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Earnings ResultsFourth Quarter 2018

January 31, 2019

Cautionary Language

2

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, 2017 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 and EBITDAX for fiscal or quarterly periods in 2019-2022, for CNX or CNXM, CNX

Resources 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 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.

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

Executive Summary

3

Q4 2018 EXPECTATION

STRATEGIC INITIATIVE

2018 Production &

EBITDAX per Share Growth(1)

▪ Q4 2018 Consolidated Adjusted EBITDAX Per Share(2)

increased 90% year-over-year

▪ Adjusted EBITDAX per share growth remains an output of

prudent capital allocation

Balance Sheet &

Leverage Ratio(1)

▪ Ended year at 2.25x attributable net debt / TTM

attributable adjusted EBITDAX or below the stated 2.5x

target

▪ Leverage will continue to be evaluated on a number of

bases in order to fully evaluate the health of the balance

sheet and capacity to buy back shares as well as invest in

incremental activity and M&A opportunities

Share Repurchases

▪ Repurchased an additional 6.8 million shares from the

beginning of the quarter through January 18, 2019

bringing the total number of retired shares to 32.6 million

since the program began in Q4 2017

▪ Share repurchases remain a major part of the strategy and

will be executed opportunistically through 2019 and into

2020

Operational Execution

▪ Production of 136 Bcfe in Q4 2018 resulted in 507 Bcfe

produced for the full year

▪ Many operational successes in 2018 headlined by

outperformance in SWPA Marcellus and CPA Utica

▪ Majority of development plan for 2019 remains in SWPA

Marcellus while SWPA and CPA Utica wells continue to be

studied

2019 Guidance Update▪ Updated 2019 guidance includes minimum production of

495-515 Bcfe and D&C capital of $575-$625 million

▪ Pro forma minimum production growth of 3-7%

▪ 2019 capital guidance supports base development activity;

incremental activity will depend on factors such as CNX

share price, forward strip pricing, Utica data set, and

supply/demand indicators

▪ Guidance updates will be made accordingly through the year

Commitment to the Strategy

▪ The CNX philosophy and strategy drove the 14%

reduction in shares since October 2017 while drastically

reducing leverage and growing operational scale

▪ Grew EBITDAX year-over-year despite divestitures

▪ Capital allocation through a rate of returns focus continues

to be the strategy; share repurchases remain a priority along

with growing balance sheet capacity through disciplined

production and EBITDAX growth

CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected net income, the most comparable financial measure calculated in

accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

(1) See non-GAAP reconciliation table below.

(2) When using shares outstanding as of January 18, 2019.

Steadfast in Philosophy

4

PHILOSOPHYMaximize

the

long-term

per share

value

of the firm

through

prudent

capital

allocation

and

continuous

cost

management

Risk-adjusted returns set basis for all capital allocation decisions

RETURNS

Flexibility in development plans and capital deployment drive optionality

FLEXIBILITY

Hedging and minimal commitments reduce risk

HEDGING

Substantial share repurchases compound per share value

REPURCHASES

Confident in Strategy

5

MINIMUM BASE OF ACTIVITY

INCREMENTAL ACTIVITY

EBITDAX GROWTH

BALANCE SHEET CAPACITY

SHARE COUNT REDUCTION

HEDGE BOOK

LOW COST

STRUCTURE

PLAN RISK

MITIGATION

NAV/SHARE GROWTH

Strategy

designed to

work

through the

cycle and

does so at

strip pricing

in all

periods

STRONG

MARGINS

MINIMAL

COMMITMENTS

HIGH RATES OF

RETURN

PLAN

FLEXIBILITY

BASED ON

REAL-TIME

DECISIONS

This process, which grew

EBITDAX and reduced

shares through 2018, is

primed to be deployed in

2019 and beyond

The Strategy Drives Significant EBTIDAX per Share Growth

Note: Calculated as Adjusted EBITDAX divided by period end shares outstanding as disclosed in SEC filings.

