Strip $2.27 in 2020

NYMEX Strip $2.43 in 2021~33% of 2023(1) production

hedged under maintenance

scenario at $2.85 NYMEX

vs.

~1% for peers at $2.66

NYMEX

Balance Sheet is Getting Stronger

19

Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs


projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items..

(1) LP-adjusted leverage assuming CNXM LP ownership is used to offset the debt. CNXM market value as of 1/24/2020.

$ in millions

Stand-AloneStand-Alone Net Debt and Leverage

December 31, 2019

Total Long-Term Debt (GAAP) $2,048.5

Less: Cash and Cash Equivalents $15.3

Forecasted Net Debt (Non-GAAP) $~1,783.2

2020 Forecasted Stand-Alone Leverage Ratio ~2.25x

2020 Stand-Alone Adjusted EBITDAX $787.5

2021 Leverage Ratio

Set To Go Even Lower

Less: Forecasted 2020 Total FCF $250.0

LP-Adjusted(1)

$2,048.5

$15.3

$~1,005.5

~1.3x

$787.5

$250.0

Less: 50.7M units

x $15.34(1)

0.6 x2.0 x

3.3 x 3.2 x 2.8 x4.0 x 3.7 x

1.4 x

2.3 x

5.5 x

10.6 x12.9 x

12.8 x

18.3 x

2.0 x

4.3 x

8.8 x

13.8 x

15.7 x16.8 x

22.0 x


0.6x

2.0x

2.8x

3.2x3.3x

3.7x4.0x


Highly Resilient Balance Sheet

20

Note: Peers include AR, COG, EQT, GPOR, RRC, SWN.

(1) For peers based on Capital IQ consensus estimates for 2021E EBITDA and 2021E net debt as of 1/24/2020. CNX 2021E based on forecast. Off-balance sheet

obligations based on the respective 2018 10-Ks of CNX and the peer companies.

Net Debt + Off-Balance Sheet Obligations /

2021E EBITDA(1)

▪ Under current strip, CNX expects to generate FCF and reduce

leverage in 2020 and 2021

▪ Flexibility through low total liability positioning in Appalachia

▪ Deliberate, strategic decision by management to avoid expensive

FT contracts that are now underwater

▪ Instead, relies on hedges (NYMEX + Basis) to mitigate pricing risk

▪ Selected, thoughtful firm transportation commitments, limiting the

need to “drill to fill”

▪ Most peers expected to increase leverage in 2021

Net Debt / 2021E EBITDA(1)

~

Net Debt

Off-Balance Sheet Obligations

81% 80%

73%

66% 65%

54%

15%

Peer 1 Peer 5 Peer 4 Peer 2 Peer 3 CNX Peer 6

403%

302%

251% 246%

150%

41%

20%


484%

368%

319% 316%

231%

95%

35%


21

CNX Screens Well on All-In Debt Metrics vs. Appalachian Peers

Total Debt(1) as % of EV FT Commitments as % of EV Total Debt(1) + FT Commitments as a % of EV

Source: Public filings; Market cap as of 1/3/2020. Peers include AR, COG, EQT, GPOR, RRC, SWN.

(1) CNX total debt is consolidated and as of Q4 2019 and as of Q3 2019 for peers, excludes lease obligations; per latest company filings. Off-balance sheet obligations

based on respective 2018 10-Ks of CNX and peer companies. 21

2022 Senior Notes Maturities Easily Addressed

22

$ in m

illio

ns



projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items..

Total FCF includes approximately $50 million in assets sales in 2020E and 2021E.

(1) CNXM market value as of 1/24/2020.

~$780M

CNXM

Units(1)

$1.2B

Revolver

Liquidity

Ability to

payoff or

refinance

2022 FCF also expected to be additional source of funds

23

CNX Under the Current

NYMEX Strip

◼ Expect to generate approximately $250 million in total FCF in each 2020 and 2021

◼ Leverage ratio decreases to approximately 2.0x

◼ Modest production growth in 2021 expected, based on the midpoint of the 2020 guidance range

◼ Sets up for a strong ramp of activity into 2022 and beyond

◼ Or will have the optionality to stay in a slow-and-steady mode if macro conditions warrant

Peers?

◼ Production flat to decreasing

◼ FCF neutral to negative

◼ Leverage ratios increasing with some expected to increase significantly

CNX has taken a deliberate approach, focusing on flexibility to appropriately manage through the commodity cycle

What Lies Ahead in 2021?

23



projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.

Total FCF includes approximately $50 million in assets sales in 2020E and 2021E.

