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Earnings ResultsFirst Quarter 2018

May 3, 2018

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; our operational relationship with other parties, including midstream facilities; operational risks relating to pipeline

systems, drilling natural gas wells, 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, 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 2018-2022, 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. 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

Q1 2018 EXPECTATION

STRATEGIC INITIATIVE

Operational Execution▪ Total production in the quarter of 129.5 Bcfe or average of

1.439 Bcfe/d exceeded YE2017 average monthly exit rate

of 1.390 Bcfe/d

▪ Reaffirming production guidance of 520-525 Bcfe for

FY2018

Stacked Pay Development▪ Turned-in-line RHL11E deep dry Utica well with positive

early results

▪ Transferring completion design and spacing lessons from

Monroe County and Green Hill to Richhill stacked pay

Share Repurchases ▪ Bought back ~$200 million of common stock since Oct. ‘17▪ Approximately $250 million remaining on outstanding

repurchase authorization through 3Q18

Debt Repayment ▪ Payed down ~$391 million in debt in the period ▪ Continue to target steady state 2.5x net debt/EBITDAX

CNX Midstream Integration

and Shirley-Penns Drop

▪ Closed GP transaction in early January and rebranded as

CNX Midstream; closed Shirley-Pennsboro asset drop for

$265 million helping to pay for a large portion of the cost of

the GP

▪ Fully aligned management teams with a clear

development plan and well commitments sets the stage

for steady and prolonged distribution growth

SOG and Other Asset Sales▪ Sold SOG assets for ~$88 million in cash proceeds; sold an

additional ~$14 million in scattered acreage and other

miscellaneous assets

▪ Further focuses development activity on top-tier

Marcellus and Utica assets; reduces legacy liabilities and

cash servicing costs to de minimis levels

HG Exchange Transaction

▪ On May 2, 2018, executed a transaction with HG Energy II;

CNX received 11,400 DevCo I Marcellus acres and $5

million in cash in exchange for 95% interest in DevCo II

midstream assets and scattered acres in DevCo III; CNXM

received additional well commitments from both parties

▪ Transaction and revised GGA results in further de-risked

15% distribution growth based on minimum well

commitments alone

SOG Sale Drives Continued Reduction in Legacy Liabilities

(1) Excludes wells located in the Murray and CONSOL Energy development area.

4

Conventional Shallow Oil and Gas (SOG) assets sold in

West Virginia and Pennsylvania, including CBM(1)

▪ Agreement signed mid-February

- Closed on March 30, 2018

▪ ~11,000 wells

▪ Cash proceeds of $88 million

▪ Buyer assumed liabilities of ~$200 million

- Primarily asset retirement obligations

▪ Associated annual production of ~20 Bcfe

SOG Wells Included in Sale

-

50

100

150

200

250

2017 2018E 2019E 2020E 2021E 2022E

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

Sh

are

s O

uts

tan

din

g (

mill

ion

s)

Ma

rket C

ap

($

in m

illio

ns)

Market Cap

Shares Outstanding - Including Drop Proceeds

Shares Outstanding - No Additional Sales/Drops

Share Buybacks To-Date and Potential Capacity

5

Share Reduction230.1 million 223.7 million

Additional

85+ million share

reduction(2)

Q3 2017 End Year-End 20172018E-2022E

Buyback PotentialAs of:

S/O: 217.9 million

As of 4/20/2018

Potential share count reduction of ~60%

by year-end 2022 including additional drop proceeds

▪ Prior to spin (~$100 million):

- 6.4 million shares repurchased at a volume

weighted average price of $16.08(3)

▪ Since spin (~$100 million):

- 6.7 million shares repurchased at a volume

weighted average price of $14.61(4)

▪ Approximately $250 million remaining on share

repurchase authorization for 2018

(1) Stock repurchase price assumes static year-forward EV/EBITDAX multiple of 5.9x on guided adjusted EBITDAX and net debt levels. Market cap estimate includes

deployment of ~$1.8 billion related to potential drop proceeds and tax refunds. See CNX Analyst Day materials dated March 13, 2018 for full details.

