Analyst & Investor Meeting

Analyst & Investor Meeting Pittsburgh, Pennsylvania March 13, 2018

Cautionary Language 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. 2

Agenda Strategic Overview Nick DeIuliis, Chief Executive Officer Marketing Chad Griffith, VP Marketing Operations Tim Dugan, Chief Operating Officer Andrea Passman, VP Development Finance Don Rush Chuck Hardoby, VP Finance Business Development Don Rush, Chief Financial Officer Questions & Answers 3

Strategic Overview Nick DeIuliis

154-Year Legacy is a Competitive Advantage Industrialist Andrew Mellon financed the consolidation of the coal estate throughout Appalachia leading to the founding of Consolidation Coal Company The Dominion assets CNX acquired in 2010 trace their roots to the late 1800s and John D. Rockefeller s Standard Oil Company, which formed Consolidated Natural Gas 1860 1960 1980 2000 2008 2010 2014 2017 2018 The vast interwoven nature of the CNX acreage holdings has resulted in nonoperated well data from more than 800 Marcellus and Utica wells dating back to 1968 5

Greater than the Sum of the Parts Set in motion more than a decade ago, CNX emerged as a premier standalone E&P company on November 29, 2017 The separation of the businesses allows CNX to efficiently deploy its capital allocation strategy 6

Asset Base Creates Compelling Value Creation Opportunity Large Contiguous Acreage Position Net Marcellus Acres / Net Utica Acres (1) 531,000 / 652,000 % Operated Reserves to Production (years) 95.5% 18.6 Proved Reserves 7.6 Tcfe Highly Productive Asset Base 2017 Average Net Production 1,116 MMcfe/d 5-Year Production CAGR Half-Cycle Portfolio IRR 20% 75% Current Deep Dry Utica Performance 3.7 Bcfe/1000 Leading Economic Profile 2018E Total Cash Production and Gathering Costs $1.01-$1.11 /Mcfe 2017 EBITDAX Margin 2017 Recycle Ratio 32% 3.3x Targeted Leverage Ratio by YE2018 2.5x (1) See appendix slide 102 for complete acreage breakdown by region. 7

The CNX Strategy is to Grow NAV/Share via Capital Allocation Key drivers of the strategy: Methodical execution driving IRR and EBITDAX growth Basin disruption through stacked pay development Top-tier balance sheet Opportunistic share count reduction CNXM 15% distribution growth stability and drop inventory Strategy is reinforced by management philosophy, company values, incentive plans, and ownership 8

IRR (%) $ in millions Methodical Execution Driving IRR and EBITDAX Growth 80% 70% Expected Five-Year Plan Portfolio Economics 75% $2,000 Drill Bit Investment Driving EBITDAX Growth 60% $1,500 50% 40% 38% $1,000 30% 20% $500 10% 0% Full Cycle Half Cycle $0 2018E 2022E Low High Note: See appendix for full and half cycle economic assumptions. (1) Based on midpoint of financial guidance. 9

NPV ($ in millions) IRR (%) Stacked Pay Development Will Disrupt the Appalachian Basin CNX has a non-replicable asset base allowing for stacked pay development Stacked pay provides 30% increase to total field NPV Stacked pay drives superior IRRs through economies of scale and greater flexibility Stacked Pay Pad Economics Example Reduces capital $300 120% Reduces cycle times $250 100% Reduces LOE $200 80% Reduces gathering and processing fees Seismic across acreage hold that de-risks drilling, completion, and production $150 $100 60% 40% Increases utilization and efficiencies Extends growth opportunity $50 $0 $2.00 $2.50 $3.00 20% 0% Gas Price Unstacked NPV Stacked NPV Unstacked IRR % Stacked IRR % Note: Assumes six Marcellus laterals at 9,500 and six Utica laterals at 8,500. 10

Top Tier Balance Sheet Strength Drives Capital Optionality STEADY STATE 2.5X LEVERAGE RATIO DRILL BIT ROBUST HEDGE BOOK & FT STRATEGY IRR ANALYSIS SHARE COUNT REDUCTION DISCRETIONARY CASH FLOW ASSET MONETIZATIONS BALANCE SHEET CAPACITY BOLT-ON ACQUISITIONS 11

