Earnings Results - CNX Resources...

Earnings ResultsThird Quarter 2019

October 29, 2019

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 cash flow and other projected non-GAAP metrics for fiscal or quarterly periods in

2019 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

Large, High Quality Inventory in the Core Marcellus and Utica

Low Cash Costs Matters Even More in a Low Price Environment

Strong Hedge Position Protects Future Cash Flows and Ensures Capital Returns

On Track to Significantly Lower SG&A

Increasing Free Cash Flow Despite Lower Commodity Price Since Last Update

Strong Performance in Q3 for both CNX and CNXM

Strong Balance Sheet

An Emphasis on Flexibility and Ability to React to Dynamic Commodity Price Environment

Major Highlights

3

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. 4

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

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

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

Assuming a run rate of 36

SWPA Central Marcellus TILs

per year:

CNX maintains ~12 years of

core inventory after YE2020

CNX maintains approximately

12 years of additional

inventory in Shirley/Pens

WVa., assuming 1 pad per year

CNX’s production grows with

only 40 wells per year

CNX’s controlled acres are only

~6% developed

SWPA Tier 1 Undeveloped Acres 69,800

Divided by

Acres per well 163

Equals

Total Undrilled Locations 427

Average wells TIL (2018-2020E) 36

Years Inventory remaining 12

$0.78 $0.79

$1.11 $1.15

$1.25 $1.31

$1.70

$2.15

-

0.75

1.50

2.25

CNXConsolidated


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

5

Low Production Cash Costs Create Competitive Advantage

(1) TTM as of Q3 2019 end for CNX and TTM as of Q2 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 total company gathering rates with benefit of MLP.

(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 Q3 2019 for CNX and TTM as of Q2 2019 for peers.

TTM Q2/Q3 2019 Production Cash Costs per Mcfe(1)

CNX’s top-tier

production cash

costs and

substantial hedge

book create a

significant

advantage in a weak

natural gas pricing

environment

(4)

Avg. Daily

Production(5)

(Bcfe/d)

1.5 2.2 1.5 1.4 4.2 2.3 2.2 3.1

(2)

(3)

Workflow Integration Driving Significant SG&A Savings

6

Consolidated

FY2018

Actual

$113M(1)

UPDATED

Consolidated

FY2019E

Guidance

$100M(1)

PREVIOUS

Consolidated

FY2020E

Guidance

$110M(1)

UPDATED

Consolidated

FY2020E

Guidance

$85M(1)

~$30M in consolidated SG&A savings expected

in 2020, compared to 2018

(1) Consolidated cash SG&A excludes non-cash stock compensation expense and based on the midpoint of the guidance range.

UPDATED

Stand-Alone

FY2020E

Guidance

$70M(1)

PREVIOUS

Consolidated

FY2019E

Guidance

$110M(1)

94 % 91 %

59 % 58 %

30 %

16 %

0 %

$2.97

$2.87

$2.63

$2.88

$2.77 $2.77

$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 ($

/Mcf)

Substantial Hedges in 2020 and 2021 with Strongest Hedge Price

Note: Peers include AR, COG, EQT, GPOR, RRC, SWN. As of Q3 2019 for CNX and as of Q2 2019 for peers. NYMEX as of October 9, 2019.

(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. 7

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

79 %76 %

26 %23 %

0 % 0 % 0 %

$2.79

$ 2.93

$ 2.83

$ 2.55

$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 2 Peer 3 Peer 4 Peer 5 Peer 6%

of

Co

nsen

su

s P

rod

. H

ed

ged

2021 % of Production Hedged 2021 Average NYMEX Price Floor

Pri

ce F

loo

r ($

/Mcf)

2021E % of production

hedged increases to 80%

under a scenario of flat

2020 gas volumes of 520

Bcf

NYMEX Strip $2.40 in 2020

NYMEX Strip $2.43 in 2021

~53% of 2022E production

hedged at NYMEX $3.01

per Mcf under a scenario

of flat 2020 gas volumes

of 520 Bcf

Despite Weaker Gas Prices, Preserved FCF and Bolstered 2021 Inventory

8

Q2 $135M Free Cash FlowOLD 2020 FCF Guidance

Outside Changes NYMEX Declined in 2020 ($2.55 to $2.40 per MMBtu) & 2019

Management Changes Volumes Capital Costs

$146M Free Cash FlowNEW 2020 FCF Guidance Q3

2019 also improved: EBITDAX$5M Capital $17.5M

Despite gas prices significantly weakening in 2019 & 2020, CNX increased

its 2019 & 2020 FCF by over $30M

Note: CNX Resources Corporation is unable to provide a reconciliation of projected E&P Stand-alone FCF 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.

Competitive Advantages and Philosophy Drive Investment Thesis

9

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 GP

Water infrastructureBlending strategy Share repurchases

Investments in high rate of return opportunities

(over 20% hurdle rate)

Capital allocation process

drives NAV per share growth

Core SWPA

Marcellus inventory

Net Debt

Or Debt Paydown /

Share Buybacks

Operations Update

$1.72 $1.66 $1.63 $1.46 $1.61 $1.70 $1.69

$1.28 $1.21 $1.29

$1.63

$1.36

$0.93 $0.82

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019

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

$1.21 $1.09 $1.04 $1.00 $1.11 $1.18 $1.13

$1.79 $1.78 $1.88

$2.09

$1.86

$1.45 $1.38

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019

Total Production Cash Costs Total Production Cash Margin

Margin 60% 62% 64% 68% 63% 55% 55%

Q3 2019 Operational Results Summary

11

▪ Marcellus Shale cash production costs were $1.33 per Mcfe in Q3

2019, up $0.08 from $1.25 per Mcfe in Q3 2018, or a 6% increase

▪ Utica Shale cash production costs were $0.48 per Mcfe in Q3 2019, a

decline of $0.08, or 14%, from $0.56 per Mcfe in Q3 2018

- The decline in Utica cash costs was a result of lower production

taxes and processing costs associated with the divestiture of CNX’s

wet Ohio Utica acreage in 2018

▪ E&P stand-alone capital expenditures increased 7% Y/Y to $272 million

in Q3 2019 from $255 million spent in Q3 2018

- Q3 2019 capital spend came in better than expected(1) Average sales prices for 3Q2019, 3Q2018, and 2Q2019 include gain on commodity derivative instruments (cash

settlements) of $0.47, $0.03, and $0.08 per Mcf, respectively.