Appendix

Financial Guidance

25

PREVIOUS (10/30/2019) UPDATE (1/30/2020)

2020E 2020E

Revenue and Other Operating Income E&P Consolidated E&P Consolidated

Production Volumes:

Natural Gas (Bcf) 505-535 495-525

NGLs (MBbls) 4,490-4,715 4,535-4,760

Condensate (MBbls) 245-265 245-265

Total Production (Bcfe) 535-565 525-555

% Liquids ~5% ~5%-6%

Natural Gas NYMEX Price ($/MMBtu)(1) $2.40 $2.27

Natural Gas Basis Differential to NYMEX ($/MMBtu)(1) ($0.25)-($0.35) ($0.25)-($0.35)

NGL Realized Price ($/Bbl)(1) $14.00-$16.00 $15.50-$17.50

Condensate Realized Price % of WTI(1) 70% 70%

Realized Hedging Gain/(Loss) ($ in millions)(2) $145-$155 $210-$220

Other Operating Income (3rd party water income and resold FT) ($ in millions) $10-$20 $10-$20

CNXM 3rd Party Gathering Revenue $65-$70 $70-$75

Costs

Average per unit operating expenses ($/Mcfe):

Lease Operating Expense

Production, Ad Valorem, and Other Fees

Transportation, Gathering and Compression

Total Cash Production and Gathering Costs $1.06-$1.14 $0.67-$0.75 $1.06-$1.14 $0.67-$0.75

($ in millions)

Selling, General, and Administrative Costs(3) $65-$75 $80-$90 $65-$75 $80-$90

Exploration Expense $0-$10 $0-$10

Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$75 $65-$75

Other Non-Operating Expense (Income) $0-$10 $0-$10

CNX Resources Corporation is unable to provide a reconciliation of projected stand-alone or consolidated adjusted EBITDAX to projected operating income, the most

comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate GAAP projected operating income given the unknown effect,

timing, and potential significance of certain income statement items.


(2) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing as of 1/8/2020. Anticipated hedging activity is not included in projections.

(3) Excludes stock-based compensation.

$80$88 $103

$124

$170 $171 $175

$306

$-

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

$0.18

$0.20

$0

$50

$100

$150

$200

$250

$300

$350

CNX - 2020EStand-Alone

Guidance

Peer 1 Peer 2 CNX -Stand-Alone

Peer 3 Peer 4 Peer 5 Peer 6

Tota

l S

G&

A (

$/M

cfe

)

Tota

l S

G&

A A

bsolu

te D

olla

rs (

$M

)

Cash SG&A (ex. stock comp) - ($M) Non-cash stock comp Cash SG&A (ex. stock comp) - ($/Mcfe)

Realignment Driving Expected Best-In-Class SG&A

26

Expect ~$30 million in total expected

consolidated cash SG&A savings

since 2018

▪ Combined upstream and midstream

teams

▪ Streamlined to one monitoring

system

Total 2020E SG&A (cash + non-cash)

is expected to be over 50% less than

peer average

Integrated Real-Time Operations

Center (IRTOC)

▪ Efficient cross-functional cooperation

Note: Cash SG&A excludes non-cash stock compensation expense.

(1) TTM as of Q4 2019 end for CNX and TTM as of Q3 2019 for peers. Peers include AR, COG, EQT, GPOR, RRC, SWN.

TTM Q3/Q4 2019 SG&A(1)

Q4 2019 Financial Results Summary

27

Note: The Non-GAAP financial measures in the tables above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation."

(1) For the quarter ended December 31, 2019, total shares outstanding of 186,642,962 (Non-GAAP) are as of 1/20/2020. For the quarter ended December 31, 2018, total

shares outstanding of 198,335,252 (Non-GAAP) are as of 1/18/2019.

(2) Capital expenditures exclude $72 million and $56 million of total capital investment net to CNXM in the fourth quarter of 2019 and 2018, respectively, as reported in

CNXM Fourth Quarter Results.

(3) See the "Price and Cost Data Per Mcfe" in the appendix for a reconciliation to total Production Costs.

(4) Fully burdened cash costs include production cash costs, selling, general and administrative (SG&A) cash costs, other operating cash expense, other cash (income)

expense, and interest expense.

