Earnings ResultsFourth Quarter 2017

January 30, 2018

Cautionary Language

2

This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended). Statements that are nothistorical are forward-looking, and include our operational and strategic plans; estimates of gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates offuture 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, plans, estimatesand projections. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of future actual results. Factors that could cause future actual results to differ materially from theforward-looking statements include risks, contingencies and uncertainties that relate to, among other matters, the following: pricing volatility for natural gas and natural gas liquids based upon a number of factorsbeyond our control including oversupply relative to the demand for our products, weather and the price and availability of alternative fuels; an extended decline in the prices we receive for our natural gas and naturalgas liquids affecting our operating results and cash flows; our dependence on gathering, processing and transportation facilities and other midstream facilities owned by CNXM and others; disruption of, capacityconstraints in, or proximity to pipeline systems, and decreases in availability of third-party pipelines or other midstream facilities interconnected to CNXM’s gathering systems; uncertainties in estimating oureconomically recoverable natural gas reserves, and inaccuracies in our estimates; the high-risk nature of drilling natural gas wells; our identified drilling locations are scheduled out over multiple years, making themsusceptible to uncertainties that could materially alter the occurrence or timing of their drilling; the impact of potential, as well as any adopted environmental regulations; risks inherent in natural gas operations;decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials; impairment of certain of our gas assets if natural gas prices remain depressed or drillingefforts are unsuccessful; the competitive nature of the natural gas industry or overcapacity in this industry; deterioration in the economic conditions in any of the industries in which our customers operate, a domestic orworldwide financial downturn, or negative credit market conditions; hedging activities may prevent us from benefiting from price increases and may expose us to other risks; inability to collect payments from customersif their creditworthiness declines or if they fail to honor their contracts; existing and future government laws, regulations and other legal requirements that govern our business may increase our costs of doing businessand may restrict our operations; significant costs and liabilities may be incurred as a result of pipeline and related facility integrity management program testing; our ability to find adequate water sources and to disposeof or recycle water used or removed from strata; the outcomes of various legal proceedings; acquisitions and divestitures we anticipate may not occur or produce anticipated benefits; risks associated with our debt;failure to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves; any decrease in our borrowing base; operating with one or more joint venture partners or incircumstances where we are not the operator, which may restrict our operational and corporate flexibility; changes in federal or state income tax laws; challenges associated with strategic determinations, including theallocation of capital and other resources to strategic opportunities; terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations; construction of newmidstream assets by CNXM may not result in revenue increases and may be subject to risks; dependence on key members of management and our ability to attract and retain experienced technical and otherprofessional personnel; issues relating to our the separation of CONSOL Energy, including failure to realize expected benefits, failure to perform under various transaction agreements that were executed as part of theseparation, including with respect to indemnification obligations and the possibility of substantial tax liability; and other factors, many of which are beyond our control. Additional factors are described in detail under thecaptions "Forward Looking Statements" and "Risk Factors" in our annual report on Form 10-K for the year ended December 31, 2016 filed with the Securities and Exchange Commission (SEC), as supplemented by ourquarterly reports on Form 10-Q. 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 onthem unduly.

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 andlegally 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 theirnature 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.

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 ofnatural 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 ourexpense. 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 partiesmay participate in the wells we drill, thereby reducing our working interest in those wells.

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.

Post-Spin Company Names and Stock Trading Symbols

3

Effective November 28, 2017, the company known as CONSOL Energy Inc. (NYSE: CNX) separated its gas business (GasCo orRemainCo) and its coal business (CoalCo or SpinCo) into two independent, publicly traded companies by means of a separationof CoalCo from RemainCo.

The gas business, CNX Resources Corporation (RemainCo, GasCo or CNX), continues to be listed on the NYSE, retaining the tickersymbol "CNX". Information regarding CNX and its natural gas business is available at www.cnx.com.

Following the closing of CNX’s purchase of Noble Energy’s 50% interest in CNX Gathering LLC, which occurred on January 3, 2018, themaster limited partnership that was named CONE Midstream Partners, LP has changed its name to CNX Midstream Partners LP andnow trades on the NYSE under a new ticker symbol: “CNXM”. CNX indirectly owns 100% of the general partnership interests of CNXMidstream Partners LP as well as all of its incentive distribution rights. Information regarding CNX Midstream Partners LP is available atwww.cnxmidstream.com.