Net Debt / EBITDAX EBITDAX ($ in millions) Shares Outstanding (millions) Market Cap ($ millions) Leverage Ratio Capacity Allows for Share Count Reduction Growing EBITDAX Creates Natural Capacity within 2.5x Leverage Ratio Available Capacity Reinvested in Share Count Reduction 3.0x Cumulative available capacity of ~$3 billion 2018-2022 $2,500 250 $10,000 2.5x Steady State Leverage Ratio: 2.5x $2,000 200 ~$70/share on baseline capacity (1) $9,000 $8,000 2.0x $7,000 $1,500 1.5x 150 ~$30/share (1) $6,000 $1,000 $5,000 1.0x 100 $4,000 0.5x 0.0x 2018E 2019E 2020E 2021E 2022E $500 $0 50 Potential to reduce float ~40% by YE2022 under status quo plan or ~60% by YE 2022 with deployment of potential drop proceeds $3,000 $2,000 $1,000 Available debt capacity at 2.5x leverage ratio for share buybacks Net Debt / EBITDAX excluding share buybacks or asset sale proceeds EBITDAX Range - 2017 2018E 2019E 2020E 2021E 2022E Shares Outstanding Market Cap (1) $- Note: Leverage ratio assumes the high case of financial guidance, while assuming no additional asset sales or drops. (1) Stock repurchase price assumes static year-forward EV/EBITDAX multiple of 5.9x on guided adjusted EBITDAX and net debt levels. Does not assume deployment of ~$1.6 billion in potential drop proceeds and $0.2 billion in alternative minimum tax refund. 12

$ in millions $ in millions CNXM 15% Distribution Growth De-Risked $300 CNXM Distributable Cash Flows by Source 2017-2022E Expected CNXM Distributions to CNX 2017-2022E $140 $130 $250 $120 $103 $100 $200 $80 $80 $150 $60 $60 $100 $40 $28 $42 $50 $20 $0 2017 2018E 2019E 2020E 2021E 2022E $0 (1) 2017 2018 2019 2020 2021 2022 PDPs pre-s/p Drop Shirley-Penns MVC LP Distribution to CNX (as Declared) McQuay Activity Commitments Total Distributions Activity Above MVC & Commitments GP & IDR Distribution (as Declared) (1) 2017 GP IDR at 50% ownership. 13

Compensation Plan Reinforces Strategy Long-Term Incentive Program (PSUs) Short-Term Incentive Compensation Program 2016 Free Cash Flow Compensation plans motivate management to execute on: 2017 Free Cash Flow Methodical operational execution 2018 & Beyond 50% Relative TSR (S&P 500) 50% Absolute Stock Price Adjusted EBITDA/Share Company-wide short-term incentive plan Governed by 2.5x leverage ratio target Balance sheet discipline Basin disruption through stacked pay development CNXM growth stability and upside opportunities Encourages return of capital to shareholders Share count reduction CEO compensation 90% at-risk (STIC, RSUs, and PSUs) 14

SHARES OUTSTANDING NAV DRIVEN BY Importance of Both Numerator and Denominator in NAV/Share DIFFERENTIATED ASSET BASE OPERATIONAL EXECUTION GROWING RESERVES VALUE OPTIMIZED VALUE OF MLP PRUDENT ASSET MONETIZATION BALANCE SHEET & HEDGE BOOK Share count reduction can be the best capital allocation decision if it passes through the NAV and IRR filters = NAV/Share Accretion & Recognition 15

Operations Tim Dugan Andrea Passman

Unique Stacked Acreage Portfolio Sets the Stage 531,000 Total Net Marcellus Acres 582 Net Undeveloped Marcellus Locations in SWPA 652,000 Total Net Utica Acres 669 Net Undeveloped Utica Locations in SWPA ~89% Total Company Average NRI ~90% Total Company HBP ASSET BASE HIGHLIGHTS Vast multi-formation acreage position built over 150+ years Premier gathering infrastructure and midstream MLP Monetization opportunities outside core development plan SKILL SET Modeling, delineation, and innovative solutions driven by decades of data Cutting edge strategic intelligence through extensive acreage position Multi-basin experience delivered by personnel and joint ventures 17