Strong operating cash

margins despite weaker gas

prices vs. last year

Quarter

Ended

Quarter

Ended

Quarter

Ended

Quarter

Ended

December 31, December 31, December 31, December 31,

2019 2018 2019 2018

($ in millions, except per share data) Stand-alone% Increase/

(Decrease)Consolidated

% Increase/

(Decrease)

Adjusted Net (Loss) Income ($27) $120 -122.5% $22 $160 -86.3%

Total Shares Outstanding (in millions)(1)

186.6 198.3 -5.9% - - -

Adjusted Net (Loss) Income per Outstanding Share (1)

($0.14) $0.61 -123.0% - - -

Adjusted EBITDAX $214 $270 -20.7% $264 $314 -15.9%

Adjusted EBITDAX per Outstanding Share(1)

$1.15 $1.36 -15.4% $1.41 $1.58 -10.8%

Capital Expenditures(2)

$156 $266 -41.4% - - -

Quarter

Ended

Quarter

Ended

December 31, December 31,

(Per Mcfe) 2019 2018

Average Sales Price - Total Company $2.54 $3.09

Total Production Cash Costs(3)

$1.11 $1.00

Operating Cash Margin $1.43 $2.09

Operating Cash Margin (%) 56% 68%

Total Fully Burdened Cash Costs(4)

$1.63 $1.47

Fully Burdened Cash Margin $0.91 $1.62

$1.64 $1.70 $1.69 $1.63

$1.33

$0.93 $0.82

$0.91

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2019 Q2 2019 Q3 2019 Q4 2019

Total Fully-Burdened Cash Costs Total Fully-Burdened Cash Margin

$1.11 $1.18 $1.13 $1.11

$1.86

$1.45 $1.38 $1.43

$0.00

$0.50

$1.00

$1.50

$2.00

Q1 2019 Q2 2019 Q3 2019 Q4 2019

Total Production Cash Costs Total Production Cash Margin

($/Mcfe) 4Q 2019 4Q 2018

Y/Y

Change 4Q 2019 3Q 2019

Q/Q

Change

Average Sales Price(1)

$2.54 $3.09 ($0.55) $2.54 $2.51 $0.03

Total Production Costs(2)

$1.97 $1.89 $0.08 $1.97 $1.99 ($0.02)

Sales Volumes (Bcfe) 143.4 136.1 7.3 143.4 128.3 15.1

Sales Volumes by Category (Bcfe)

Marcellus 101.3 87.0 14.3 101.3 87.3 14.0

Utica 28.3 34.1 (5.8) 28.3 26.8 1.5

CBM 13.7 14.9 (1.2) 13.7 14.1 (0.4)

Other 0.1 0.1 0.0 0.1 0.1 0.0

Margin 63% 55% 55% 56%

Q4 2019 Operational Results Summary

28

▪ Marcellus Shale cash production costs were $1.28 per Mcfe in Q4

2019, up $0.08 from $1.20 per Mcfe in Q4 2018, or a 7% increase

▪ Utica Shale cash production costs were $0.47 per Mcfe in Q4 2019, an

increase of $0.05, from $0.42 per Mcfe in Q4 2018

- The increase in both Marcellus and Utica cash costs was mainly a

result of higher firm transportation costs and CNXM fees

▪ E&P stand-alone capital expenditures decreased 41% Y/Y to $156

million in Q4 2019 from $266 million spent in Q4 2018

(1) Average sales prices for 4Q2019, 4Q2018, and 3Q2019 include gain (loss) on commodity derivative instruments

(cash settlements) of $0.33, ($0.56), and $0.47 per Mcf, respectively.

(2) Total Production Costs for 4Q2019, 4Q2018, and 3Q2019 include DD&A of $0.86, $0.89, and $0.86 per Mcfe,

respectively.

(3) Includes per unit Lease Operating Expense; Transportation, Gathering and Compression; and Production, Ad Valorem and Other Fees. See non-GAAP reconciliation

table in appendix.

(4) Fully burdened cash costs include production cash costs, selling, general and administrative (SG&A) cash costs, other operating cash expense, other cash (income)

expense, and interest expense. Q4 2019, Q3 2019, Q2 2019, and Q1 2019 total fully burdened cash costs exclude a gain on asset sales of $0.25 per Mcfe, $0.03

per Mcfe, $0.00 per Mcfe, and $0.03 per Mcfe, respectively.

Production Cash Costs(3) and Margins 1Q19-4Q19 Fully-Burdened Cash Costs(4) and Margins 1Q19-4Q19

$/M

cfe

$/M

cfe

Margin 45% 35% 33% 36%

Q4 2019 Activity Summary

29

(1) Measured in lateral feet from perforation to perforation.