The coal business, CONSOL Energy Inc. (SpinCo, CoalCo or CONSOL), is listed on the NYSE under the ticker symbol: "CEIX".CoalCo owns, operates and develops coal assets, including the Pennsylvania Mining Complex, the Baltimore Marine Terminal, andapproximately one billion tons of greenfield coal reserves. Information regarding the new CONSOL Energy and its coal business isavailable at www.consolenergy.com.

The master limited partnership that was named CNX Coal Resources LP (NYSE: CNXC) has changed its name to CONSOL CoalResources LP and trades on the NYSE under a new ticker symbol: "CCR". CONSOL owns 100% of the general partner of CONSOLCoal Resources LP (representing a 1.7% general partner interest), as well as all of the incentive distribution rights and the common andsubordinated interests in CNX Coal Resources LP that were owned by CNX prior to the spin-off. Information regarding CONSOL CoalResources LP is available at www.ccrlp.com.

Executive Summary

4

Q4 2017 EXPECTATIONSTRATEGIC INITIATIVE

CNX Resources Launch Completed spin-off of CoalCo in late-November; combined

value of shares has increased ~20% since effective date while gas peer group is flat over same period

Two premier standalone entities in the energy industry poised for growth and stability

Production Guidance Reaffirmed 2018 production guidance of 520-550 Bcfe, growth of >30% at the midpoint

Confidence in production profile driven by strong results in Monroe County, OH dry Utica and new wells coming online in SWPA Marcellus

Share Repurchase Bought back ~$103 million of CNX shares to date, all of which occurred in Q4 2017

Balance of one-year $450 million authorization in effect and remains a capital allocation priority

Deep Dry Utica Aikens 5J and 5M drilled and completed for ~$15 million and now flowing above previous type curve expectations

Confirms commercial viability of the Central Pennsylvania deep dry Utica

CNX Midstream Transaction On January 3, 2018, acquired 100% control of the GP

interest and IDRs, and amended the Gas Gathering Agreement with CNX; CNXM unit price up ~18% since December 15 acquisition announcement

Rebranded and relaunched CNX Midstream Partners LP now able to confidently convey line of sight to multiple years of 15% distribution growth

CNX Midstream: Launch of a Premier Single-Sponsor MLP

5

GP Transaction Overview CNX closed on acquisition of NBL’s 50% interest in CONE Gathering

LLC, the GP controlling entity of CONE Midstream Partners (CNNX) CONE Midstream Partners LP (CNNX) renamed CNX Midstream

Partners LP (CNXM) CNX now 100% owner of MLP IDRs and remaining undropped interest

in DevCos CNX continues to own 21.7 million common LP units

Immediate Changes Strategy alignment from sponsor through MLP

- New CEO, CFO and three new Board members Commercial Agreement change, effective January 3, 2018

- 61,000 new Utica acres dedicated to CNXM- Four year minimum activity commitment from sponsor- Incremental fees for compression services- Unlocking of stacked pay resources for full-scale development

Extending long-term distribution target

Note: Simplified organization view: some intermediate holding companies have been omitted.(1) Public includes 33.5% held by Noble Energy, Inc.

Public(1)

41.8mm Common Units

CNX Midstream GP LLCThe “General Partner”

Incentive Distribution Rights

CNX Gathering, LLC

100%

NYSE: CNX

64.5% LP Interest

2% GP Interest

Anchor Systems(Development Co. 1)

Growth Systems(Development Co. 2)

Additional Systems(Development Co. 3)

33.5% LP Interest

100% 5% GP Interest 5% GP Interest

95% Interest

NYSE: CNXM

Post-Spin Value Analysis: First Two Months

6

The CoalCo spin transaction has unlocked substantial value just two months since it was executed Holders of CNX shares prior to the effective spin date (11/29/2017) have seen appreciation of ~18%

- In that same time period, shares of natural gas peers are flat

(1) As of 1/23/2018.(2) Aggregate share price change of AR, COG, GPOR, EQT, RRC, SWN from 11/28/2017-1/23/2018.(3) Actual CEIX share price divided by 8 to account for distribution ratio (1 share of CEIX distributed for each 8 shares of CNX held by owner).