(2) Not including deployment of ~$1.8 billion of potential drop proceeds and tax refunds.

(3) Shares repurchased from October-November 2017. Included rights to CEIX share distribution at a ratio of 1 share of CEIX for every 8 shares held of CNX.

(4) Shares repurchased as of market close 4/20/2018.

~$110/share

with drop

proceeds(1)

0

50

100

150

200

250

300

350

400

450

500

Entering 2018 2018 2019 2020 Year End 2020

Exchange Agreement Expands SWPA Central Marcellus Inventory

6

Prior

Net SWPA

Central

Marcellus

Inventory

391Prior

Net SWPA

Central

Marcellus

Inventory

217

Additional

Locations from

HG Exchange

70

TILs 46

TILs 55

TILs 73

Additional

Locations from

HG Exchange

70

SWPA Central Marcellus Inventory 2018E-2020E

SWPA Central Marcellus

locations remaining at

YE2020 based on current

development schedule287

Increase in remaining

SWPA Central Marcellus

locations due to Asset

Exchange Agreement 32%

461SWPA Central Marcellus

locations entering 2018

7

“Attributable Share” Reconciled to Consolidated Results

(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

as of Q1 2018 was 85.6% and 14.4%, respectively. Consolidated cash flow from operations for CNX Midstream for Q1 2018 was $42.258 million.

Attributable to CNX Shareholders + Noncontrolling Interest = Consolidated

Inside the MLP Outside the MLP 63.91% of CNXM

Q1 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 $208 $13 $8 $8 $236 $22 $259

Total Debt $1,824 $149 -- $1,973 $264 $2,237

Total Cash $77 $2 $79 $4 $82

Net Debt $1,747 $147 $1,894 $260 $2,155

($ in millions)

Q1 2018

E&P

Standalone +

CNX

Gathering(2)

= CNX + MLP(2)

=

Total

Consolidated

Cash from Operations $217 $6 $223 $36 $259

Capital Expenditure $216 $2 $218 $14 $232

($ in millions)

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

Q1 2018 Results

8

Note: The terms “adjusted net income attributable to CNX Shareholders”, “adjusted EBITDA attributable to CNX Shareholders”, and “adjusted EBITDAX from continuing

operations" are non-GAAP financial measures, which are reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation."

(1) Income tax effect of Total Pre-tax Adjustments (excluding exploration expense) was ($180,679) for the three months ended March 31, 2018. Adjusted net income

attributable to CNX Resources Shareholders for the three months ended March 31, 2018 is calculated as GAAP net income attributable to CNX Shareholders of

$527,563 less total pre-tax adjustments of ($666,221), plus the associated tax expense of ($180,679) equals the adjusted net income attributable to CNX Resources

Shareholders of $42,021.

Q1 2018 Summary

($ in millions, except per share data) 1Q 2018 1Q 2017

Y/Y

Change 1Q 2018 4Q 2017

Q/Q

Change

Adjusted Net Income / (Loss) Attributable to CNX Shareholders $42 $37 $5 $42 $222 ($180)

Adjusted Earnings / (Loss) Per Share $0.19 $0.16 $0.03 $0.19 $0.98 ($0.79)

Revenue and Other Income from Continuing Operations $496 $320 $176 $496 $477 $19

Adjusted EBITDAX Attributable to CNX Shareholders $236 $124 $112 $236 $187 $49

Adjusted EBITDAX attributable

to CNX Shareholders increased

90%compared to Q1 2017

Net Income and Adjusted EBITDAX

▪ On a GAAP basis, net income attributable to CNX shareholders of $528 million in the 2018 first quarter or $2.35 per diluted share; adjusted net income attributable to CNX shareholders of $42 million, or $0.19 per diluted share(1); adjusted net income excludes the following pre-tax items:

- $624 million gain on company’s previously held equity interest in CNX Gathering in connection with acquisition of 50% of GP

- $52 million unrealized gain on commodity derivative instruments

- $9 million in gains on certain asset sales

▪ Total company adjusted EBITDAX attributable to CNX Shareholders in the first quarter of $236 million; on a consolidated basis, adjusted EBITDAX from continuing operations was $259 million in the first quarter

Balance Sheet and Hedge Book Drive Capacity to Retire Shares

9

(1) Includes current portion.