Q4 2019 2019

($ in millions) TD FRAC TIL

Average

Lateral

Length(1)

Rigs at

Period

End TD FRAC TIL

SWPA

Central

Marcellus 4 6 4 9,850 - 38 34 36

Utica 1 1 1 5,925 - 13 9 8

WV

Shirley-Penns

Marcellus 4 - - - 1 9 5 5

Utica - - - - - - - -

CPA South Utica - - - - - 1 - -

OH Dry Utica 3 - - - 1 5 2 2

Total 12 7 5 2 66 50 51

Expect to run 2 rigs and 1 frac crew in 2020

Executive Summary

30

Q4 2019 EXPECTATION

STRATEGIC INITIATIVE

Substantial Hedge Position▪ ~98% of 2020 gas volumes hedged at NYMEX $2.96

per Mcf; ~83% of 2021 gas volumes hedged at

NYMEX $2.91 per Mcf

▪ Hedge book protects our returns and margins for the

majority of 2020 and 2021 activity

Low Production Cash Costs▪ Production cash costs improved in the fourth quarter

to $1.11 per Mcfe, compared to the third quarter

▪ 2020 production cash costs expectations are in-line

with 2019, while SG&A and other operating expenses

are down meaningfully in 2020, compared to 2019

Significant Expected SG&A Savings▪ Continue to integrate and optimize combined

upstream and midstream teams to streamline

operations and capitalize on efficiencies

▪ Significant expected consolidated cash SG&A

savings of ~$25M in 2020, compared to 2019

Balance Sheet & Leverage Ratio ▪ 2022 senior notes maturities easily addressed ▪ 2021 leverage ratio set to go lower than 2020

EBITDAX, Capital, and FCF

Guidance

▪ Increasing FY2020 E&P EBITDAX guidance to $765-

$810M from $710-$755M; decreasing FY2020 E&P

capital expenditure guidance to $450-$510M from

$490-$550M

▪ Continue to make all capital allocation decisions on a

strict rate of return basis and look for opportunities to

increase efficiencies

SWPA Utica and Stacked Pay▪ One 4-well pad in 2020 plan to execute blending

strategy in Richhill development field

▪ SWPA Utica continues to serve an integral economic

purpose in our investment portfolio (primarily

blending), and that purpose will continue to provide

opportunity for continual reservoir productivity

optimization in 2020

Note: The Non-GAAP financial measures in the table above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation.“

CNX Resources Corporation is unable to provide a reconciliation of projected stand-alone or consolidated adjusted EBITDAX to projected operating income, the most

comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate GAAP projected operating income given the unknown effect,

timing, and potential significance of certain income statement items.

Midpoints of Guidance Ranges 2019 Actuals/Midpoints of 2020 Guidance Total Changes

($ in millions) 2019 2020E Total 2019A 2020E Total Since Q2 2019

Production (Bcfe) 520 583 1,103 539 540 1,079 (24)

Total E&P Capital $920 $580 $1,500 $876 $480 $1,356 ($144)

Stand-Alone EBITDAX $750 $793 $1,543 $772 $788 $1,560 $17

Natural Gas 2020 NYMEX ($/MMBtu) $2.55 $2.09(1)

($0.46)

Cumulative Changes Since Q2 2019 Call

31

~$30M in

SG&A

removed

from system

since 2018

Plan Flexibility Based on Macro and Market Conditions

Disciplined Capital Allocators

Plan Based on Risk-Adjusted Returns, Supported by

Best-in-Class Hedge Book

Q2 2019 Earnings Call (7/30/2019) Q4 2019 Earnings Call (1/30/2020)

Note: The 2019 Non-GAAP financial measures in the table above are defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation.“ CNX is

unable to provide a reconciliation of projected financial results contained in this presentation, including FCF, adjusted EBITDAX, fully burdened cash costs and other metrics

to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected metrics,

including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items..

(1) Forward market price as of 1/24/2020.

Marketing Highlights and Liquids Realizations

32

Marketing Highlights

▪ Directly-marketed ethane volumes were 273,000

barrels in Q4 and, on an equivalent basis, yielded a

$0.06 per MMBtu premium over CNX’s residue

natural gas alternative.

2019 2018

Q4 Q4

NYMEX Natural Gas ($/MMBtu) $2.50 $3.64

Average Differential (0.51) (0.29)

BTU Conversion (MMBtu/Mcf)(1) 0.15 0.24

Gain on Commodity Derivative

Instruments-Cash Settlement0.33 (0.56)

Realized Gas Price per Mcf $2.47 $3.03

(1) Conversion factor 1.08 1.07

Natural Gas Price Reconciliation

Natural Gas Liquids, Oil and Condensate

▪ Q4 2019 liquids sold: 10.5 Bcfe

▪ Total weighted average price of all liquids decreased 20% to $20.49

per Bbl in Q4 2019 from $25.61 per Bbl in Q4 2018 and increased 44%

from $14.26(1) per Bbl in Q3 2019.