(2) Total Production Costs for 3Q2019, 3Q2018, and 2Q2019 include DD&A of $0.86, $0.93, and $0.89 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) Includes Production Cash Costs listed above plus SG&A (excluding non-cash stock compensation), Other Operating Cash Expense, Other Cash Expense (Income),

and Interest Expense.

Production Cash Costs(3) and Margins 1Q18-3Q19 Fully-Burdened Cash Costs(4) and Margins 1Q18-3Q19

($/Mcfe) 3Q 2019 3Q 2018

Y/Y

Change 3Q 2019 2Q 2019

Q/Q

Change

Average Sales Price(1)

$2.51 $2.92 ($0.41) $2.51 $2.63 ($0.12)

Total Production Costs(2)

$1.99 $1.97 $0.02 $1.99 $2.07 ($0.08)

Sales Volumes (Bcfe) 128.3 119.0 9.3 128.3 134.5 (6.2)

Sales Volumes by Category (Bcfe)

Marcellus 87.3 70.6 16.7 87.3 92.4 (5.1)

Utica 26.8 33.6 (6.8) 26.8 28.1 (1.3)

CBM 14.1 14.7 (0.6) 14.1 13.9 0.2

Other 0.1 0.1 0.0 0.1 0.1 0.0

Margin 43% 42% 44% 53% 46% 35% 33%

$/M

cfe

$/M

cfe

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

▪ Two SWPA dry Utica pads TIL'd in Q3 2019

- MAJ 6 (4 wells)

- MOR 10 (3 wells)

▪ One SWPA dry Utica pad to TIL in Q1 2020

▪ Only completing enough to blend over the next several

years

- 1 pad expected to TIL in both 2020 and 2021

▪ 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

Drilling Highlights

▪ RHL 8 – 6 Well Marcellus Pad – High Operational Performance

- Drilling days average of ~ 13 days per well

- Drilling footage in lateral of an average of 5,891’ per day

▪ Most recent rig move from pad to pad of 2.75 days

Completions Highlights

▪ Stimulation record of 15 stages in 24 hours

▪ Most recent pad will be completed by Evolution all-electric frac crew

average ~18 pump hours per day

First Appalachian basin long-term contract currently underway

▪ Realizing savings of ~$250,000 per well related to fuel costs, which is an

increase of $70,000 per well from previous update

▪ Richhill water line from Ohio River to PA is operational and serving as

primary water source for SWPA stimulation operations

Production and Midstream Highlights

▪ Lower OPEX - Implementation of automated sand traps

▪ Commissioned 17,500 hp of compression (5 Morris / 2 Shirley) having a

capacity of 350 MMcf per day

Evolution Frac Crew

Financial Results &

Guidance Update

Q3 2019 Financial Results Summary

15

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."

(1) For the quarter ended September 30, 2019, total shares outstanding of 186,586,751 (Non-GAAP) are as of October 15, 2019. For the quarter ended September 30, 2018,

total shares outstanding of 203,599,810 (Non-GAAP) are as of October 16, 2018.

(2) Capital expenditures exclude $63.9 million and $42.3 million of total capital investment net to CNXM in the third quarter of 2019 and 2018, respectively, as reported in

CNXM Third 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

September 30, September 30, September 30, September 30,

2019 2018 2019 2018

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

(Decrease)Consolidated

% Increase/

(Decrease)

Adjusted Net (Loss) Income ($11) $26 -142.3% $31 $57 -45.6%

Total Shares Outstanding (in millions)(1)

186.6 203.6 -8.3% - - -

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

($0.06) $0.13 -145.3% - - -

Adjusted EBITDAX $159 $203 -21.7% $204 $239 -14.6%

Adjusted EBITDAX per Outstanding Share(1)

$0.85 $1.00 -14.8% $1.09 $1.17 -6.6%

Capital Expenditures(2)

$272 $255 6.7% - - -

Quarter

Ended

Quarter

Ended

September 30, September 30,

(Per Mcfe) 2019 2018

Average Sales Price - Total Company $2.51 $2.92

Total Production Cash Costs(3)

$1.13 $1.04

Operating Cash Margin $1.38 $1.88

Operating Cash Margin (%) 55% 64%

Total Fully Burdened Cash Costs(4)

$1.69 $1.63

Fully Burdened Cash Margin $0.82 $1.29

Fully Burdened Cash Margin (%) 33% 44%

16

Flexibility to weather

commodity headwinds…

◼ In the event of a sustained downturn in gas prices, CNX has the ability and discipline to reduce activity and preserve balance

sheet strength and inventory

— Substantially all acreage is HBP or owned in fee, limiting the need to “drill to hold”

— Thoughtful firm transportation commitments, limiting the need to “drill to fill”

— Minimal service provider commitments

— Active hedging / risk mitigation program with strong prices for 2020 & 2021

◼ Internally, CNX regularly reviews downside scenarios that minimize drilling and take advantage of existing hedge position to

maximize free cash flow and preserve the balance sheet

…Or accelerate to take

advantage of tailwinds

◼ Conversely, in the event of a sustained rally in gas prices, CNX has the ability to quickly accelerate activity and maximize

cash flow generation and corporate returns

— Substantial, low-cost / high margin inventory

— All significant infrastructure in place

— Ability to take advantage of significant liquidity position to satisfy near-term capex requirements, while locking in medium

term cash flows through hedging

— Ability to sell liquid assets

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

An Emphasis on Flexibility in Planning and Strategic Decisions

16

Updated 2019 and 2020 Guidance

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) Expected 5-6% liquids.