6

$0.54

$0.45 $0.48

$0.83

$1.08

$0.96

$1.03

$1.41

$-

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018

Per Share Adjusted EBITDAX Attributable to CNX Resources Shareholders

Q1 2017 – Q4 2018

Q4 2018 Summary

($ in millions, except per share data) 4Q 2018 4Q 2017 Y/Y Units Y/Y - % 4Q 2018 3Q 2018 Q/Q Units Q/Q - %

Revenue and Other Income from Continuing Operations $435 $477 ($42) -9% $435 $397 $38 10%

Consolidated Adjusted Net Income / (Loss)(1)

$160 $217 ($57) -26% $160 $57 $103 181%

Consolidated Adjusted EBITDAX(1)

$314 $187 $127 68% $314 $239 $75 31%

Consolidated Adjusted EBITDAX(1)

Per Share $1.58 $0.83 $0.75 90% $1.58 $1.12 $0.46 41%

Shares Outstanding at Period End (millions) 198.3 223.8 (25.5) -11% 198.3 203.6 (5.3) -3%

Q4 2018 Financial Results Summary

7

Note: The terms “Consolidated adjusted EBITDAX,” “Adjusted EBITDAX attributable to CNX Resources Shareholders,” “Consolidated adjusted EBITDAX per share,” and

“adjusted net income“ are non-GAAP financial measures, which are reconciled to the GAAP net income below.


(2) When using shares outstanding as of January 18, 2019.

Q4 2018

Consolidated Adjusted EBITDAX

Per Share(2) increased

90%year-over-year

Net Income and Adjusted EBITDAX

▪ Consolidated net income of $129 million in the 2018 fourth quarter; consolidated

adjusted net income of $160 million(1); adjusted net income excludes the following pre-

tax items:

- $37 million unrealized loss on commodity derivative instruments

- $5 million in other miscellaneous items

▪ Consolidated Adjusted EBITDAX in the fourth quarter of $314 million or $1.58

outstanding per share(1)(2); Adjusted EBITDAX attributable to CNX Resources

Shareholders was $279 million(1) in the fourth quarter

(2) (2)

$1.69 $1.65 $1.59 $1.46

$1.31 $1.22

$1.33

$1.63

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2018 Q2 2018 Q3 2018 Q4 2018

$/M

cfe

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

$1.21 $1.09 $1.04 $1.00

$1.79 $1.78 $1.88

$2.09

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2018 Q2 2018 Q3 2018 Q4 2018

$/M

cfe

Total Production Cash Costs Total Production Cash Margin

E&P Standalone Costs and Margins Drive Rates of Return

8

Production Cash Costs(1) and Margins FY2018

Margin 58% 61% 64% 68%

CNX has the lowest per unit cash

production costs of all southwest

Marcellus operators driven largely

by low Transportation, Gathering

and Compression costs

Fully-Burdened Cash Costs(2) and Margins FY2018

Margin 44% 43% 46% 53%

Low fully-burdened cash costs and

hedged revenues drive rates of

return well above cost of capital

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

reconciliation table below.

(2) 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.

$1.00

$0.46

$0.30

$1.76

$-

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

Q4 2018

SWPA Central Marcellus CapEx per Mcfe

Plus Fully-Burdened Cash Costs

Company-Wide Production Cash Cost

SWPA Central Marcellus Example

Well Capital(1) $8,300,000

EUR (Bcfe/1000’) 2.8

Lateral length 9,500’

Mcfe 26,600,000

Capital Cost/Mcfe ~$0.30

Capital Efficiency Driving Down Total Costs Over Time

9

▪ Current DD&A charges ($0.89/Mcfe in Q4 2018) account for legacy

operations

▪ Based on up-to-date per well capital expenditures and expected type

curves, capital per Mcfe in SWPA Marcellus is currently $0.31

▪ Over time, DD&A charges per Mcfe are expected to decline

significantly as legacy charges roll off and recent capital efficiency is

reflected in company financials

Company Fully-Burdened Cash Costs plus

SWPA Central Marcellus Capex per Mcfe

(1) Based on Company regional type curve and economic inputs as disclosed March 13, 2018.

230.1

6.4 5.8 5.3 8.3

6.8 0.5

198.0

-

50.0

100.0

150.0

200.0

250.0

S/O 3Q17E Repurchased4Q17E

Repurchased1Q18

Repurchased2Q18

Repurchased3Q18

Repurchased4Q18 to1/18/19

Comp SharesIssued

S/O 10/16/2018

Share

s (

mill

ions)

Debt Discipline and EBITDAX Growth Drive Available Capacity

10

(1) Includes current portion.


(3) Calculated by taking an average minority interest percentage of 63.91%.