▪ In Q4 2019, liquids comprised 7% of production volumes and 11% of

natural gas, NGLs, and oil revenue.

Average Price Realization ($ per Bbl)

2019 2018

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

NGLs $19.20 $13.68 $18.36 $26.76 $24.54 $28.08 $28.38 $27.48

Oil $51.72 $56.64 $50.52 $43.56 $60.54 $63.00 $58.32 $56.46

Condensate $44.68 $75.54(2) $45.36 $39.00 $38.34 $58.56 $56.82 $49.32

(1) $14.11 per Bbl excluding prior period adjustment.

(2) $34.09 per Bbl excluding prior period adjustment.

Financial Guidance: 2020E Natural Gas Marketing Mix and Basis

Note: Forward market prices are as of 1/8/2020.

33

Northeast Pipeline Projects

Southeast Pipeline Projects

ETNG

2020E Gas: 9%

CY20 Basis: $0.20

TCO Pool

2020E Gas: 20%

CY20 Basis: ($0.33)

TETCO ELA & WLA

2020E Gas: 5%

CY20 Basis: ($0.17)

Dawn Pipeline Projects

Gulf Market Pipelines

Michcon

2020E Gas: 10%

CY20 Basis: ($0.18)

DOM South

2020E Gas: 10%

CY20 Basis: ($0.44)

TETCO M2

2020E Gas: 40%

CY20 Basis: ($0.45)

TETCO M3

2020E Gas: 6%

CY20 Basis: $0.06

Percentages include physical sales

Volumes 2020E CY 2020

(000 MMBtu) Gas Sold (%) Basis

DOM South 42,496 8% ($0.44)

ETNG Mainline 21,656 4% $0.20

TCO Pool 79,382 14% ($0.33)

TETCO ELA & WLA 26,828 5% ($0.17)

TETCO M3 33,536 6% $0.06

TETCO M2 192,302 35% ($0.45)

Michcon 54,430 10% ($0.18)

Physical basis sales 101,333 18% ($0.21)

Total (000 MMBtu) 551,963 100% ($0.29)

Total (MMcf) 510,000

NYMEX $2.27

Weighted Average Basis (Not considering hedging) ($0.29)

2020E Average Realized Price (per MMBtu) $1.98

Conversion Factor (MMBtu/Mcf) 1.082

2020E Average Realized Price (per Mcf) $2.14

Market

490.8 417.0

281.0

164.7 147.7

0

50

100

150

200

250

300

350

400

450

500

550

2020 2021 2022 2023 2024

Gas V

olu

mes H

edged (

Bcf)

NYMEX + Basis (2)

Natural Gas Hedging and Basis Protection

34

(2)

Hedge Volumes and Pricing Q1 2020 2020 2021 2022 2023 2024

NYMEX Hedges

Volumes (Bcf) 115.6 479.4 395.4 266.6 136.5 136.6

Average Prices ($/Mcf) $3.00 $2.96 $2.91 $2.99 $2.85 $2.90

Physical Fixed Price Sales and Index Hedges

Volumes (Bcf) 2.8 11.4 21.6 14.4 28.2 11.1


Total Volumes Hedged (Bcf)(1) 118.4 490.8 417.0 281.0 164.7 147.7

NYMEX + Basis (fully-covered volumes)(2)

Volumes (Bcf) 118.4 490.8 417.0 281.0 164.7 147.7


NYMEX Hedges Exposed to Basis

Volumes (Bcf) - - - - - -

Average Prices ($/Mcf) - - - - - -

Total Volumes Hedged (Bcf)(1) 118.4 490.8 417.0 281.0 164.7 147.7

CNX’s substantial

hedge book de-risks

rates of return and

creates time to adjust

development plans

and protect the

balance sheet in the

face of weaker prices

Fully-covered hedges represent

~96% of 2020 dry gas volumes(3)

NYMEX hedges added during Q4:

42.8 Bcf (2023 and 2024)

Basis hedges added during Q4:

149.7 Bcf (2020, 2021, 2022, 2023,

and 2024)

(1) Hedge positions as of 1/8/2020. Excludes basis hedges in excess of NYMEX hedges of 3.3 Bcf, 6.8 Bcf, 26.3 Bcf, 24.3 Bcf, 9.4 Bcf, and 3.8 Bcf for Q1 2020, 2020,

2021, 2022, 2023, and 2024, respectively.

(2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements.

(3) Assuming midpoint of total dry gas production guidance for 2020E.