CNX/CEIX Share Price Since Spin

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

$-

$5.00

$10.00

$15.00

$20.00

$25.00

11/28/2017 12/5/2017 12/12/2017 12/19/2017 12/27/2017 1/4/2018 1/11/2018 1/19/2018

CNX Share Price CEIX Share Price Combined CNX & CEIX Price Δ (%) Peer Avg Price Δ (%)

CNX & CEIX+18%

Gas Peers(2)

+0%

Last day of CNX trading before spin effective date: $16.16

Combined value of CNX & CEIX: $19.10(1)

(3)

Q4 2017 Results

7

Net Income and Adjusted EBITDA On a GAAP basis, Net Income from Continuing Operations of $282 million in the 2017 fourth quarter or $1.24 per diluted share;

Adjusted Net Income from Continuing Operations of $222 million, or $0.98 per diluted share(1); Adjusted Net Income excludes the following pre-tax items:- $106 million unrealized gain on commodity derivative instruments- $20 million related to settlement expense- $8 million in various other items

Total company Adjusted EBITDA Attributable to Continuing Operations in the fourth quarter of $173 million

Note: The terms “Adjusted Net Income" and “Adjusted EBITDA Attributable to Continuing Operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation."(1) Income tax effect of Total Pre-tax Adjustments was $17,850 for the three months ended December 31, 2017. Adjusted net income for the three months ended

December 31, 2017 is calculated as GAAP income from continuing operations of $282,143 less total pre-tax adjustments of $77,612, plus the associated tax expense of $17,850 equals the adjusted net income from continuing operations of $222,381.

Q4 2017 Summary($ in millions, except per share data) 4Q 2017 4Q 2016

Y/YChange 4Q 2017 3Q 2017

Q/QChange

Net Income / (Loss) from Continuning Operations $282 ($300) $582 $282 ($34) $316Total Dilutive Earnings / (Loss) Per Share $1.21 ($1.33) $2.54 $1.21 ($0.11) $1.32Revenue and Other Income from Continuing Operations $477 $74 $403 $477 $290 $187Adjusted EBITDA Attributable to Continuing Operations $173 $132 $41 $173 $105 $68

Marketing: Gas Hedges

(1) Hedge positions as of 1/15/2018. Q1 2018 and 2018 exclude 6.0 Bcf and 13.7 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 production guidance of 520-550 Bcfe in 2018E. 8

Approximately 70% of total 2018E production volumes hedged(3)

NYMEX hedges added during Q4: 279 Bcf (2018-2022)

Basis hedges added during Q4: 209 Bcf (2017-2022)

Hedge Volumes and Pricing Q1 2018 2018 2019 2020 2021 2022

NYMEX Only HedgesVolumes (Bcf) 88.2 357.6 260.1 187.3 148.5 143.0 Average Prices ($/Mcf) 3.14 $3.14 $3.04 $3.09 $2.99 $3.04

Physical Fixed Price SalesVolumes (Bcf) 4.2 17.3 12.9 11.0 18.0 10.4 Average Prices ($/Mcf) 2.61 $2.61 $2.48 $2.43 $2.47 $2.60

Total Volumes Hedged (Bcf)(1) 92.4 374.9 273.0 198.3 166.5 153.4

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

Volumes (Bcf) 92.4 374.9 263.2 182.2 148.2 62.4 Average Prices ($/Mcf) 2.75 $2.76 $2.73 $2.76 $2.58 $2.54

NYMEX Only Hedges Exposed to BasisVolumes (Bcf) - - 9.8 16.1 18.3 91.0Average Prices ($/Mcf) - - $3.04 $3.09 $2.99 $3.04