E&P Midstream

Net Debt Attributable to CNX Shareholders

$ in millions December 31, 2018

Total

Total Debt (GAAP)(1)(2) $1,921.3 $477.2 $2,398.5

Less: Cash and Cash Equivalents $0.8 $16.4 $17.2

Net Debt (Non-GAAP)(2) $1,920.5 $460.8 $2,381.3

Less: Net Debt Attributable to

Noncontrolling Interest(3)- $294.5 $294.5

Net Debt Attributable to

CNX Resources Shareholders$1,920.5 $166.3 $2,086.8

In Q4 2018, CNX redeemed approximately $20 million of

5.875% notes due 2022

At December 31, 2018, the company's credit facility had $612

million of borrowings outstanding and $198 million of letters of

credit outstanding, leaving $1,290 million of unused capacity

Q4 2018 Net Debt / TTM Attributable Adjusted EBITDAX 2.25x

Shares Repurchased Since Program Announced

▪ Completed remainder of initial $450 million share repurchase

authorization

▪ Have deployed ~$490 million since the end of Q3 2017 retiring

almost 14% of shares outstanding

▪ Authorization outstanding for $300 million with no expiration date

▪ Balance sheet capacity, driven by growing EBITDAX, will continue

to expand and contract under the 2.5x leverage ceiling

- As capital allocation decisions arise, all will be analyzed

through the strict NAV/share lens and with future opportunities

in mind as well

TTM Adjusted EBITDAX Attributable to CNX Shareholders (3) $929.1

21%

38%

4%

69%

103%

53%

64%

-14%

Peer Avg 50%

-40%

-20%

0%

20%

40%

60%

80%

100%

120%

140%

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 CNX Peer Avg

Only E&P of the Peer Group to have Reduced Shares Since 2013

Source: Capital IQ.

Notes: Peers include AR, CHK, COG, EQT, GPOR, RRC, and SWN.

11

Peer Share Count Percent Change: YE2013-YE2018

Expect continued substantial share count reduction over next three years

Flexibility in Development Mitigates Risk and Grows NAV/Share

12

MINIMUM BASE

OF ACTIVITY

SUPPORTS

Multiyear:

CNXM Commitments

Service Contracts

Hedge Book

INCREMENTAL

ACTIVITY

Share Repurchases

Equity Price

Forward Strip Pricing

Supply/Demand Indicators

M&A Opportunities

Utica Data Set

RISK-

ADJUSTED

RETURN

ANALYSISDRIVES

Through the Cycle:

Balance Sheet Capacity

NAV/Share Growth

Process occurring on a daily basisIN

CR

EM

EN

TA

L

DIS

CR

ET

ION

AR

Y C

AP

ITA

L

2019 Minimum Guidance Update

CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected net income, the most comparable financial measure calculated in

accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

(1) Expected 5-6% liquids.

(2) Pro forma growth comparing 2019E production with 2018 production from assets not sold of 480 Bcfe.

(3) Forward pricing date as of 1/15/2019.

(4) Includes CNX Midstream LP + GP/IDR distributions of $55 million in FY2019E.

13

2019E

Minimum Capital Expenditures($ millions)

Low High

Drilling & Completions $575 $625

Non-D&C $175 $175

Total E&P Capital $750 $800

CNX Midstream LP Capital $250 $280

Total Consolidated Capital $1,000 $1,080

Minimum Production(Bcfe)

Total Production Volumes (Bcfe)(1) 495 515

Y/Y Growth (2018 pro forma)(2) 3% 7%

Adjusted EBITDAX(3)

($ millions)

E&P Standalone + Distributions(4) $790 $825

Consolidated $945 $985

Capital budget represents a minimum set of D&C activity

Throughout the year, the company will evaluate a series

of factors to determine incremental activity and will

update capital guidance accordingly

Those factors include gas prices, CNX equity prices,

supply/demand indicators, Utica data set, M&A

opportunities, and company appetite for risk

$29

$39

$55

$-

$10

$20

$30

$40

$50

$60

FY 2017 FY 2018 FY 2019E

Dis

trib

utions R

eceiv

ed in E

ach Y

ear

($ m

illio

ns)

LP GP+IDR

LP and GP Distributions Help Grow Balance Sheet Capacity

Note: Distributions received in each respective time period correspond to prior quarter due to delay in declaration and record dates.