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

Total Debt (GAAP)(1)

E&P MidstreamNet Debt Attributable to CNX Shareholders

Less: Cash and Cash Equivalents

Net Debt (Non-GAAP)

Net Debt Attributable to CNX Resources Shareholders

$1,824 $413

$77 $6

$1,747 $407

$ in millions

Less: Net Debt Attributable to Noncontrolling Interest(2)

March 31, 2018

Total

$2,237

$83

$2,154

- $261 $261

$1,747 $147 $1,894

Target

<2.5x net debt

/ EBITDAX

During the quarter, CNX purchased $391 million of its

outstanding 5.875% senior notes due in April 2022

374.5

312.8

205.6 194.6

112.0

23.0

29.3

56.0

0

50

100

150

200

250

300

350

400

2018 2019 2020 2021 2022

Gas V

olu

mes H

edged (

Bcf)

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

Marketing: Natural Gas Hedging and Basis Protection

10

▪ Systematically layering in

hedges out to 2022 to protect

margins on proved developed

production and a portion of

PUDs (capex)

▪ Locking-in revenue and de-

risking capital decisions by

matching NYMEX and basis

hedge volumes

▪ Protecting from in-basin blowout

through regional basis hedges

▪ Approximately 81% of total

2018E gas volumes hedged(3)

▪ NYMEX hedges added during

Q1: 167.5 Bcf (2019-2022)

▪ Basis hedges added during Q1:

193.2 Bcf (2018-2022)

(1) Hedge positions as of 4/23/2018. Q2 2018, 2018, and 2021 exclude 2.3 Bcf, 14.2 Bcf, and 4.0 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) Based on midpoint of total gas production guidance of 450-475 Bcf in 2018E.

(2)

Hedge Volumes and Pricing Q2 2018 2018 2019 2020 2021 2022

NYMEX Hedges

Volumes (Bcf) 89.5 357.2 323.0 223.9 173.3 154.2

Average Prices ($/Mcf) $3.13 $3.15 $3.03 $3.09 $3.01 $3.05

Physical Fixed Price Sales

Volumes (Bcf) 4.3 17.3 12.8 11.0 21.3 13.8


Total Volumes Hedged (Bcf)(1) 93.8 374.5 335.8 234.9 194.6 168.0

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

Volumes (Bcf) 93.8 374.5 312.8 205.6 194.6 112.0


NYMEX Hedges Exposed to Basis

Volumes (Bcf) - - 23.0 29.3 - 56.0

Average Prices ($/Mcf) - - $3.03 $3.09 - $3.05

Total Volumes Hedged (Bcf)(1) 93.8 374.5 335.8 234.9 194.6 168.0

Financial Guidance: 2018E

11

2018E

Revenue and Other Operating Income E&P Consolidated

Production Volumes:

Natural Gas (Bcf) 450-475

NGLs (MBbls) 7,500-7,700

Oil (MBbls) 15-20

Condensate (MBbls) 590-610

Total Production (Bcfe) 500-525

% Liquids 9%-10%

Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40)

NGL Realized Price ($/Bbl) $23.00-$24.00

Condensate Realized Price % of WTI 70%

Oil Realized Price % of WTI 100%

Realized Hedging Gain/(Loss) ($ in millions) (1) $85-$90

Other Operating Income (3rd party water income and resold FT) ($ in millions) $15-$20

CNXM 3rd Party Gathering Revenue $80-$85

Costs

Average per unit operating expenses ($/Mcfe):

Lease Operating Expense $0.15-$0.18

Production, Ad Valorem, and Other Fees $0.06-$0.08

Transportation, Gathering and Compression $0.80-$0.85 $0.60-$0.65

Total Cash Production and Gathering Costs $1.01-$1.11 $0.81-$0.91

($ in millions)

Selling, General, and Administrative Costs(2) $85-$95 $95-$110

Exploration Expense $10-$15

Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70

Other Non-Operating Expense $15-$20

Total Capital Expenditures $790-$915 $875-$1,005

CNXM EBITDA Attributable to CNX $60-$65

EBITDAX Attributable to CNX $825-$850

CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected operating 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) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 2/16/2018. Anticipated hedging activity is not included in projections.