(2) Forward market prices are as of 10/9/2019. 2019 price on open volumes reflects Q4 2019 only.

(3) Includes CNX Midstream LP+GP/IDR distributions of $55 million in FY2019E and $75 in FY2020E. Per share using 186.6 million shares outstanding as of 10/15/2019.17

Previous UPDATED Previous UPDATED

2019E 2019E 2020E 2020ECapital Expenditures($ millions)

Low High Low High Low High Low High

Drilling & Completions $695 $745 $690 $715 $450 $520 $400 $450

Non-D&C $200 $200 $200 $200 $90 $100 $90 $100

Total E&P Capital $895 $945 $890 $915 $540 $620 $490 $550

CNX Midstream LP Capital $310 $330 $310 $330 $80 $100 $80 $100

Total Consolidated Capital $1,205 $1,275 $1,200 $1,245 $620 $720 $570 $650

Production (Bcfe)

Total Production Volumes(1) 510 530 530 540 570 595 535 565

y/y ~1% ~5%

Prices on Open Volumes

Natural Gas NYMEX ($/MMBtu)(2) $2.45 $2.37 $2.55 $2.40

Natural Gas Basis Differential

($/MMBtu)(2) ($0.25)-($0.35) ($0.35)-($0.40) ($0.25)-($0.35) ($0.25)-($0.35)

Adjusted EBITDAX(2)

($ millions)

E&P Standalone +

Distributions(3)$740 $760 $745 $765 $770 $815 $710 $755

E&P Standalone +

Distributions(3) per Share$3.95 $4.05 $3.99 $4.10 $4.11 $4.35 $3.81 $4.05

Consolidated $885 $925 $910 $940 $945 $1,010 $885 $950

2019E D&C capital based on midpoint

expected to decrease by $17.5M from

previous update, while production expected

to increase 15 Bcfe

CNXM capital still expected to decline

significantly following large build year in

2019; as a result, CNXM expected to begin

generating free cash flow in Q1 2020

For 2019 and 2020 combined, D&C capital

is reduced by ~$80 million, resulting in 17.5

Bcfe less production in 2020, compared to

previous update, after accounting for the 15

Bcfe accelerated from 2020 into 2019

Set up to generate significant

FCF in 2020 and beyond, and

we will invest it appropriately

2020E D&C capital based on midpoint

expected to decrease by $60M from

previous updated and production expected

to decrease by ~32.5 Bcfe

Updated 2019 and 2020 Guidance

18

2019E 2020ERevenue and Other Operating Income E&P Consolidated E&P Consolidated

Production Volumes:

Natural Gas (Bcf) 500-508 505-535

NGLs (MBbls) 5,125-5,315 4,490-4,715

Condensate (MBbls) 205-215 245-265

Total Production (Bcfe) 530-540 535-565

% Liquids ~6% ~5%

Natural Gas NYMEX Price ($/MMBtu)(1) $2.37 $2.40

Natural Gas Basis Differential to NYMEX ($/MMBtu)(1) ($0.35)-($0.40) ($0.25)-($0.35)

NGL Realized Price ($/Bbl)(1) $16.00-$18.00 $14.00-$16.00

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

Realized Hedging Gain ($ in millions)(2) $80-$90 $145-$155

Other Operating Income (3rd party water income and resold FT) ($ in millions) $5-$10 $10-$20

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

Costs

Average per unit operating expenses ($/Mcfe):

Lease Operating Expense $0.12-$0.13

Production, Ad Valorem, and Other Fees $0.05-$0.06

Transportation, Gathering and Compression $0.96-$0.98 $0.62-$0.64

Total Cash Production and Gathering Costs $1.13-$1.17 $0.79-$0.83 $1.06-$1.14 $0.67-$0.75

($ in millions)

Selling, General, and Administrative Costs(3) $75-$85 $95-$105 $65-$75 $80-$90

Exploration Expense $15-$20 $0-$10

Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $75-$85 $65-$75

Other Non-Operating Expense (Income) ($10)-($20) $0-$10

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

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

timing, and potential significance of certain income statement items.

(1) Forward market prices are as of 10/9/2019 and reflect Q4 2019 only in 2019E.

(2) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing as of 10/9/2019. Anticipated hedging activity is not included in projections.

(3) Excludes stock-based compensation.

New 2020

consolidated SG&A

guidance is a ~$25M

reduction from

previous guidance of

$105-$115M

Workforce

integration driving

SG&A reductions

New 2019

consolidated SG&A

guidance is a ~$10M

reduction from

previous guidance of

$105-$115M

$80$90 $105

$125

$177 $181 $181

$278

$-

$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

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

19

Already realized ~$25 million in total

expected consolidated cash SG&A

savings out of the original $30 million

target for 2020

▪ 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 Q3 2019 end for CNX and TTM as of Q2 2019 for peers. Peers include AR, COG, EQT, GPOR, RRC, SWN.

TTM Q2/Q3 2019 SG&A(1)

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8P

roduction (

Bcfe

/d)

Legacy PDP Marcellus PUD Utica PUD

Production Cadence and Hedge Advantage 2019-2020

(1) Assumes midpoint of guided 2019-2020 production ranges.

(2) Midpoint of 2020 production guidance range.20

Expected Daily Production 2019-2020(1)

Five-year average all-in

maintenance capital (D&C +

non-D&C): ~$400 million to

hold flat production of 550

Bcfe(2)

Average Hedged Volumes

490 Bcf or 94% of gas production hedged at

NYMEX $2.97 in 2020

2020

Marcellus: 35

Utica: 12

Marcellus: 41

Utica: 10

2019

TIL

s

Hedge advantage continues into

2021 with peer leading 414 Bcf of

volumes fully hedged at an all-in

price (basis included) of $2.40

per Mcf

(0.30)$ (0.20)$ (0.10)$ Base(2)

0.10$ 0.20$ 0.30$

Average NYMEX ($/MMBtu) 2.10$ 2.20$ 2.30$ 2.40$ 2.50$ 2.60$ 2.70$

E&P Standalone

Adjusted EBITDAX + Distributions(3)

$ 719 $ 724 $ 728 $ 733 $ 738 $ 743 $ 748

E&P Standalone FCF(3)(4)

132$ 137$ 141$ 146$ 151$ 156$ 161$

Hedge Book Reduces EBITDAX Sensitivity to Commodity Swings

21

(1) CNX Resources Corporation is unable to provide a reconciliation of projected E&P Stand-alone adjusted EBITDAX or E&P Stand-alone FCF 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) Pricing as of 10/9/2019. Assumes static basis differential of ($0.25)-($0.35) per MMBtu as guided for 2020E.