14

LP + GP/IDR Distributions FY2017-FY2019E

LP distributions from CNX Midstream

have consistently grown 15% year-

over-year

As growth continues, LP + GP/IDR

distributions make a larger

contribution to CNX’s incremental

available capital and balance sheet

capacity

369.3 424.4

351.5

216.7

101.9

6.7

44.2

58.8

59.9

25.0

0

50

100

150

200

250

300

350

400

450

500

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

15

(2)

Hedge Volumes and Pricing Q1 2019 2019 2020 2021 2022 2023

NYMEX Hedges

Volumes (Bcf) 83.5 359.2 457.2 389.1 262.9 99.3

Average Prices ($/Mcf) $3.07 $3.05 $2.96 $2.91 $2.96 $2.84

Fixed Price Sales and Index Hedges

Volumes (Bcf) 5.2 16.8 11.4 21.2 13.7 27.6


Total Volumes Hedged (Bcf)(1) 88.7 376.0 468.6 410.3 276.6 126.9

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

Volumes (Bcf) 87.1 369.3 424.4 351.5 216.7 101.9


NYMEX Hedges Exposed to Basis

Volumes (Bcf) 1.6 6.7 44.2 58.8 59.9 25.0


Total Volumes Hedged (Bcf)(1) 88.7 376.0 468.6 410.3 276.6 126.9

(1) Hedge positions as of 1/18/2019.

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

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

Layering in hedges out to 2023 to protect

margins on proved developed production

and a portion of PUDs

Fully-covered hedges represent

~88% of 2019E base gas volumes(3)

NYMEX hedges added during Q4:

448.6 Bcf (for 2018 through 2023)

Basis hedges added during Q4:

361.2 Bcf (2018 through 2023)

De-risked pricing for next three

years and meaningful upside

potential

Protecting from in-basin

blowout through regional

basis hedges

Q4 and FY2018 Activity

16

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

(2) 50% working interest. Sale of OH Utica JV assets closed in Q3 2018, at which point flowing production from five TILs transferred to buyer.

Q4 2018 FY2018

TD FRAC TIL

Average

Lateral

Length(1)

HZ Rigs

at Period

End TD FRAC TIL

SWPA

Central

Marcellus 19 12 11 8,316 2 61 43 41

Utica - - - - 1 - 1 1

WV

Shirley-Penns

Marcellus - - - - - 5 5 5

Utica - - - - - - - -

CPA Utica 1 - 1 6,529 1 4 2 2

OH DryUtica

- 2 4 9,306 - 8 8 14

OH Wet(2) - - - - - - 5 5

Total 20 14 16 4 78 64 68

$1.31 $1.22 $1.26 $1.16

$1.21 $1.09

$1.04 $1.00

$-

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

Tota

l C

ash P

roduction C

osts

($

/Mcfe

)

Transportation, Gathering and Compression Lease Operating ExpenseProduction, Ad Valoerm, and Other Fees

Q4 2018 Operational Results Summary

17

▪ Marcellus Shale costs were $1.98 per Mcfe in Q4 2018, a decrease of

$0.34 from $2.32 per Mcfe vs. Q4 2017, or a 15% decline

- Driven by decreases to LOE, transportation, gathering and

compression costs, taxes, and DD&A

▪ Utica Shale costs were $1.43 per Mcfe in Q4 2018, a decrease of

$0.16 from $1.59 per Mcfe in Q4 2017, or a 10% improvement

- Excluding DD&A, Utica production cash costs were just $0.42 per

Mcfe in Q4 2018

- The increase in Utica volumes was more modest than in prior

quarters due to the divestiture of Ohio wet Utica joint venture assets

▪ E&P capital expenditures increased in Q4 2018 to $266 million from

$253 million spent in Q3 2018

(1) Average sales prices for 4Q2018, 4Q2017, and 3Q2018 include (loss) / gain on commodity derivative instruments

(cash settlements) of ($0.56), $0.19, and $0.03 per Mcf, respectively.

(2) Total Production Costs for 4Q2018, 4Q2017, and 3Q2018 include DD&A of $0.89, $1.01, and $0.93 per Mcfe,

respectively.

Cash Production Costs(1) 1Q17-4Q18

($/Mcfe) 4Q 2018 4Q 2017

Y/Y

Change 4Q 2018 3Q 2018

Q/Q

Change

Average Sales Price(1)

$3.09 $2.80 $0.29 $3.09 $2.92 $0.17

Total Production Costs(2)

$1.89 $2.17 ($0.28) $1.89 $1.97 ($0.08)

Sales Volumes (Bcfe) 136.1 118.9 17.2 136.1 119.0 17.1

Sales Volumes by Category (Bcfe)

Marcellus 87.0 64.0 23.1 87.0 70.6 16.4

Utica 34.0 33.8 0.3 34.0 33.6 0.4

CBM 15.0 16.0 (1.0) 15.0 14.7 0.3

Other 0.1 5.1 (5.0) 0.1 0.1 0.0


Production Costs by Segment Show Ongoing Improvement

(1) Excludes Depreciation, Depletion and Amortization.