Type Curve Guidance Areas Refined For Modeling Accuracy Type curve (TC) guidance areas refined to present more accurate characteristics of acreage - Went from five TC regions (SWPA, CPA, WV, and OH Dry & Wet) to now eight (SWPA: Central & Greater, WV: SHR/PENS & East, CPA: South & North, and OH: Dry & Wet) - SWPA Central type curves increased in both Marcellus and Utica compared to prior divisions - ~80% of three-year plan in SWPA Central New type curve assumptions include: - Increased lateral spacing in OH dry Utica and adjustment for dry Utica sale in Jefferson County - EURs increased in three of four focus areas in three year plan (SWPA Central, WV SHR/PENS, and OH Dry) Available electronic type curve data allows for detailed modeling of the CNX production profile (1) (1) See http://investors.cnx.com/events-and-presentations/events/2018. 18

0.74 1.21 1.56 1.94 2.00 2.17 2.44 1.22 1.61 2.30 2.48 2.71 2.99 3.18 3.85 5.06 1.86 2.92 3.39 2.03 4.77 4.46 3.26 2.40 2.18 2.69 2.31 5.66 2.63 1.85 3.07 2.67 2.51 2.59 2.54 2.78 2.79 3.45 2.91 3.55 2.89 2.93 2.27 2.39 2.42 2.57 2.85 BTAX IRR (%) Capital Efficiency Continues to Improve NAV growth driven by optimization and stacked pay Increased EURs from model-driven spacing, completion design, and managed pressure drawdown 160% 140% 120% 100% 80% Capital Efficiency (Mcfe/$) 1.83 Mcfe/$ 2.78 Mcfe/$ 2.78 Mcfe/$ 2.84 Mcfe/$ Avg BTAX IRR 85% Service cost inflation in 2017 offset by increased EURs 60% 40% Avg BTAX IRR 52% Avg BTAX IRR 57% 20% Avg BTAX IRR 25% 0% 2015 2016 2017 2018E EUR/CAPEX (Mcfe/$) Note: Bars represent single well-level economics, which includes total D&C capital employed. 19

EUR (Bcfe/1000') EUR (Bcfe/1000') EUR Increases Driven by Modeling and Optimization Marcellus EURs Modeling Maximizes NAV 85% increase in proppant loading from pre-2016 to 2018E Subsurface communication mitigation implemented Lateral spacing optimization Managed pressure drawdown Cluster diversion technology 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 2.7 2.9 1.7 <2016 2016-2017 2018E Min/max stress optimization 3-D seismic guided drill plans Core area delineation 3.5 3.0 2.5 Utica EURs 2.6 3.3 2.0 1.5 1.4 1.0 0.5 0.0 <2016 2016-2017 2018E 20

$ in millions PDP Performance Drives Low Maintenance Capital 35% PDP Base Decline % $900 $800 Maintenance Capital Possible Cumulative FCF of ~$1.4 billion 2019E-2022E 30% $700 25% $600 $500 Possible FCF at (1) Maintenance Capital 20% $400 $300 15% $200 10% 5% <20% in Q2 2019 <10% in Q2 2021 0% 2018E 2019E 2020E 2021E 2022E $100 $0 2018E 2019E 2020E 2021E 2022E Maintenance Capital Possible FCF at Maintenance Capital Planned Capital Average Maintenance Capital Average maintenance capital of ~$325 million per year to hold exit rate flat at 1.39 Bcfe/d (2) Expected exit-to-exit base decline rate of 32% in FY2018, compared to FY2017 (1) For illustrative purposes; assumes annual production of 507 Bcfe (1.39 Bcfe/d exit rate), average EBITDAX of $800 million and interest expense of $100 million. (2) December 2017 net daily average. 21