(2) Excludes stock-based compensation.

Transportation, gathering and compression costs

expected to decline $0.15-$0.20 year-over-year

primarily due to increased contribution of lower

cost dry Utica volumes in Monroe County, OH

Unutilized FT and Processing Fees: $50 million

Idle Rig Fees: $5 million

Basis calculated on 2018 market mix.

Hedge gain/(loss) calculated on

NYMEX and financial basis hedges

Royalty income, right of way sales, interest income

and ‘other’ all netted against bank fees, other

corporate expense, and other land rental expense

Operations: Q1 2018 Results Summary

12

▪ Marcellus Shale costs were $2.30 per Mcfe in Q1

2018, an increase of $0.12 from $2.18 per Mcfe vs.

Q1 2017, or a 6% impairment

- Water disposal costs increased and processing

costs were higher related to Shirley-Pennsboro

wells turned-in-line in second half of 2017

▪ Utica Shale costs were $1.60 per Mcfe in Q1 2018, a

decrease of $0.56 from $2.16 per Mcfe in Q1 2017, or

a 26% improvement

- Transportation, gathering and compression

expenses improved as lower cost Monroe Country

dry Utica volumes increased

▪ E&P capital expenditures decreased in Q1 2018 to

$216 million from $233 million spent in Q4 2017

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

instruments (cash settlements) of ($0.14), ($0.55), and $0.19, respectively.

(2) Average Costs for 1Q2018, 1Q2017, and 4Q2017 include DD&A of $0.89, $1.01, and $1.01, respectively.

($/Mcfe) 1Q 2018 1Q 2017

Y/Y

Change 1Q 2018 4Q 2017

Q/Q

Change

Average Sales Price(1)

$3.00 $2.85 $0.15 $3.00 $2.80 $0.20

Total Production Costs(2)

$2.10 $2.32 ($0.22) $2.10 $2.17 ($0.07)

Sales Volumes (Bcfe) 129.5 95.0 34.5 129.5 118.9 10.6

Sales Volumes by Category (Bcfe)

Marcellus 65.9 58.0 7.9 65.9 64.0 1.9

Utica 43.5 15.3 28.2 43.5 33.8 9.7

CBM 15.9 16.7 (0.8) 15.9 16.0 (0.1)

Other 4.2 5.0 (0.8) 4.2 5.1 (0.9)

Operations: Q1 2018 Activity and 2018 Development Plan

13

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

(2) 50% working interest.

Q1 2018 2018E

($ in millions) TD FRAC TIL

Average

Lateral

Length(1)

Rigs at

Period End TD FRAC TIL

SWPA

Central

Marcellus 17 3 6 9,281 2 62 48 46

Utica - 1 1 6,213 3 1 1

WV

Shirley-Penns

Marcellus - - - - 5 5 5

Utica - - - - - - -

CPA South Utica - 1 1 6,741 4 4 2

OH DryUtica

2 - 6 8,641 1 8 10 15

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

Total 19 5 14 3 82 73 74

Richhill 11E and Marchand 3M deep dry Utica

wells currently undergoing testing

1 additional CPA deep

dry Utica TIL planned for

2H18Notable Wells

▪ Applied learnings in SWPA Central is demonstrating consistent

production results with capital efficiency increases

Consistent SWPA Marcellus Performance Sets Richhill Baseline

14

1,000

10,000

0 50 100 150 200Daily

Pro

duction N

orm

aliz

ed @

10,0

00’ (

Mcf/

d)

Production Days

GH Legacy GH Modern GH-55

0.92

2.89

4.02

0.00

1.00

2.00

3.00

4.00

5.00

GH Legacy (2008-2011) GH Modern (2015-2016) GH-55 (2018)