18

Marcellus Utica CBM & Other TOTAL

4Q18 4Q17 Δ 4Q18 4Q17 Δ 4Q18 4Q17 Δ 4Q18 4Q17 Δ

Production Volumes (Bcfe) 87.0 64.0 23.0 34.0 33.8 0.2 15.1 21.1 (6.0) 136.1 118.9 17.2

Lease Operating Expense 0.09 0.15 (0.06) 0.12 0.16 (0.04) 0.33 0.46 (0.13) 0.12 0.21 (0.09)

Transportation, Gathering and Compression 1.06 1.13 (0.07) 0.23 0.35 (0.12) 0.73 0.90 (0.17) 0.82 0.87 (0.05)

Production, Ad Valorem, and Other Fees 0.05 0.08 (0.03) 0.07 0.05 0.02 0.13 0.11 0.02 0.06 0.08 (0.02)

Depreciation, Depletion and Amortization 0.78 0.96 (0.18) 1.01 1.03 (0.02) 1.23 1.22 0.01 0.89 1.01 (0.12)

Total Production Costs 1.98 2.32 (0.34) 1.43 1.59 (0.16) 2.42 2.69 (0.27) 1.89 2.17 (0.28)

Total Production Cash Costs(1) 1.20 1.36 (0.08) 0.42 0.56 (0.14) 1.19 1.47 (0.28) 1.00 1.16 (0.16)

($/Mcfe)

Marcellus LOE and

Transportation, Gathering and

Compression fees down a

combined 10% year-over-year

Decline in Utica Production

Cash Costs to just $0.42 per

Mcfe helping drive down

company average

CBM Production Cash Costs

declined $0.28 or 19% year-

over-year

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

10,000,000

0 2 4 6 8 10 12 14 16 18 20

Mcf

Months

Peer 1 Type Curve Peer 1 Actuals Peer 2 Type Curve

Peer 2 Actuals CNX Type Curve CNX Actuals

Dry Gas Marcellus Wells Exceeding Expectations and Peers

Note: Peer data from company filings and DrillingInfo.

(1) Solid lines show PA state production data for dry gas wells located in Greene and Washington counties and turned-in-line in 2017 or 2018. Normalized to 9,500’

lateral length.

(2) Dotted lines on graph represent company-stated type curves for dry gas wells.19

Company

EUR

(Bcf/1000’)

Lateral

Length Total EUR

CNX 2.8 9,500 26.6

Peer 1 2.4 9,500 22.8

Peer 2 2.5 9,500 24.0

SWPA Dry Type Curves vs. Greene & Washington County

State Data Actuals: 2017-2018 TILs(1)

Recent CNX dry gas wells

currently outperforming type

curve while peers underperform

expectations on similar wells SWPA Dry Type Curves Normalized to 9,500’

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

0 20 40 60 80 100 120 140 160 180 200

Cum

ula

tive M

cf N

orm

aliz

ed t

o 7

000'

Days

Aikens 5J Aikens 5M

Gaut 4I CPA Dry Utica 3.5 TC

Bell Point 6

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0

5,000

10,000

15,000

20,000

25,000

30,000

Oct-18 Dec-18 Feb-19 Apr-19 Jun-19 Aug-19 Oct-19 Dec-19

Tu

bin

g P

ressu

re (

Psi)

Flo

w R

ate

(M

cf/

d)