Drilling Days Drilling Days Drilling Days Drilling Days Drilling Days Declining Steadily in Every Region Total Marcellus Average Drilling Days per Well CPA Utica Average Drilling Days per Well 30 140 25 20 15 10 5 120 100 80 60 40 20 0 2014 2015 2016 2017 2018E 0 2015 2016 2017 2018E Ohio Wet Utica Average Drilling Days per Well Ohio Dry Utica Average Drilling Days per Well 35 30 25 20 15 10 5 0 2014 2015 2016 2017 2018E 80 70 60 50 40 30 20 10 0 2014 2015 2016 2017 2018E 22

Average Days/1,0000 ft Average Days/1,0000 ft Completion Cycle Times Driving Capital Efficiency Total Portfolio Completions Cycle Times Marcellus Completions Cycle Times 5 5 4 4 3 3 2 2 1 1 0 2014 2015 2016 2017 2018E 0 2014 2015 2016 2017 2018E 23

DEVELOPMENT PLAN 24

YE2017 YE2018E YE2019E YE2020E YE2021E YE2022E Bcfe/d TIL Locations Shift to SWPA and Stacked Pay: Surplus Core Marcellus Inventory 450 3.5 400 3.0 Stacked Pay Factory up and running 350 300 TILs 46 TILs 55 2.5 2.0 1.5 1.0 20% Production CAGR 2017-2022E (1) 250 200 150 100 50 Net SWPA Central Marcellus Inventory 391 TILs 73 Net SWPA Central Marcellus Inventory 217 0.5 0 Entering 2018 2018 2019 2020 Year End 2020 0.0 As CNX returns focus to the core SWPA region, the company is expected to consume only a fraction of existing CNXM DevCo I Marcellus locations in the near term - This creates valuable optionality in the development plan Marcellus Utica Other - Increases activity - Extends stacked pay development - Creates asset sale and swap opportunities (1) Based on the midpoint of guidance. 25

PV10 ($ in thousands) IRR (%) Stacked Pay Creates Substantial Uplift Beyond Longer Laterals Stacked pay PV10 is 4.4x unstacked pay $25,000 140 PV10 (1) $20,000 120 Longer lateral PV10 is 1.9x shorter lateral 100 PV10 (1) $15,000 80 Stacked pay is a more influential economic driver than only focusing on lateral length; CNX combines both value drivers in development $10,000 $5,000 60 40 20 Extending laterals delays turn-in-line, while stacked pays can be added at a later date optimizing IRR and EBITDAX $0 0 $2.00 $2.50 $3.00 Gas Price Unstacked 9500' Unstacked 12000' Stacked 9500' Stacked 12000' Unstacked 9500' ROR Stacked 9500' ROR Unstacked 9500' Unstacked 12000' Stacked 9500' Stacked 12000' LOE ($/Mcf) 0.10 0.10 0.05 0.05 Gathering rate ($/Mcf) 1.13 1.13 0.46 0.46 CAPEX ($ in millions) 8.4 9.8 8.3 9.7 Note: Example based on Richhill SWPA Marcellus and Utica development employing wet/dry blending strategy foregoing processing costs. (1) Based on $2.00 gas price. 26

Technological Advances Driving Tangible Results STACKED PAY FACTORY PORTFOLIO NAV OPTIMIZATION EARTH MODEL Fully integrated subsurface model Neural net drives productivity indicators Drove understanding of three Utica areas DATA ACQUISTION Core, logs, seismic Third party data Delineation Testing Seismic de-risks SWPA stacked pay development and improves NAV by $60 million DESIGN OPTIMIZATION Reservoir and frac modeling Managed pressure drawdown via rate transient analysis Machine learning Managed pressure drawdown improves EUR by 20% Designs are optimized in 3 wells vs. 13 System modeling Linear programming Improves field NPV by 30% Big data analysis Ensures highest NPV combination of fields while balancing risk 27