Total Volumes Hedged (Bcf)(1) 92.4 374.9 273.0 198.3 166.5 153.4

374.9

263.2 182.2 148.2

62.4

0.0

9.8

16.1 18.3 91.0

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

Guidance

9

Operations 2018EProduction Volumes:Natural Gas (Bcf) 475-505NGLs (MBbls) 6,700-7,300Oil (MBbls) 50-55Condensate (MBbls) 550-560Total Production (Bcfe) 520-550% Liquids 9%-10%

Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40)NGL Realized Price ($/Bbl) $24.00-$25.00Condensate Realized Price % of WTI 70%Oil Realized Price % of WTI 100%

Capital Expenditures ($ in millions):Drilling and Completion $515-$580Land, Midstream, and Water(1) $275-$300

Total CapEx $790-$880

Average per unit operating expenses ($/Mcfe):Lease Operating Expense $0.16-$0.18Production, Ad Valorem, and Other Fees $0.06-$0.08Transportation, Gathering and Compression $0.78-$0.82Total Cash Production and Gathering Costs $1.00-$1.08

Other Expenses ($ in millions):Selling, General, and Administrative Costs(2) $100-$105Other Operating Expenses(3) $70-$75

Note: Base plan assumes NYMEX as of 1/3/2017 of $2.85 per MMBtu + weighted average basis of ($0.32) per MMBtu on open volumes.CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDA 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) Excludes capital associated with CNXM GP acquisition.(2) Includes attributable portion of CNXM SG&A. Excludes stock-based compensation.(3) Includes unutilized firm transportation and processing fees, idle rig expense, and other miscellaneous items.(4) Includes approximately $60-$90 million of EBITDA attributable to CNX’s ownership in CNXM.

Adjusted EBITDA ($ in millions) 2018EEarnings Before Interest, Taxes and DD&A (EBITDA) $845-895Adjustments:Unrealized (Gain) on Commodity Derivative Instruments (15)Stock-Based Compensation 15

Adjusted EBITDA(4) $845-$895

Transportation, gathering and compression costs expected to decline $0.20 year-over-year primarily due to increased contribution of lower cost dry Utica volumes in Monroe County, OH

Idle rig fees declining significantly as rigs go back to work and contracts end

Operations: Q4 2017 Results Summary

10

Marcellus Shale costs were $2.32 per Mcfe in Q4 2017, an increase of $0.12 from $2.20 per Mcfe vs. Q4 2016, or a 5% impairment- Gathering costs increased due to higher processing

and CNX Midstream fees related to an increase in the production mix towards wet gas

Utica Shale costs were $1.59 per Mcfe in Q4 2017, a decrease of $0.27 from $1.86 per Mcfe in Q4 2016, or a 15% improvement- Transportation, gathering and compression

expenses improved as lower cost volumes came online in Monroe County

Capital expenditures increased in Q4 2017 to $233.4 million, from $149.5 million spent in Q3 2017 due primarily to an increase in completions activity

(1) Average Sales Prices for 4Q2017, 4Q2016, and 3Q2017 include gains on commodity derivative instruments (cash settlements) of $0.19, $0.46, and $0.20, respectively.

(2) Average Costs for 4Q2017, 4Q2016, and 3Q2017 include DD&A of $1.01, $1.05, and $1.00, respectively.

(Prices $/Mcfe; Volumes Bcfe) 4Q 2017 4Q 2016Y/Y

Change 4Q 2017 3Q 2017Q/Q

ChangeAverage Sales Price(1) $2.80 $2.77 $0.03 $2.80 $2.50 $0.30Total Production Costs(2) $2.17 $2.27 ($0.10) $2.17 $2.26 ($0.09)Sales Volumes 118.9 101.3 17.6 118.9 101.0 17.9

Sales Volumes by CategoryMarcellus 64.0 56.5 7.5 64.0 60.4 3.6Utica 33.8 22.2 11.6 33.8 20.1 13.7CBM 16.0 17.4 (1.4) 16.0 16.2 (0.2)Other 5.1 5.2 (0.1) 5.1 4.3 0.8

Operations: Q4 2017 Activity and 2018 Development Plan

11

Q4 2017 FY 2017 2018E

TD Frac TIL

Average Lateral

Length(1) TD Frac TIL

Average Lateral

Length(1) TD Frac TILMarcellus

Southwest Pennsylvania 1 6 - 9 16 11 9,090 55 37 41 West Virginia - 2 4 8,792 - 20 20 8,052 5 5 5