Gas Actuals (mcf/d) Gas Forecast Tubing Pressure Actuals

Tubing Pressure Forecast Line Pressure

Expected to cumulatively

produce 9 Bcf at the time it hits

line pressure

CPA Deep Utica Bell Point 6 Producing In-Line with Past Successes

20

Managed Pressure Expectation – 430 Days Flat

Bell Point 6 Performance vs. Existing Mamont Wells

CPA Dry Utica Pads To-Date

Geologic and

fracture

modelling allows

for the

optimization of

landing zone and

completion

designs, which

drive production

repeatability,

maximized IRRs,

and enhanced

capital efficiency

Expected to

produce at flat

rate for

approximately 430

days until hitting

line pressure in

December 2019

Anticipated

managed

pressure

drawdown of ~20

psi/day

Ohio River Waterline to Supply Core SWPA Development

21

New water line to connect core SWPA Central

development area to reliable and continuous water source

▪ In service expected: Q4 2019

▪ Expected throughput: 120 Bbl/min

▪ Project IRR: 40%-50%

▪ Connect to Richhill area and supply vast majority of SWPA

Central pads

▪ Will support deployment of Evolution all electric frac crew

Ohio River Water Line: Planned Route

~70% of CNX

water is transferred

through pipeline

infrastructure

80% cost savings compared to

trucking

Natural gas powered completions instead of diesel saves

~$200,000 per Marcellus lateral or ~$400,000 per Utica lateral

Dual pipeline construction results in

13% total cost reduction, increased

synergies, and lower project risk

Water Infrastructure Benefits

Water pipelines

constructed in

tandem with

gathering system

when appropriate

Construction of gas line with water infrastructure prior to

completion allows crews to use field gas in place of diesel

Appendix

Marketing Highlights and Liquids Realizations

23

(1) Calculation includes the impact of gas hedging cash settlements.

Marketing Highlights

▪ Directly-marketed ethane volumes were 251,400

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

$0.91 per MMBtu premium over CNX’s residue

natural gas alternative.

▪ $0.06 per Mcfe uplift(1) from liquids for total average

realization of $3.09 per Mcfe in Q4 2018

2018 2017

Q4 Q4

NYMEX Natural Gas ($/MMBtu) $3.64 $2.93

Average Differential (0.29) (0.76)

BTU Conversion (MMBtu/Mcf)* 0.24 0.12

(Loss) Gain on Commodity Derivative

Instruments-Cash Settlement(0.56) 0.19

Realized Gas Price per Mcf $3.03 $2.48

* Conversion factor 1.07 1.06

Natural Gas Price Reconciliation

Natural Gas Liquids, Oil and Condensate

▪ Q4 2018 liquids sold: 7.5 Bcfe

▪ Total weighted average price of all liquids decreased 19% to $25.61

per Bbl in Q4 2018 from $31.82 per Bbl in Q4 2017 and decreased

13% from $29.35 per Bbl in Q3 2018

▪ In Q4 2018, liquids comprised approximately 6% of production

volumes and 7% of total revenue and other operating income

Average Price Realization ($ per Bbl)

2018 2017

Q1 Q2 Q3 Q4 FY18 Q1 Q2 Q3 Q4 FY17

NGLs $27.48 $28.38 $28.08 $24.54 $27.30 $29.16 $15.96 $19.32 $30.48 $24.18

Oil $56.46 $58.32 $63.00 $60.54 $59.34 $44.40 $48.18 $41.94 $45.48 $45.36

Condensate $49.32 $56.82 $58.56 $38.34 $50.58 $33.84 $34.14 $41.34 $46.08 $39.54

CY2019 CY2020

Hedged Volumes Hedged Forward Forecasted Gain/(Loss)

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

($/MMBtu)

NYMEX 386,088 $2.83 $3.07 ($0.23) ($90,344)

Basis:

DOM South (DOM) 43,800 ($0.59) ($0.38) ($0.21) ($9,242)

TCO Pool (TCO) 52,360 ($0.35) ($0.31) ($0.04) ($2,095)

Michcon (NMC) 32,263 ($0.20) ($0.18) ($0.02) ($484)

TETCO ELA (TEB) 7,300 ($0.09) ($0.12) $0.03 $212

TETCO WLA (TWB) 7,300 ($0.08) ($0.07) ($0.01) ($102)

TETCO M3 (TMT) 14,813 $0.08 $0.53 ($0.45) ($6,651)

TETCO M2 (BM2) 110,610 ($0.58) ($0.41) ($0.17) ($18,693)

Total Financial Basis Hedges 268,446 ($37,055)

Total Projected Realized Loss ($127,399)

2019E Gas Hedging Gain/Loss Projections

24

Note: Forward market prices, hedged volumes, and hedge prices are as of 1/18/2019. Anticipated hedging activity is not included in projections.

(1) January prices are settled.