Three Utica Areas Require Distinct Development Plans OHIO UTICA Manufacturing play 3.2 Bcf/1,000 80 of pay Low fracture intensity Optimized 10,500 laterals GAUT 4I MARCHAND 3M CPA UTICA Stacked pay play within the Utica and Point Pleasant 3.5+ Bcf/1,000 300 of pay in Utica, Point Pleasant and Lexington 13,200 TVD 10,500 TVD SWITZ FIELD RHL 11 GH 9 SWPA UTICA Stacked pay factory with Marcellus 3.2 Bcf/1,000 80 of pay Intermittently fractured 12,000 TVD 28

The Utica is a Precision Play OHIO (SWITZ) SWPA (RHL11E) CPA (Marchand3M) Understanding reservoir characteristics in combination with facies drives productivity 29

Ohio Utica Model Drove SWPA and CPA Success The model drove early success and eliminated the need for trial and error testing Ohio Utica is the analogue model for rapid SWPA and CPA Utica optimization Optimization of variable sand loading up to 3,000 lbs/ft within variable inter-lateral spacing up to 1,500 Tail-in ceramic proppant Landing point defined by area - Modeling defines target zone in a highly siliceous area to maximize both drilling efficiency and well productivity Legacy Base Optimized Fracture Conductivity (md-ft) 30

Capital ($ in millions) SWPA Utica: Very Strong Early Results from Richhill 11E Richhill 11E SWPA Utica well currently flowing above 3.2 Bcfe/1000 type curve Drilled through series of natural fracture clusters, which were identified in 3D seismic analysis Required more drilling days than the expected run rate, which elevated drilling costs - Elevated drilling costs offset by productivity of the well due to natural fracture clusters Other additional costs related to completion design testing drove the RHL11E well to exceed target capital costs, but there is clear line of sight to the projected $14.3 million RHL11E Summary Lateral length (1) 6,200 Total capital less science Average flowing pressure Average production (2) Target flowing production @ flat first 12 months $21 million 8,445 psig 22.1 MMcf/d 18 MMcf/d $25 $20 $15 $10 $5 $0 Most Recent SWPA Utica Well on Path to Target Capital Drilling Completions Water, Construction, and Other Total RHL11E Actual AFE, less Science SWPA Utica Target Capital (3) (1) Measured perforation to perforation. (2) As of 3/8/2018. Turned in line 2/17/2018, excludes first four days of flowback/clean up. (3) Normalized for lateral length to align with 6,200 RHL11E (target capital lateral length in SWPA Utica is 8,500 ft. 31

SWPA Utica Requires Engineered Design Success is consistently hitting repeatable results by: - Drilling on seismic - Managed pressure drilling - Cyber steering to improve in-zone statistics - Customized well layouts - Engineered completion designs to optimize for natural fractures and over-pressured faults Target well cost in SWPA Utica: $14.3 million Onondaga Point Pleasant 32

SWPA Region Overview: Greater and Central SWPA Central Marcellus Utica Undeveloped Net Locations 391 438 EUR (Bcfe/1000 ) (1) 2.8 3.2 Total NRI 87% 89% Total PDPs 182 1 Net Current Production (Bcfe/d) 0.412 0.004 Core focus area for future development Stacked pay approach for increased returns SWPA Greater Marcellus Utica Undeveloped Net Locations 191 231 EUR (Bcf/1000 ) (1) 2.7 3.0 Total NRI 91% 91% Total PDPs 12 - Net Current Production (Bcfe/d) 0.082 - ACAA development drives SWPA Greater, with two pads completed to date Richhill Field Wadestown Morris Field Note: See appendix slide 104 for peer capital efficiency comparison. (1) See appendix slides 108 and 109 for complete modeling assumptions and type curve. 33