(3) Based on midpoint of guidance range.

(4) Includes distributions from CNX Midstream plus $62 million in tax refund expected in 2020. FCF defined as Adjusted EBITDAX + Distributions + tax refund –

standalone capital expenditures – standalone interest.

Each $0.10 move in 2020 NYMEX

price results in just a ~$5 million

change in E&P Standalone

Adjusted EBITDAX + Distributions

2020E EBITDAX and FCF Sensitivity(1)

Hedge book drives expected 2020 free cash flow that

is well protected from commodity price swings

22

Overview

◼ Low cost-structure, robust hedge book, and planned capital program are positioning the company to deliver significant free

cash flow in 2020 and beyond

◼ Free cash flow expected to be deployed across three options: incremental 2020 activity at high internal rates of return, debt

reduction, and/or additional share buybacks with focus on optimizing intrinsic per share value

Liquidity

◼ Adequate liquidity maintained to satisfy all potential operating needs

– Over $1.6 billion of consolidated liquidity as of September 30, 2019

– CNX owns ~21.7M common units of CNXM

Operations

◼ CNX hedges production in conjunction with spending the capital associated with drilling for it

◼ Low cost structure with potential for increased savings over time

◼ Capital allocation decisions driven by risk-adjusted rates of return to drive growth and returns while maximizing free cash flow

and balance sheet strength

Hedging

◼ Hedged out to 2024 to protect margins from commodity price fluctuations on existing production and a portion of anticipated

development program

◼ CNX hedges basis to match physical delivery points and fully cover NYMEX hedge volumes

Returns Focus

◼ Focus on risk-adjusted returns drives capital allocation

◼ Demonstrated historical increase in production, EBITDAX/share, and corporate returns over time

22

Prudent Thoughtful Financial Policy

0.7 x2.8 x 2.6 x 2.3 x 2.4 x 3.5 x 3.1 x1.2 x

2.2 x4.2 x

9.4 x11.4 x

11.1 x

15.0 x

1.9 x

5.0 x

6.8 x

11.7 x

13.8 x14.6 x

18.0 x


$1 $ 3 $ 2 $ 2 $ 3 $ 4 $ 5 $2 $2 $4

$9 $10

$18

$24

$3 $5 $6

$11 $13

$21

$29


Highly Resilient Balance Sheet

23

Note: Consensus IBES 2019E EBITDA estimates as of 10/18/19. Peers include AR, COG, EQT, GPOR, RRC, SWN. The Non-GAAP financial measures above are

defined and reconciled to GAAP net income in the appendix under "Non-GAAP Reconciliation."

(1) CNX net debt is consolidated and as of Q3 2019 and as of Q2 2019 for peers. Off-balance sheet obligations based on the respective 2018 10-Ks of CNX and the peer

companies.

Current Leverage (Net Debt + Off-Balance

Sheet Obligations)(1) ($ in billions)▪ 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”

▪ Three filter test for taking on new FT:

- Do we need FT to get to a liquid market?

- Does it get us to a better market at a positive netback?

- Does it help us manage volatility of the markets we are in?

Net Debt + Off-Balance Sheet Obligations /

2019E EBITDA(1)

Net Debt

Off-Balance Sheet Obligations

Net Debt

Off-Balance Sheet Obligations

484%

383%

340%325%

218%

102%

34%

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

402%

316%

268%

248%

133%

43%

20%


85%82%

77%

71%

67%

58%

14%


24

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 10/18/19. Peers include AR, COG, EQT, GPOR, RRC, SWN.

(1) CNX total debt is consolidated and as of Q3 2019 and as of Q2 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. 24

Appendix

Solid Financial and Operational Performance

26

Revenue Protection

Other Liquid Assets

Leading Cash Margins

Proven Execution Track-Record Capital Allocation Via Risk-Adjusted Returns

Long-term Strategic Focus

Conservative Financial Profile

Active Long-term Cost Management 2

3

4

5

1

8

7

6

▪ Active hedging program locks in revenue and de-risks

capital decisions prior to drilling

▪ ~94% total 2020E gas volumes hedged

▪ Own ~21.7 million of CNXM common units and

CNXM GP and related IDR’s

▪ Owned surface acres and other non-core assets

▪ Peer leading cash costs and capital efficiency

▪ Cash production costs in 2020E of approximately

$1.10 per Mcfe

▪ Reduced leverage by 50% from 4.8x at 4Q16 to 2.4x as of 3Q19

▪ Reduced E&P debt by ~$1.4 billion (41%) from YE15 to 3Q19

▪ Consistently deliver or beat expectations

▪ Reduced 19% of shares outstanding since inception of buyback program

▪ Significant reduction to SG&A

▪ Avoided expensive FT contracts that are now underwater

▪ D&C contract durations matched to our hedge book

allowing activity to meet our core operating plan

▪ 3Q19 leverage of 2.4x

▪ Leverage ceiling ≤ 2.5x

▪ Continued focus on medium-term maturities

▪ Upfront planning mitigates future uncertainty

▪ Detailed 5-year operating plan for base case with flexibility

to increase or decrease activity based on market

conditions

▪ Capital allocation decisions are constantly evaluated

▪ Will continue to allocate capital based on risk-adjusted IRRs

▪ Capital dedicated to drill bit due to deep inventory of highly economic locations