Q1 2020 and 2020 Gas Hedging Gain/Loss Projections

35

Note: Forward market prices, hedged volumes, and hedge prices are as of 1/8/2020. Anticipated hedging activity is not included in projections.

(1) January prices are settled.

(2) Q1 and annual amounts based on sum of monthly hedge positions vs. strip.

▪ In addition to NYMEX and basis financial hedges, CNX has physical fixed basis sales and physical fixed price sales with customers

▪ 2020E physical fixed basis sales and physical fixed price sales: 93.6 Bcf

▪ Physical sales provide additional basis hedge

- Flows through gas sales in financials

Q1 2020 CY2020

Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted

Hedged Volumes Hedged Forward Gain/(Loss)(2)

Hedged Volumes Hedged Forward Gain/(Loss)(2)

(000 MMBtu) Price Market(1)

($ in 000s) (000 MMBtu) Price Market(1)

($ in 000s)

($/MMBtu)

NYMEX 124,840 $2.78 $2.14 $78,787 518,000 $2.74 $2.27 $240,655

Basis:

DOM South (DOM) 18,655 ($0.57) ($0.39) ($3,326) 75,030 ($0.57) ($0.44) ($9,457)

TCO Pool (TCO) 15,925 ($0.39) ($0.32) ($1,065) 65,580 ($0.39) ($0.33) ($3,627)

Michcon (NMC) 7,963 ($0.16) ($0.11) ($381) 34,013 ($0.17) ($0.18) $252

TETCO ELA (TEB) 1,820 ($0.09) ($0.10) $27 7,320 ($0.09) ($0.11) $128

TETCO WLA (TWB) 3,640 ($0.08) ($0.07) ($8) 14,640 ($0.08) ($0.06) ($175)

TETCO M3 (TMT) 5,005 $1.39 $0.85 $2,744 16,315 $0.20 $0.06 $2,506

TETCO M2 (BM2) 47,320 ($0.55) ($0.37) ($8,522) 210,810 ($0.54) ($0.45) ($19,189)

Transco Zone 5 South (DKR) - - - - 12,530 $0.16 $0.27 $1,461

Total Financial Basis Hedges 100,328 ($10,531) 436,238 ($28,101)

Total Projected Realized Gain $68,256 $212,554

December 31,

2019 2018

Deferred Tax Assets:

Alternative Minimum Tax $ 51,241 $ 102,482

Net Operating Loss - Federal 202,913 124,341

Net Operating Loss - State 130,430 110,339

Foreign Tax Credit 43,194 43,194

Interest Limitation 25,734 32,147

Equity Compensation 9,308 13,096

Gas Well Closing 17,888 10,140

Salary Retirement 9,236 9,434

Capital Lease 1,209 1,624

Other 10,030 13,714

Total Deferred Tax Assets 501,183 460,511

Valuation Allowance (125,054) (94,455)

Net Deferred Tax Assets 376,129 366,056

December 31, December 31,

2019 2018

Current Assets

Cash and Cash Equivalents $ 16,283 $ 17,198

Accounts and Notes Receivable

Trade 133,480 252,424

Other Receivables 13,679 11,077

Supplies Inventories 6,984 9,715

Recoverable Income Taxes 62,425 149,481

Prepaid Expenses 265,250 61,791

Total Current Assets 498,101 501,686

2020 AMT Credit and Additional Refunds

Note: Current Assets and Deferred Tax tables from the 2019 and 2018 10-K respectively.

36

▪ Combined AMT refund and additional tax refunds to drive total

cash tax inflow of ~$62 million in 2020

▪ Incremental AMT refund expected in 2020 and 2021 of approximately

$51 million each year

▪ Company continues to expect no cash tax payments for 4-5 years due

to NOL utilization

$138 million of AMT and other tax refunds

received in 2019

CPA Dry Utica Results Remain Consistent and Strong

37

CPA Dry Utica Results

Pressure Drawdown vs 7,000’ Norm. Cumulative Production

CPA Dry Utica Cumulative Production

Normalized to 7000’

▪ BP6 TIL Q4- 2018 performing in-line with other wells in area

▪ Strong, consistent, and repeatable performance is increasing

confidence in the production and economics of CPA Utica

▪ Combined with recent D&C efficiencies in SWPA Utica at

below $1,800/ft D&C yields high returns

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

- 2,000 4,000 6,000 8,000 10,000

% o

f In

itia

l R

ese

rvo

ir P

ressu

re

Cumulative Production (MMcf)

BP6 AIKENS5J AIKENS5M GAUT4

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0 100 200 300 400 500 600

Cum

ula

tive

Pro

du

ctio

n (

MM

cf)

Days

BP6 AIKENS5J AIKENS5M GAUT4

CNX Acreage Position Remains Top-Tier in Appalachia

Source: Company reports. Peers include AR, COG, EQT, GPOR, RRC, SWN.