Capital E

ffic

iency (

Mcf/

$)

Green Hill Production Comparison Over Time

Green Hill Capital Efficiency Over Time

GH Legacy(2008-2011)

GH Modern(2015-2016)

GH-55(2018)

Average lateral length (ft) 1,800 5,750 9,500

Costs/ft $3,384 $1,170 $903

EUR (Bcf/1,000’) 2.5 3.6 3.6

96% of the lateral

footage was placed in

the 10’ target zone

Comingled flowback

operations accelerated

production by 20 days

along with reduced

capital

Replicating these techniques and results in Richhill

Marcellus will compound stacked pay efficiencies

Q1 2018 SWITZ Dry Utica Optimized Field Development Informs Richhill

15

1,000

10,000

0 50 100 150 200 250 300 350

8,0

00’ N

orm

aliz

ed P

roduction

(Mcf/

d)

Days

1100' vs 1350' Spacing

1100' Spacing 1350' Spacing

Ohio Dry Utica Field Spacing Changes

Richhill Compared to Switz:

▪ Similar geophysical density

responses

▪ Higher reservoir pressure

▪ Same landing point

▪ Optimized managed pressure

drawdown strategy

Decreased

Cycle Times

Proppant

Selection

and Loading

Full Field

Optimization

with Wider

Spacing

However, Richhill benefits

from:

▪Stacked pay efficiencies

▪Drilling guided by 3-D Seismic

1100’ Spacing 1350’ Spacing Δ

Costs/ft $1,534 $1,328 -13%

Capital Efficiency (Mcfe/$) 1.46 2.41 +65%

Extending inter-lateral spacing from 1100’ to 1350’ reduced total

field capital as fewer wells were required to recover comparable

volumes

▪ This concept is being deployed in Richhill SWPA Utica

▪ Optimized completion design and process have driven further

efficiencies as seen here:

Appendix

Marketing: Highlights and Liquids Realizations

17

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

(2) Excludes propane hedging impact.

Marketing Highlights

▪ Directly-marketed ethane volumes were 439,000 barrels in

Q1 and, on an equivalent basis, yielded a $1.24 per

MMBtu premium over CNX Resources’ residue natural gas

alternative

▪ $0.18/Mcfe uplift(1) from liquids for total average realization

of $3.00 per Mcfe in Q1 2018

2018 2017

Q1 Q1

NYMEX Natural Gas ($/MMBtu) $3.00 $3.32

Average Differential (0.21) (0.30)

BTU Conversion (MMBtu/Mcf)* 0.17 0.16

Loss on Commodity Derivative

Instruments-Cash Settlement(0.14) (0.55)

Realized Gas Price per Mcf $2.82 $2.63

* Conversion factor 1.06 1.05

Natural Gas Price Reconciliation

Natural Gas Liquids, Oil and Condensate

▪ Q1 2018 liquids sold: 12.0 Bcfe

▪ Total weighted average price of all liquids decreased 2% to

$29.15 per Bbl in Q1 2018 from $29.72 per Bbl in Q1 2017(2) and

decreased 8% from $31.82 per Bbl in Q4 2017

▪ In Q1, liquids comprised approximately 9% of 2018 production

volumes and 12% of total revenue and other operating income

Average Price Realization ($ per Bbl)(2)

2018 2017

Q1 Q1

NGLs $27.48 $29.16

Oil $56.46 $44.40

Condensate $49.32 $33.84

Natural Gas Hedging – Gain/Loss Projections

18

Note: Forward market prices are as of 4/12/2018. Hedged volumes and prices are as of 4/23/2018. Anticipated hedging activity is not included in projections.

(1) April prices are settled.