▪ Hedge strategy reduces risk when deploying drill bit capital

▪ Flexibility with gas prices

Q3 Activity Summary

27

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

Q3 2019 YTD 2019

($ in millions) TD FRAC TIL

Average

Lateral

Length(1)

Rigs at

Period

End TD FRAC TIL

SWPA

Central

Marcellus 11 10 10 11,169 1 34 29 32

Utica 2 3 7 6,205 1 12 7 7

WV

Shirley-Penns

Marcellus 2 5 5 11,063 5 5 5

Utica - - - - - - -

CPA South Utica - - - - 1 - -

OH Dry Utica - 2 2 - 2 2 2

Total 15 20 24 2 54 43 46

▪ Expect to run approximately two rigs

and one frac crew in 2020

Marketing Highlights and Liquids Realizations

28

Marketing Highlights

▪ Directly-marketed ethane volumes were 262,000

barrels in Q3 and, on an equivalent basis, yielded a

$0.47 per MMBtu premium over CNX Resources’

residue natural gas alternative.

▪ CNX gas price decline from Q2 2019:

Before hedging - (18.7)%

Including hedging - (3.1)%

2019 2018

Q3 Q3

NYMEX Natural Gas ($/MMBtu) $2.23 $2.90

Average Differential (0.33) (0.36)

BTU Conversion (MMBtu/Mcf)(1) 0.14 0.17

Gain on Commodity Derivative

Instruments-Cash Settlement0.47 0.03

Realized Gas Price per Mcf $2.51 $2.74

(1) Conversion factor 1.08 1.06

Natural Gas Price Reconciliation

Natural Gas Liquids, Oil and Condensate

▪ Q3 2019 liquids sold: 8.1 Bcfe

▪ Total weighted average price of all liquids decreased 51% to $14.26(1)

per Bbl in Q3 2019 from $29.35 per Bbl in Q3 2018 and decreased

25% from $19.14 per Bbl in Q2 2019.

▪ In Q3 2019, liquids comprised 6% of production volumes and 7% of

Natural Gas, NGLs and Oil Revenue

Average Price Realization ($ per Bbl)

2019 2018

Q3 Q2 Q1 Q3 Q2 Q1

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

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

Condensate $75.54(2) $45.36 $39.00 $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: 2019E Natural Gas Marketing Mix and Basis

29

Note: Forward market prices are as of 10/9/2019.

Northeast Pipeline Projects

Southeast Pipeline Projects

ETNG

2019E Gas: 10%

CY19 Basis: $0.53

TCO Pool

2019E Gas: 19%

CY19 Basis: ($0.33)

TETCO ELA & WLA

2019E Gas: 5%

CY19 Basis: ($0.10)

Dawn Pipeline Projects

Gulf Market Pipelines

Michcon

2019E Gas: 10%

CY19 Basis: ($0.19)

DOM South

2019E Gas: 8%

CY19 Basis: ($0.45)

TETCO M2

2019E Gas: 42%

CY19 Basis: ($0.48)

TETCO M3

2019E Gas: 6%

CY19 Basis: $0.27

Percentages include physical sales

Volumes 2019E CY 2019

(000 MMBtu) Gas Sold (%) Basis

DOM South 24,788 5% ($0.45)

ETNG Mainline 6,504 1% $0.53

TCO Pool 85,618 16% ($0.33)

TETCO ELA & WLA 18,523 3% ($0.10)

TETCO M3 33,592 6% $0.27

TETCO M2 185,058 34% ($0.48)

Michcon 51,454 9% ($0.19)

Physical basis sales 137,877 26% ($0.13)

Total (000 MMBtu) 543,414 100% ($0.26)

Total (MMcf) 504,000

NYMEX $2.60

Weighted Average Basis (Not considering hedging) ($0.26)

2019E Average Realized Price (per MMBtu) $2.34

Conversion Factor (MMBtu/Mcf) 1.078

2019E Average Realized Price (per Mcf) $2.52

Market

Financial Guidance: 2020E Natural Gas Marketing Mix and Basis

Note: Forward market prices are as of 10/9/2019.

30

Northeast Pipeline Projects

Southeast Pipeline Projects

ETNG

2020E Gas: 9%

CY20 Basis: $0.53

TCO Pool

2020E Gas: 18%

CY20 Basis: ($0.36)

TETCO ELA & WLA

2020E Gas: 5%

CY20 Basis: ($0.09)

Dawn Pipeline Projects

Gulf Market Pipelines

Michcon

2020E Gas: 9%

CY20 Basis: ($0.18)

DOM South

2020E Gas: 12%

CY19 Basis: ($0.44)

TETCO M2

2020E Gas: 41%

CY20 Basis: ($0.48)

TETCO M3

2020E Gas: 6%

CY20 Basis: $0.53

Percentages include physical sales

Volumes 2020E CY 2020

(000 MMBtu) Gas Sold (%) Basis

DOM South 53,661 9% ($0.44)

ETNG Mainline 23,235 4% $0.53

TCO Pool 77,272 14% ($0.36)

TETCO ELA & WLA 26,090 5% ($0.09)

TETCO M3 32,612 6% $0.53

TETCO M2 201,638 36% ($0.48)

Michcon 52,932 9% ($0.18)

Physical basis sales 96,240 17% ($0.22)

Total (000 MMBtu) 563,680 100% ($0.27)

Total (MMcf) 520,000

NYMEX $2.40

Weighted Average Basis (Not considering hedging) ($0.27)

2020E Average Realized Price (per MMBtu) $2.13

Conversion Factor (MMBtu/Mcf) 1.084

2020E Average Realized Price (per Mcf) $2.31

Market

403.4 484.0

414.2

268.0

142.1

1.8

5.6

-

10.1

2.5

0

50

100

150

200

250

300

350

400

450

500

550

2019 2020 2021 2022 2023

Gas V

olu

mes H

edged (

Bcf)

NYMEX Only Hedges Exposed to Basis NYMEX + Basis (2)

Natural Gas Hedging and Basis Protection

31

(2)