(1) Locations calculated by dividing total controlled acreage in type curve region by the area of a well (9,500’ lateral length * 750’ inter-lateral spacing).

(2) Any incremental leasing and associated land leasing capital spend would increase the number of undeveloped locations. 38

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000


Appalachian Peer Group Net Acres CNX SWPA Central Marcellus Locations(1)

Assuming a run rate of 36

SWPA Central Marcellus TILs

per year:

CNX maintains ~12 years of

core inventory after YE2020

CNX maintains approximately

12 years of additional

inventory in Shirley/Pens

WVa., assuming 1 pad per year

CNX’s production grows with

only 40 wells per year

CNX’s controlled acres are only

~6% developed

SWPA Tier 1 Undeveloped Acres 69,800

Divided by

Acres per well 163

Equals

Total Undrilled Locations 427

Average wells TIL (2018-2020E) 36

Years Inventory remaining 12

Non-GAAP Reconciliation

39

Source: Company filings.

(1) Stand-alone includes both CNX’s E&P and Unallocated segments.

(2) MLP cash flow from operations and CNX Gathering calculated using same percentage mix of gross adjusted EBITDA and adjusted EBITDA net to the MLP, which in

Q4 2019 was 95.0% and 5.0%, respectively. Consolidated cash flow from operations for CNX Midstream for Q4 2019 was $41.4 million.

Cash from Operations and Capital Expenditures by Segment

Three Months Ended

December 31,

2019 2018 2019 2018

($ in thousands)Stand-alone

(1)Stand-alone

(1) Total Company Total Company

Net (Loss) Income from EBITDAX Reconciliation ($287,970) $90,106 ($240,055) $129,415

Adjustments

Total Pre-tax Adjustments from EBITDAX Reconciliation 353,715 41,297 354,113 41,933

Tax Effect of Adjustments (92,433) (11,199) (92,537) (11,371)

Adjusted Net (Loss) Income ($26,688) $120,204 $21,521 $159,977

December 31, 2019


(1) Midstream Total Company

Total Long-Term Debt (GAAP) $2,048,531 $705,912 $2,754,443

Less Cash and Cash Equivalents 15,328 955 $16,283

Net Debt (Non-GAAP) $2,033,203 $704,957 $2,738,160

($ in millions)

Q4 2019

E&P

Standalone +

CNX

Gathering(2)

= CNX + MLP(2)

=

Total

Consolidated

Cash from Operations $73.1 $2.1 $75.1 $39.3 $114.5

Capital Expenditures $151.6 $4.1 $155.7 $72.4 $228.1


40

Price and Cost Data per Mcfe

($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019

Average Sales Price - Total Company 2.85$ 2.47$ 2.50$ $ 2.80 3.00$ 2.87$ 2.92$ $ 3.09 2.97$ 2.63$ 2.51$ 2.54$

Lease Operating Expense 0.23$ 0.23$ 0.22$ 0.21$ 0.28$ 0.21$ 0.14$ 0.12$ 0.14$ 0.15$ 0.11$ 0.09$

Transportation, Gathering and Compression 0.99$ 0.94$ 0.98$ 0.87$ 0.86$ 0.82$ 0.84$ 0.82$ 0.92$ 0.98$ 0.97$ 0.97$

Production, Ad Valorem, and Other Fees 0.09$ 0.05$ 0.06$ 0.08$ 0.07$ 0.06$ 0.06$ 0.06$ 0.05$ 0.05$ 0.05$ 0.05$

Depreciation, Depletion and Amortization 1.01$ 0.98$ 1.00$ 1.01$ 0.89$ 0.91$ 0.93$ 0.89$ 0.88$ 0.89$ 0.86$ 0.86$

Total Production Costs 2.32$ 2.20$ 2.26$ 2.17$ 2.10$ 2.00$ 1.97$ 1.89$ 1.99$ 2.07$ 1.99$ 1.97$

Less: Depreciation, Depletion and Amortization 1.01$ 0.98$ 1.00$ 1.01$ 0.89$ 0.91$ 0.93$ 0.89$ 0.88$ 0.89$ 0.86$ 0.86$

Total Cash Production Costs 1.31$ 1.22$ 1.26$ 1.16$ 1.21$ 1.09$ 1.04$ 1.00$ 1.11$ 1.18$ 1.13$ 1.11$