Q2 2018 CY2018 CY2019

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

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

($/MMBtu)

NYMEX 94,185 $2.98 $2.70 $0.28 $26,560 377,775 $2.98 $2.84 $0.14 $54,620

Basis:

DOM South (DOM) 7,280 ($0.59) ($0.57) ($0.02) ($168) 30,100 ($0.60) ($0.63) $0.03 $939

ETNG Cascade Creek TZ5 0 $0.00 $0.00 $0.00 $0 0 $0.00 $0.45 $0.00 $0

ETNG Mainline 0 $0.00 $0.00 $0.00 $0 0 $0.00 $0.23 $0.00 $0

Chicago 0 $0.00 ($0.25) $0.00 $0 0 $0.00 ($0.14) $0.00 $0

TCO Pool (TCO) 9,100 ($0.27) ($0.20) ($0.07) ($623) 36,500 ($0.27) ($0.26) ($0.01) ($376)

Michcon (NMC) 3,640 ($0.03) ($0.16) $0.13 $485 14,448 ($0.03) ($0.22) $0.18 $2,663

TETCO ELA (TEB) 1,365 ($0.09) ($0.09) $0.00 $2 5,475 ($0.09) ($0.09) $0.00 $18

TETCO WLA (TWB) 0 $0.00 ($0.08) $0.00 $0 0 $0.00 ($0.07) $0.00 $0

TETCO M3 (TMT) 4,550 ($0.12) ($0.48) $0.37 $1,666 19,895 ($0.05) $0.25 ($0.31) ($6,094)

TETCO M2 (BM2) 47,548 ($0.60) ($0.59) ($0.01) ($263) 191,613 ($0.60) ($0.63) $0.03 $6,387

Total Financial basis 73,483 $1,099 298,031 $3,537

Total Projected Gain/(Loss) $27,659 $58,157

(1)

Non-GAAP Reconciliation

19

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 March 31, 2018 is Net Income Attributable to Noncontrolling interest of $17,983

plus Depreciation, Depletion and Amortization of $2,707, plus Interest Expense of $1,699, plus Stock-based compensation of $374.

Note: Income tax effect of Total Pre-tax Adjustments (excluding exploration expense) was ($180,679) and $40,306 for the three months ended March 31, 2018 and March

31, 2017, respectively. Adjusted net income attributable to CNX Resources Shareholders for the three months ended March 31, 2018 is calculated as GAAP net income

attributable to CNX Shareholders of $527,563 less total pre-tax adjustments from the above table of ($666,221), plus the associated tax expense of ($180,679) equals the

adjusted net income attributable to CNX Resources Shareholders of $42,021.

Three Months Ended

March 31,

2018 2018 2018 2018 2017

($ in thousands)

E&P

DivisionMidstream Unallocated

(1) Total

Company

Total

Company

Net Income (Loss) $99,809 $35,534 $410,203 $545,546 ($38,966)

Less: Loss from Discontinued Operations - - - - (36,269)

Add: Interest Expense 36,062 2,489 - 38,551 41,606

Less: Interest Income (76) - - (76) (953)

Add: Income Taxes - - 213,694 213,694 (63,194)

Earnings/(Loss) Before Interest & Taxes (EBIT) 135,795 38,023 623,897 797,715 (97,776)

Add: Depreciation, Depletion & Amortization 115,866 8,801 - 124,667 95,678

Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing

Operations $251,661 $46,824 $623,897 $922,382 ($2,098)

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (52,078) - - (52,078) (24,640)

Gain on Certain Asset Sales - (4,737) (4,750) (9,487) -

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

Severance Expense 749 65 - 814 230

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

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

Loss (Gain) on Debt Extinguishment - - 15,635 15,635 (822)

Stock-Based Compensation 4,330 579 - 4,909 3,754

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

Exploration Expense 2,380 - - 2,380 9,785

Total Pre-tax Adjustments ($43,470) ($4,093) ($616,278) ($663,841) $126,172

Adjusted EBITDAX from Continuing Operations $208,191 $42,731 $7,619 $258,541 $124,074

Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2)

- 22,763 - 22,763 -

Adjusted EBITDAX Attributable to CNX Resources Shareholders $208,191 $19,968 $7,619 $235,778 $124,074

Documents

Earnings Results - consol-energy-ir.prod-use1.investis.comconsol-energy-ir.prod-use1.investis.com/~/media/... · Although CNX believes these sources are reliable, it has not independently