Hedge Volumes and Pricing Q4 2019 2019 2020 2021 2022 2023

NYMEX Hedges

Volumes (Bcf) 112.3 388.4 478.3 393.2 264.7 117.5

Average Prices ($/Mcf) $2.98 $3.02 $2.97 $2.93 $3.01 $2.90

Physical Fixed Price Sales and Index Hedges

Volumes (Bcf) 3.4 16.8 11.3 21.0 13.4 27.1


Total Volumes Hedged (Bcf)(1) 115.7 405.2 489.6 414.2 278.1 144.6

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

Volumes (Bcf) 112.9 403.4 484.0 414.2 268.0 142.1


NYMEX Hedges Exposed to Basis

Volumes (Bcf) 2.8 1.8 5.6 - 10.1 2.5

Average Prices ($/Mcf) $2.98 $3.02 $2.97 - $3.01 $2.90

Total Volumes Hedged (Bcf)(1) 115.7 405.2 489.6 414.2 278.1 144.6

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

(1) Hedge positions as of 10/9/2019. 2021 excludes 8.1 Bcf of physical basis sales not matched with NYMEX hedges.

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

(3) Assuming midpoint of total dry gas production guidance in 2019E and 2020E.

Fully-covered hedges represent

~80% and ~93% of 2019E and

2020E base dry gas volumes,

respectively(3)

NYMEX hedges added during Q3:

52.9 Bcf (2019 and 2020)

Basis hedges added during Q3:

130.6 Bcf (2019, 2020, 2021, and

2022)

Q4 2019E, 2019E, and 2020E Gas Hedging Gain/Loss Projections

32

Note: Forward market prices, hedged volumes, and hedge prices are as of 10/9/2019. Anticipated hedging activity is not included in projections.

(1) October prices are settled.

(2) Q4 2019 and annual amounts based on sum of monthly hedge positions vs. strip.

(3) January through October prices are settled.

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

▪ CY 2019E and 2020E physical fixed basis sales and physical fixed price sales: 127.9 Bcf and 88.8 Bcf

▪ Physical sales provide additional basis hedge

- Flows through gas sales in financials

Q4 2019 CY2019 CY2020

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

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



(000 MMBtu) Price Market(1)

($ in 000s) (000 MMBtu) Price Market(3)

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

($/MMBtu)

NYMEX 121,870 $2.74 $2.37 $46,061 419,193 $2.80 $2.60 $99,106 518,000 $2.74 $2.40 $178,119

Basis:

DOM South (DOM) 11,040 ($0.59) ($0.70) $1,176 43,800 ($0.59) ($0.45) ($6,045) 75,030 ($0.57) ($0.44) ($9,293)

TCO Pool (TCO) 22,070 ($0.32) ($0.51) $4,085 64,270 ($0.34) ($0.33) $918 65,580 ($0.39) ($0.36) ($1,626)

Michcon (NMC) 9,275 ($0.18) ($0.29) $1,012 34,092 ($0.19) ($0.19) $109 34,013 ($0.17) ($0.18) $507

TETCO ELA (TEB) 1,840 ($0.09) ($0.10) $19 7,300 ($0.09) ($0.13) $274 7,320 ($0.09) ($0.11) $173

TETCO WLA (TWB) 1,840 ($0.08) ($0.07) ($15) 7,300 ($0.08) ($0.08) $6 14,640 ($0.08) ($0.07) ($80)

TETCO M3 (TMT) 5,590 $0.56 $0.15 $1,595 17,558 $0.25 $0.27 $880 16,315 $0.20 $0.53 ($6,901)

TETCO M2 (BM2) 37,225 ($0.55) ($0.72) $5,681 123,100 ($0.57) ($0.48) ($9,362) 210,810 ($0.54) ($0.48) ($11,671)

Transco Zone 5 South (DKR) - - - - - - - - 4,280 $0.00 $0.61 $233

Total Financial Basis Hedges 88,880 $13,553 297,420 ($13,220) 427,988 ($28,658)

Total Projected Realized Gain $59,614 $85,886 $149,461

December 31,

2018 2017

Deferred Tax Assets:

Alternative Minimum Tax $ 102,482 $ 188,080

Net Operating Loss - Federal 124,341 99,524

Net Operating Loss - State 110,339 107,756

Foreign Tax Credit 43,194 44,402

Interest Limitation 32,147 —

Equity Compensation 13,096 21,866

Gas Well Closing 10,140 55,486

Salary Retirement 9,434 9,404

Capital Lease 1,624 2,020

Other 13,714 11,831

Total Deferred Tax Assets 460,511 540,369

Valuation Allowance (94,455) (136,576)

Net Deferred Tax Assets 366,056 403,793

September 30, December 31,

2019 2018

Current Assets

Cash and Cash Equivalents $ 5,484 $ 17,198

Accounts and Notes Receivable

Trade 96,997 252,424

Other Receivables 11,462 11,077

Supplies Inventories 7,527 9,715

Recoverable Income Taxes 11,184 149,481

Prepaid Expenses 213,072 61,791

Total Current Assets 345,726 501,686

2019 AMT Credit and Additional Refunds

Note: Current Assets and Deferred Tax tables from Q3 2019 10-Q and 2018 10-K respectively.

(1) Timing of recovery of approximately $3.5 million remains uncertain and therefore not included in 2019 plan.