Total Marcellus 1 8 4 9 36 31 60 42 46

UticaOhio dry Utica (Monroe County, OH) 1 9 8 9,083 17 27 20 8,721 7 4 10 Southwest Pennsylvania 1 - - 1 - - 4 1 1 Central Pennsylvania 1 2 2 6,987 3 2 2 6,987 4 4 2

Total Utica 3 11 10 21 29 22 15 9 13

Upper DevonianSouthwest Pennsylvania - - 1 13,498 - 1 3 12,081 - - -

Total Upper Devonian - - 1 - 1 3 - - -

Total Wells 4 19 15 30 66 56 75 51 59

Rigs Running at Period End 3 3 4

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

2018 Activity: SWPA Marcellus Outperforming Type Curves

(1) Legacy Morris comprised of 21 wells TIL March 2012-June 2013; Morris 30 pad comprised of 5 wells TIL mid-2017.

12

11

41

05

1015202530354045

2017 2018E

TILs

SWPA Marcellus TILs – 2017 vs. 2018E

SWPA Marcellus comprises a much larger portion of 2018 development activity year over year- Activity in the Morris, Green Hill, and Richhill fields driving the

increase- Plan to run 2-3 rigs in region throughout the year- Expected to TIL 41 SWPA Marcellus wells in full-year 2018

Average EUR/1,000’ increased 77% from legacy Morris wells(1)

- Increased lateral length, increased proppant loading, min/max stress optimization along with the mechanical diversion testing program is driving increased reservoir performance

All Morris pads being designed for future stacked pay development

Morris wells expected to make up more than 65% of 2018E SWPA Marcellus TIL activity

Morris Production – Legacy vs. Now

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Deep Dry Utica Update: Aikens 5J and 5M

13

Located in Westmoreland County, PA (CPA region); two wells offsetting successful Gaut 4IH well

Average capital per well: approximately $15 million Currently performing above CPA Utica 3.5 Bcf/1000’

EUR with an average lateral length of ~7,000’(1)

- Cumulative production for combined wells is 2.43 Bcf through first 47 days

Wells averaged 24 MMcf/d during first 47 days of production with average flowing pressure of 8,672 psig- Expect production to be flat for ~18 months

Executing managed pressure drawdown Aikens 5J: validating Gaut 4IH results by replicating

completion design and achieving similar results Aikens 5M: testing higher proppant loading and

model driven ceramic selection- The Aikens 5M well is on track to be the second

best well in the basin to date

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ate,

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/dTime, Days

3.7 Bcf/1000' Type Curve Actual (mcf/day)

Aikens 5J

Aikens 5M

(1) Measured in lateral feet from perforation to perforation; average drilled length of 7,500’.

2018 Activity: Core Marcellus and Growing Utica Contribution

14

CNX December 2017 monthly average exit rate of 1.39 Bcfe/d- Reached peak of 1.44 Bcfe/d in early

December Expected base exit-to-exit decline of

32% in FY2018, compared to FY2017 Marcellus continues to be the focus of

D&C activity and will see majority of capital spend for FY2018- D&C Capital ($515-$580 million)

- Marcellus: 65%- Utica: 35%

2018 Production by Formation

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Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18

Cum

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MARCELLUS PDP UTICA PDP OTHER PDP MARCELLUS ADDSUTICA ADDS CBM/OTHER ADDS Cumulative Production

Appendix

15

Appendix: Marketing Highlights and Liquids Realizations

16

(1) Calculation includes the impact of gas hedging cash settlements. (2) Excludes propane hedging impact.