Operating Cash Margin 1.54$ 1.25$ 1.24$ 1.64$ 1.79$ 1.78$ 1.88$ 2.09$ 1.86$ 1.45$ 1.38$ 1.43$


41



Twelve Months Ended

December 31,

2019 2019 2019



Net (Loss) Income ($134,706) $166,654 $31,948

Interest Expense 121,054 30,325 151,379

Interest Income (1,915) (34) (1,949)

Income Tax Expense 27,736 - 27,736

Earnings Before Interest & Taxes (EBIT) 12,169 196,945 209,114

Depreciation, Depletion & Amortization 474,351 34,112 508,463

Exploration Expense 44,337 43 44,380

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $530,857 $231,100 $761,957

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (306,325) - (306,325)

Impairment of Exploration and Production Properties 327,400 - 327,400

Impairment of Unproved Properties and Expirations 119,429 - 119,429

(Gain) Loss on Certain Asset Sales and Abandonments (3,665) 7,229 3,564

Severance Expense 2,881 436 3,317

Stock-Based Compensation 36,545 1,880 38,425

Loss on Debt Extinguishment 7,614 - 7,614

Shaw Event 4,305 - 4,305

Shaw Insurance Recovery (2,159) - (2,159)

Total Pre-tax Adjustments $186,025 $9,545 $195,570

Adjusted EBITDAX Consolidated $716,882 $240,645 $957,527

Midstream Distributions 55,333 N/A N/A

Stand-alone EBITDAX $772,215 N/A N/A


42



Three Months Ended

December 31,

2019 2019 2019



Net (Loss) Income ($287,970) $47,915 ($240,055)


Interest Income (66) (12) (78)

Income Tax Benefit (50,398) - (50,398)

Earnings Before Interest & Taxes (EBIT) (309,062) 55,582 (253,480)


Exploration Expense 29,437 43 29,480

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) ($154,893) $64,737 ($90,156)

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (92,538) - (92,538)

Impairment of Exploration and Production Properties 327,400 - 327,400

Impairment of Unproved Properties and Expirations 119,429 - 119,429

Severance Expense 113 - 113

Stock-Based Compensation 1,470 398 1,868

Shaw Insurance Recovery (2,159) - (2,159)

Total Pre-tax Adjustments $353,715 $398 $354,113





43



Three Months Ended

December 31,

2018 2018 2018



Net Income $90,106 $39,309 $129,415


Interest Income 1 - 1

Income Tax Expense (23,713) - (23,713)

Earnings Before Interest & Taxes (EBIT) 92,865 46,060 138,925


Exploration Expense 2,633 - 2,633

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $217,812 $53,830 $271,642

Adjustments:

Unrealized Loss on Commodity Derivative Instruments 36,727 - 36,727

Loss on Certain Asset Sales 96 - 96

Severance Expense (55) - (55)

Stock-Based Compensation 4,844 636 5,480

Loss on Debt Extinguishment (315) - (315)

Total Pre-tax Adjustments $41,297 $636 $41,933





44


Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

March 31, June 30, September 30, December 31, December 31,

($ in thousands) 2019 2019 2019 2019 2019

Net (Loss) Income ($64,651) $192,694 $143,960 ($240,055) $31,948

Interest Expense 35,771 40,152 38,405 37,051 151,379

Interest Income (722) (71) (1,078) (78) (1,949)

Income Tax (Benefit) Expense (11,559) 40,791 48,902 (50,398) 27,736

Earnings Before Interest & Taxes (EBIT) (41,161) 273,566 230,189 (253,480) 209,114

Depreciation, Depletion & Amortization 125,161 128,999 120,459 133,844 508,463

Exploration Expense 3,258 5,567 6,075 29,480 44,380

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $87,258 $408,132 $356,723 ($90,156) $761,957

Adjustments:

Unrealized Loss (Gain) on Commodity Derivative Instruments 153,994 (210,909) (156,872) (92,538) (306,325)

Impairment of Exploration and Production Properties - - - 327,400 327,400

Impairment of Unproved Properties and Expirations - - - 119,429 119,429

Loss on Certain Asset Sales and Abandonments 3,564 - - - 3,564

Severance Expense 23 1,182 1,999 113 3,317

Stock Based Compensation 10,903 23,873 1,781 1,868 38,425

Loss on Debt Extinguishment 7,537 77 - - 7,614

Shaw Event 4,305 - - - 4,305

Shaw Insurance Recovery - - - (2,159) (2,159)

Total Pre-tax Adjustments $180,326 ($185,777) ($153,092) $354,113 $195,570

Adjusted EBITDAX Consolidated TTM $267,584 $222,355 $203,631 $263,957 $957,527

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