33

▪ $138 million of AMT and other tax refunds received year-to-date

- Additional cash tax refunds related to past filings and other

miscellaneous recoveries of ~$11 million expected 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

Combined AMT refund and additional tax refunds to

drive total cash tax inflow of ~$138 million in 2019

(1)

SWPA Marcellus: Increased Results and Efficiencies

34

Ohio River Water Line (to Richhill)

▪ The buildout is complete 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

▪ Stage spacing was increased ~10% and proppant loading

held constant on 2019 TIL’s

▪ Optimized drawdown continues to be performed with less

production decline once at line pressure for 2019 wells

▪ Lowering capital from stage spacing optimization paired with

increased performance driving well returns higher

(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

0.0

1.0

2.0

3.0

4.0

5.0

- 50 100 150 200 250 300 350 400 450 500

9000' N

orm

aliz

ed C

um

ula

tive (

Bcf)

Days

Richhill (RHL) Marcellus – 2018 vs. Now

2018 RHL TC Current RHL TC 2018 TIL's 2019 TIL's

CPA Dry Utica Results Remain Consistent and Strong

35

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

-

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 P

roduction (

MM

cf)

Days

BP6 AIKENS5J AIKENS5M GAUT4

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

eserv

oir P

ressure

Cumulative Production (MMcf)

BP6 AIKENS5J AIKENS5M GAUT4

Integrating and Optimizing Operations To Drive Efficiencies

36

Objective Functionality Key Results

EBITDAX

Generation

▪ 24/7 real time surveillance

▪ Remote control and

automation

▪ Workforce and logistics

optimization

▪ 99.5% production uptime

▪ ~60% reduction in NPT since 2016

▪ ~30% increase in production since 2016

▪ 79% reduction in well tending unit costs

▪ ~50% reduction in total well tending dollars

since 2016

Capital

Efficiency

▪ Real-time data driven analysis

and decision making

▪ Faster and improved

communication and execution

▪ Drilling and completions risk

mitigation

▪ 11% increase in lateral length

▪ 98% in-zone performance

▪ 6% increase in in-zone performance

▪ Longest Marcellus lateral, 19,609’, geosteered

from IRTOC, 100% in target

▪ Expect to further improve completions pump

efficiencies and reduce D&C NPT

Integrated Real-Time Operations Center

230.1

6.4 25.9

3.1 8.8

184.9

1.0 +1.7

186.6

-

50.0

100.0

150.0

200.0

250.0

S/O 3Q17E Repurchased2017

Repurchased2018

Repurchased1Q19

Repurchased2Q19

Repurchased3Q19

Comp SharesIssued

S/O10/7/2019

Sh

are

s (

mill

ions)

Debt Discipline and EBITDAX Growth Drive Available Capacity

37

(1) See non-GAAP reconciliation table below.

Stand-Alone Midstream

Stand-Alone and Consolidated Net Debt

$ in millions September 30, 2019

Total

Total Long-Term Debt (GAAP) $2,000.3 $639.9 $2,640.2

Less: Cash and Cash Equivalents $2.8 $2.6 $5.5

Net Debt (Non-GAAP)(1) $1,997.5 $637.3 $2,634.8

Q3 2019 Stand-Alone Net Debt /

TTM Stand-Alone Adjusted EBITDAX + Distributions2.4x

Shares Repurchased Since Program Announced

▪ Retired ~1.0 million shares in Q3 2019

▪ Retired approximately 19% of shares outstanding since inception

▪ Remaining authorization outstanding for ~$148 million with no

expiration date

TTM Adjusted Stand-Alone EBITDAX + Distributions(1) $828.0

YE2018 Type Curve Area and Acreage Update

Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019.

38

TYPE CURVE AREAS

SWPA Central Greater TOTAL SWPA

Total Net Acres 98,100 33,700 131,800

Net Developed Acres 28,300 2,400 30,800

Net Undeveloped Locations 427 191

Average Lateral Length (ft) 9,500 9,500

Inter-Lateral Spacing (ft) 750 750

WV SHR/PENS East TOTAL WV

Total Net Acres 17,200 14,300 93,400

Net Developed Acres 6,700 - 6,700




CPA South North TOTAL CPA

Total Net Acres 103,300 95,300 301,100

Net Developed Acres 5,100 900 6,100




OH TOTAL OH

Total Net Acres 12,800

Net Developed Acres 200

Net Undeveloped Locations

Average Lateral Length (ft)

Inter-Lateral Spacing (ft)

COMPANY Total Net Acres 539,000

YE2018 Acreage and Undeveloped Location Update

Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019.

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.39

MARCELLUS UTICATYPE CURVE AREAS

SWPA Central Greater TOTAL SWPA

Total Net Acres 120,500 55,100 175,600

Net Developed Acres 300 - 300



Inter-Lateral Spacing (ft) 1,200 1,200

WV SHR/PENS East TOTAL WV

Total Net Acres 14,100 83,900 134,500

Net Developed Acres - - -




CPA South North TOTAL CPA

Total Net Acres 104,900 95,200 239,600

Net Developed Acres 400 200 600




OH Dry TOTAL OH

Total Net Acres 13,800 77,600

Net Developed Acres 10,000 10,000

Net Undeveloped Locations 14

Average Lateral Length (ft) 9,000

Inter-Lateral Spacing (ft) 1,350

COMPANY Total Net Acres 627,000

($ in millions)

Q3 2019

E&P

Standalone +

CNX

Gathering(2)

= CNX + MLP(2)

=

Total

Consolidated

Cash from Operations $254.4 $1.1 $255.5 $49.9 $305.4

Capital Expenditures $267.7 $4.5 $272.2 $63.9 $336.1

Non-GAAP Reconciliation

40

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 Q3 2019 was 98.0%

and 2.0%, respectively. Consolidated cash flow from operations for CNX Midstream for Q3 2019 was $51.0 million.

Cash from Operations and Capital Expenditures by Segment

Three Months Ended

September 30,

2019 2018 2019 2018

($ in thousands)Stand-alone

(1)Stand-alone

(1) Total Company Total Company

Net Income from EBITDAX Reconciliation $102,219 $115,583 $143,960 $146,756

Adjustments

Total Pre-tax Adjustments from EBITDAX Reconciliation (153,856) (123,395) (153,092) (122,889)

Tax Effect of Adjustments 40,464 33,465 40,263 33,328

Adjusted Net (Loss) Income ($11,173) $25,653 $31,131 $57,195

Three Months Ended

September 30,


(1) Midstream Total Company

Total Long-Term Debt (GAAP) $2,000,309 $639,925 $2,640,234

Less Cash and Cash Equivalents 2,847 2,637 $5,484

Net Debt (Non-GAAP) $1,997,462 $637,288 $2,634,750


41

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

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$

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$

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$

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$

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$

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$

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$

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$

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$


42



Twelve Months Ended

September 30,

2019 2019 2019



Net Income $243,371 $158,047 $401,418

Interest Expense 118,153 29,397 147,550

Interest Income (1,870) - (1,870)