Marketing Highlights Directly-marketed ethane volumes were 590,000 barrels in

Q4 and, on an equivalent basis, yielded a $1.80 per MMBtu premium over CNX Resources’ residue natural gas alternative

$0.32/Mcfe uplift(1) from liquids for total average realization of $2.80 per Mcfe in Q4 2017

2017 2016

Q4 Q4NYMEX Natural Gas ($/MMBtu) $2.93 $2.98Average Differential (0.76) (0.88)BTU Conversion (MMBtu/Mcf)* 0.12 0.12Gain on Commodity Derivative

Instruments-Cash Settlement 0.19 0.46

Realized Gas Price per Mcf $2.48 $2.68* Conversion factor 1.06 1.06

Natural Gas Price Reconciliation

Natural Gas Liquids, Oil and Condensate Q4 2017 liquids sold: 13.4 Bcfe Total weighted average price of all liquids increased 49% to

$31.82 per Bbl in Q4 2017 from $21.34 per Bbl in Q4 2016(2) and increased 53% from $20.77 per Bbl in Q3

In Q4, liquids comprised approximately 11% of 2017 production volumes and 15% of total operating income

Average Price Realization ($ per Bbl)(2)

2017 2016

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1NGLs $30.48 $19.32 $15.96 $29.16 $20.40 $13.14 $12.84 $12.30Oil $45.48 $41.94 $48.18 $44.40 $41.58 $42.06 $33.72 $30.84 Condensate $46.08 $41.34 $34.14 $33.84 $30.84 $37.26 $31.68 $14.64

Appendix: Gas Hedges

17

(1) Hedge positions as of 1/15/2018.

Physical fixed basis sales provide opportunities to lock in revenue in illiquid markets

Systematic hedging of both NYMEX and basis fully covers the majority of 2018 expected production

Physical Fixed Basis and Fixed Price Sales(1) Q1 2018 2018 2019 2020 2021 2022Physical Fixed Basis SalesVolumes (Bcf) 22.6 89.6 89.2 49.6 36.9 3.4Average Basis Prices ($/Mcf) $0.18 $0.14 $(0.04) ($0.07) ($0.48) $(0.67)

Physical Fixed Price SalesVolumes (Bcf) 4.2 17.3 12.9 11.0 18.0 10.4Average Prices ($/Mcf):NYMEX portion $3.17 $3.17 $3.06 $3.03 $3.01 $3.04Basis portion $(.56) $(.56) $(0.58) $(0.60) $(0.54) $(0.44)

$2.61 $2.61 $2.48 $2.43 $2.47 $2.60

Hedge Position(Outer ring = NYMEX; Inner ring = Basis)

2018

Appendix: Natural Gas Sales Market Mix

18

MIDWEST TETCO M3

TETCO M2

TETCO ELATETCO WLA

TCO POOL

DOMINION SOUTH

Natural Gas Sales Market Mix 2018EColumbia (TCO) 10%TETCO (M2) 52%TETCO (M3) 6%Dominion (DTI) 9%East Tennessee 10%TETCO ELA & WLA 5%Midwest (Michcon) 8%

100%

Non-GAAP Reconciliation

19

Source: Company filings.Note: Financial results for 2017 reflect provisional amounts related to the December 2017 enactment of the Tax Cuts and Jobs Act. These provisional estimates are based on CNX's initial analysis and current interpretation of the legislation. Given the complexity of the legislation, anticipated guidance from the U.S. Treasury, and the potential for additional guidance from the Securities and Exchange Commission (SEC) or the Financial Accounting Standards Board, these estimates may be adjusted during 2018. As a result, CNX continues to evaluate the impacts to the company's balance sheet and cash flow statements and expects to provide an update with its 10-K filing.

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 2017Net (Loss) / 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) (Loss)/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(Loss)/Earnings Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations ($2,097) $306,010 $128,724 $250,338 $682,975Adjustments:

Unrealized Gain on Commodity Derivative Instruments (24,640) (116,073) (1,512) (105,879) (248,104) Settlement Expense - - - 19,787 19,787 Gain on Asset Sales - (126,707) (30,315) - (157,022) Impairment on E&P Properties 137,865 - - - 137,865 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 Lease Expirations - 16,861 - - 16,861 Marcellus Dissolution (822) - - - (822) Loss on Debt Extinguishment - 36 2,019 896 2,951 Total Pre-tax Adjustments $116,387 ($221,647) ($23,735) ($77,612) ($206,607)

Adjusted EBITDA Attributable to Continuing Operations $114,290 $84,363 $104,989 $172,726 $476,368