(1)

▪ In addition to NYMEX and basis financial

hedges, CNX has physical fixed basis sales and

physical fixed price sales with customers

▪ CY 2019 physical fixed basis sales and physical

fixed price sales: 119.1 Bcf

▪ Physical sales provide additional basis hedge

- Flows through gas sales in financials

Q1 2019 CY2019

Hedged Volumes Hedged Forward Forecasted Gain/(Loss)

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

($/MMBtu)

NYMEX 89,775 $2.86 $3.45 ($0.60) ($53,685)

Basis:

DOM South (DOM) 10,800 ($0.59) ($0.27) ($0.32) ($3,489)

TCO Pool (TCO) 10,800 ($0.33) ($0.23) ($0.10) ($1,026)

Michcon (NMC) 6,975 ($0.18) ($0.11) ($0.07) ($453)

TETCO ELA (TEB) 1,800 ($0.09) ($0.12) $0.03 $61

TETCO WLA (TWB) 1,800 ($0.08) ($0.09) $0.01 $13

TETCO M3 (TMT) 3,275 $0.89 $2.61 ($1.72) ($5,633)

TETCO M2 (BM2) 25,200 ($0.57) ($0.28) ($0.29) ($7,283)

Total Financial Basis Hedges 60,650 ($17,810)

Total Projected Realized Loss ($71,495)

Q1 2019E Gas Hedging Gain/Loss Projections

25

Note: Forward market prices, hedged volumes, and hedge prices are as of 1/18/2019. Anticipated hedging activity is not included in projections.

(1) January prices are settled.

(1)

Non-GAAP Reconciliation

26

Source: Company filings.

(1) CNX's unallocated expenses include other expense, gain on sale of assets, loss on debt extinguishment and income taxes.

(2) Adjusted EBITDA Attributable to Noncontrolling Interest for the three months ended December 31, 2018 is Net Income Attributable to Noncontrolling interest of $27,488 plus Depreciation,

Depletion and Amortization of $3,189, plus Interest Expense of $3,480, plus Stock-based compensation of $393. Calculated by taking an average noncontrolling interest percentage of

63.91%.

Adjusted net income consolidated for the three months ended December 31, 2018 is calculated as GAAP net income of $129,415 plus total pre-tax adjustments from the above table of

$41,931, less the associated tax expense of $11,371 equals adjusted net income of $159,975. Adjusted net income consolidated for the three months ended December 31, 2017 is calculated

as GAAP net income of $276,643 less total pre-tax adjustments from the above table of $77,612, plus the associated tax benefit of $17,850 equals the adjusted net income of $216,881.

Adjusted net income consolidated for the three months ended September 30, 2018 is calculated as GAAP net income of $146,756 less total pre-tax adjustments from the above table of

$122,887, plus the associated tax expense of $33,328 equals adjusted net income of $57,197.

Three Months Ended

December 31,

2018 2018 2018 2018 2017

($ in thousands)

E&P

DivisionMidstream Unallocated

(1) Total

Company

Total

Company

Net Income (Loss) $48,250 $39,309 $41,856 $129,415 $276,643

Less: Income from Discontinued Operations - - - - 9,391

Add: Interest Expense 26,471 6,751 - 33,222 40,319

Less: Interest Income 1 - - 1 (1,198)

Add: Income Taxes - - (23,713) (23,713) 71,566

Add: Tax Reform Benefit - - - - (269,060)

Earnings Before Interest & Taxes (EBIT) 74,722 46,060 18,143 138,925 127,661

Add: Depreciation, Depletion & Amortization 122,315 7,770 (1) 130,084 122,707

Add: Exploration Expense 2,633 - - 2,633 14,093

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

Continuing Operations $199,670 $53,830 $18,142 $271,642 $264,461

Adjustments:

Unrealized Gain (Loss) on Commodity Derivative Instruments 36,727 - - 36,727 (105,879)

Loss on Certain Asset Sales - - 96 96 -

Severance Expense (55) - - (55) 177

(Gain) Loss on Debt Extinguishment - - (315) (315) 896

Stock-Based Compensation 4,842 636 - 5,478 3,907

Fair Value Put Option - - - - 3,500

Settlement Expense - - - - 19,787

Total Pre-tax Adjustments $41,514 $636 ($219) $41,931 ($77,612)

Adjusted EBITDAX from Continuing Operations $241,184 $54,466 $17,923 $313,573 $186,849

Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2)

- 34,550 - 34,550 -

Adjusted EBITDAX Attributable to CNX Resources Shareholders $241,184 $19,916 $17,923 $279,023 $186,849

27

“Attributable Share” Reconciled to Consolidated Results

Note: Tables may not foot due to rounding.

(1) CNX's unallocated expenses include other expense, gain on sale of assets, loss on debt extinguishment, and income taxes.