Income Tax Expense 54,421 - 54,421

Earnings Before Interest & Taxes (EBIT) 414,075 187,444 601,519

Depreciation, Depletion & Amortization 471,933 32,770 504,703

Exploration Expense 17,533 - 17,533

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $903,541 $220,214 $1,123,755

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (177,060) - (177,060)

(Gain) Loss on Certain Asset Sales and Abandonments (3,569) 7,229 3,660

Severance Expense 2,690 436 3,126

Stock-Based Compensation 39,919 2,116 42,035

Loss on Debt Extinguishment 7,299 - 7,299

Shaw Event 4,305 - 4,305

Total Pre-tax Adjustments ($126,416) $9,781 ($116,635)

Adjusted EBITDAX Consolidated $777,125 $229,995 $1,007,120

Midstream Distributions 50,869 N/A N/A

Stand-alone EBITDAX + Distributions $827,994 N/A N/A


43



Three Months Ended

September 30,

2019 2019 2019



Net Income $102,219 $41,741 $143,960


Interest Income (1,078) - (1,078)





Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $298,740 $57,983 $356,723

Adjustments:


Stock-Based Compensation 1,453 328 1,781

Severance Expense 1,563 436 1,999

Total Pre-tax Adjustments ($153,856) $764 ($153,092)

Adjusted EBITDAX Consolidated $144,884 $58,747 $203,631




44



Three Months Ended

September 30,

2018 2018 2018



Net Income $115,583 $31,173 $146,756


Interest Income (42) - (42)






Adjustments:


Litigation Settlements 2,000 - 2,000

Gain on Certain Asset Sales and Abandonments (130,849) - (130,849)

Severance Expense 513 - 513

Loss on Debt Extinguishment 15,385 - 15,385







45



Three Months Ended

June 30,

2019 2019 2019



Net Income $148,281 $44,413 $192,694


Interest Income (71) - (71)






Adjustments:


Severance Expense 1,182 - 1,182

Loss on Debt Extinguishment 77 - 77







46


Three Months Ended Twelve Months Ended

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

($ in thousands) 2018 2018 2018 2018 2018

Net Income $510,012 $33,614 $115,583 $90,106 $749,315

Interest Expense 36,062 31,320 28,467 26,471 122,320

Interest Income (76) - (42) 1 (117)

Income Tax Expense (Benefit) 213,694 (31,102) 56,678 (23,713) 215,557

Earnings Before Interest & Taxes (EBIT) 759,692 33,832 200,686 92,865 1,087,075

Depreciation, Depletion & Amortization 115,866 111,125 111,844 122,314 461,149

Exploration Expense 2,380 3,699 3,321 2,633 12,033 -

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $877,938 $148,656 $315,851 $217,812 $1,560,257

Adjustments:

Unrealized (Gain) Loss on Commodity Derivative Instruments (52,078) (8,976) (15,181) 36,727 (39,508)

Litigation Settlements - - 2,000 - 2,000

Impairment of Other Intangible Assets - 18,650 - - 18,650

(Gain) Loss on Certain Asset Sales and Abandonments (4,750) - (130,849) 96 (135,503)

Gain on Previously Held Equity Interest (623,663) - - - (623,663)

Severance Expense 749 - 513 (55) 1,207

Put Option Fair Value - Reversal from Prior Year (3,500) - - - (3,500)

Other Transaction Fees 1,149 257 - - 1,406

Loss (Gain) on Debt Extinguishment 15,635 23,413 15,385 (315) 54,118

Stock-Based Compensation 4,331 5,017 4,737 4,842 18,927

Total Pre-tax Adjustments ($662,127) $38,361 ($123,395) $41,295 ($705,866)

Adjusted EBITDAX Consolidated $215,811 $187,017 $192,456 $259,107 $854,391

Midstream Distributions 8,362 9,088 10,078 11,085 38,613

Stand-alone EBITDAX + Distributions $224,173 $196,105 $202,534 $270,192 $893,004

Stand-alone(1)


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Attributable to CNX Shareholders Three Months EndedTwelve Months

Ended

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

($ in thousands) 2017 2017 2017 2017 2017

Net (Loss) Income ($38,966) $169,511 ($26,441) $276,643 $380,747

Less: (Income) Loss from Discontinued Operations ($52,041) ($47,703) $4,645 $9,391 (85,708)

Add: Interest Expense 41,606 40,682 38,836 40,319 161,443

Less: Interest Income (953) (6,076) (858) (1,198) (9,085)

Add: Income Taxes (47,422) 57,958 10,530 71,566 92,632

Add: Income Tax Reform - - - (269,090) (269,090)

Earnings Before Interest & Taxes (EBIT) from Continuing Operations (97,776) 214,372 26,712 127,631 270,939

Add: Depreciation, Depletion & Amortization 95,678 91,639 102,012 122,707 412,036

Add: Exploration Expense 9,785 19,717 4,479 14,093 48,074

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) from Continuing

Operations $7,687 $325,728 $133,203 $264,431 $731,049

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (24,640) (116,073) (1,512) (105,879) (248,104)

Settlement Expense - - - 19,787 19,787

Gain on Certain Asset Sales - (126,707) (30,315) - (157,022)

Severance Expense 230 73 914 177 1,394

Fair Value Put Option - - - 3,500 3,500

Stock Based Compensation 3,754 4,163 5,159 3,907 16,983

(Gain) Loss on Debt Extinguishment (822) 36 2,019 896 2,129

Impairment of E&P Properties 137,865 - - - 137,865

Total Pre-tax Adjustments $116,387 ($238,508) ($23,735) ($77,612) ($223,468)

Adjusted EBITDAX from Continuing Operations $124,074 $87,220 $109,468 $186,819 $507,581

Earnings Results - CNX Resources...

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