(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 2018 was 98.8% and 1.2%, respectively. Consolidated cash flow from operations for CNX Midstream for Q4 2018 was $48.9 million.

Cash from Operations and Capital Expenditures

CNX LP ownership 34.09%

GP ownership 2.00%

Total CNX ownership 36.09%

NCI 63.91%

100.00%

Attributable Portion Calculation

Q4 2018

E&P

Standalone +

CNX

Gathering(2)

= CNX + MLP(2)

=

Total

Consolidated

Cash from Operations $146.7 $0.6 $147.3 $48.3 $195.6

Capital Expenditures $264.3 $1.8 $266.1 $56.2 $322.3

($ in millions)

Attributable to CNX Shareholders + Noncontrolling Interest = Consolidated

Inside the MLP Outside the MLP 63.91% of CNXM

Q4 2018

E&P

Standalone +

Attributable to

CNXM LP & GP + Unallocated(1)

+ CNX Gathering =

Total "Attributable to

CNX Shareholders" +

Attributable to

Noncontrolling Interest =

Total

Consolidated

Adj. EBITDAX $241.2 $12.7 $17.9 $7.2 $279.0 $34.6 $313.6

Total Debt $1,921.3 $172.2 -- $2,093.5 $305.0 $2,398.5

Total Cash $0.8 $5.9 $6.7 $10.5 $17.2

Net Debt $1,920.5 $166.3 $2,086.8 $294.5 $2,381.3

($ in millions)


28


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) 2018 2018 2018 2018 2018

Net Income $545,546 $61,394 $146,756 $129,415 $883,111

Add: Interest Expense 38,551 38,438 35,723 33,222 145,934

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

Add: Income Taxes 213,694 (31,102) 56,678 (23,713) 215,557

Earnings Before Interest & Taxes (EBIT) from Continuing Operations 797,715 68,730 239,115 138,925 1,244,485

Add: Depreciation, Depletion & Amortization 124,667 119,087 119,585 130,084 493,423

Add: Exploration Expense 2,380 3,699 3,321 2,633 12,033

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

Continuing Operations $924,762 $191,516 $362,021 $271,642 $1,749,941

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (52,078) (8,975) (15,181) 36,727 (39,507)

Settlement Expense - - 2,000 - 2,000

(Gain) Loss on Certain Asset Sales (9,487) - (130,849) 96 (140,240)

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

Severance Expense 814 257 513 (55) 1,529

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

Other Transaction Fees 1,149 - - - 1,149

Stock Based Compensation 4,909 5,709 5,245 5,478 21,341

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

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

Total Pre-tax Adjustments ($666,221) $39,054 ($122,887) $41,931 ($708,123)

Adjusted EBITDAX from Continuing Operations $258,541 $230,570 $239,134 $313,573 $1,041,818

Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2)

22,388 $26,711 $29,083 $34,550 $112,732

Adjusted EBITDAX Attributable to CNX Resources Shareholders $236,153 $203,859 $210,051 $279,023 $929,086


29


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) 2017 2017 2017 2017 2017

Net Income ($38,965) $169,510 ($26,441) $276,643 $380,747

Less: Loss (Income) from Discontinued Operations ($36,269) ($47,126) ($7,813) $5,500 (85,708)

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

Less: Interest Income (952) (6,077) (858) (1,198) (9,085)

Add: Income Taxes (63,194) 57,381 22,988 75,427 92,602

Add: Income Tax Reform - - - (269,060) (269,060)

Earnings Before Interest & Taxes (EBIT) from Continuing Operations (97,774) 214,370 26,712 127,631 270,939

Add: Depreciation, Depletion & Amortization 95,677 91,640 102,012 122,707 412,036

Add: Exploration Expense 9,787 19,715 4,479 14,093 48,074

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

Continuing Operations $7,690 $325,725 $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

Lease Expirations - 16,861 - - 16,861

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 ($221,647) ($23,735) ($77,612) ($206,607)

Adjusted EBITDAX from Continuing Operations $124,077 $104,078 $109,468 $186,819 $524,442


30

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

Average Sales Price - Total Company 2.85$ 2.47$ 2.50$ $ 2.80 3.00$ 2.87$ 2.92$ $ 3.09

Lease Operating Expense 0.23$ 0.23$ 0.22$ 0.21$ 0.28$ 0.21$ 0.14$ 0.12$

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

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

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

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

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

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

Operating Cash Margin 1.54$ 1.25$ 1.24$ 1.64$ 1.79$ 1.78$ 1.88$ 2.09$

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