TILs SWPA Central: Focus of Activity in Three-Year Plan Morris Production Legacy vs. Now SWPA Marcellus TILs: 2017 vs. Three-Year Plan 80 73 70 60 55 50 46 40 30 20 11 10 0 2017 2018E 2019E 2020E Average EUR/1,000 increased 77% from legacy Morris wells (1) - Morris-30 completed with enhanced stimulated reservoir design - Increased proppant loading, min/max stress optimization along with the mechanical diversion testing program - Changed targeted section of Marcellus to be drilled Morris pads being designed for future stacked pay development Morris wells expected to make up more than 65% of 2018E SWPA Marcellus TIL activity SWPA Marcellus comprises a much larger portion of the threeyear plan than in 2017 - Activity in the Morris, Richhill, and Wadestown fields driving the increase - Plan to run 2-3 rigs in region throughout the time period ~80% of three-year plan activity located in SWPA Central Marcellus/Utica (1) Legacy Morris comprised of 21 wells TIL March 2012-June 2013; Morris 30 pad comprised of 5 wells TIL mid-2017. 34

Does Not Require Processing BTU Content Requires Processing Blending Strategy Helps Drive DevCo I Stacked Pay Economics 1200 Wet Marcellus Gas Damp acreage requires processing to meet BTU specifications 1150 Damp Marcellus Gas 1110 Dry Tariff Line 1100 1070 1040 Dry Utica/Marcellus Gas Blended Gas = Damp Marcellus + Dry Utica/Marcellus Avoids processing cost of $0.55-0.60/Dth Meets BTU tariff - One Utica well required for every 3-4 damp Marcellus wells 1010 Note: Defined as Dry Utica 1010-1040 BTU; Dry Marcellus 1060-1110 BTU; Damp Marcellus 1110-1150; Wet Marcellus 1150+ BTU. 35

Existing Pad (Low Pressure) CHOKED Standard Gathering System Existing Pad (Low Pressure) Low Pressure Pipe High Pressure Pipe Two Pipe Gathering System Creates Flexibility in DevCo I Industry Standard One-Pipe System CNX DevCo I Two-Pipe System As new high pressure wells are TIL, higher pressure gas supplants older low pressure wells choking back total production New Pad (High Pressure) The low pressure pipe provides the option to continue producing existing wells rather than interrupt production when new higher pressure wells are brought online New Stacked Pay Pad (High Pressure and Low Pressure) During stacked pay development, Marcellus and Utica wells can be brought online simultaneously or independently Most Marcellus producers lack the ability to rapidly bring on production as the single pipe systems stay near full capacity Compression / Dehydration Planned compressor stations will create flexibility to customize pressures in specific gathering lines and optimize marketing plans as the project matures 36

Richhill (RHL): Stacked Pay Development Premier stacked pay field in SWPA Central - CNX expects to develop wet Marcellus laterals in the northern corridor first - While the northern Marcellus corridor is being developed, two dry Utica pads (MAJ6 and MAJ10) will be developed to blend wet Marcellus - Marcellus development will continue after the wet northern corridor is complete, with the second corridor being blended with Utica - Utica development will follow behind Marcellus until completion RHL Development Case Study 30% NPV uplift due to stacked pay development CAPEX, OPEX, and cycle time savings from shared infrastructure increase returns on both formations CNX s blending strategy provides significant uplift on top of the advantages of CAPEX, OPEX, and cycle time reduction Marcellus Utica Stacked Well Count 96 144 240 Capex ($ in millions) $816 $1,944 $2,700 NPV ($ in millions) $497 $809 $1,616 BTAX IRR 48% 49% 59% 37

Rate (Mcf/d) Rate (Mcf/d) CPA Dry Utica Update: Aikens 5J and 5M Aikens Wells EURs at 3.7 Bcf/1000 Located in Westmoreland County, PA (CPA South 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 3.58 Bcf through first 77 days Wells averaged 23 MMcf/d during first 77 days of production with average flowing pressure of 8,419 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 30000 25000 20000 15000 10000 5000 40000 35000 30000 25000 20000 15000 10000 5000 (1) Measured in lateral feet from perforation to perforation; average drilled length of 7,500. 0 0 Aikens 5J 0 100 200 300 400 500 600 700 Aikens 5J Actual (Mcf/d) Aikens 5M 0 100 200 300 400 500 600 700 Aikens 5M Actual (Mcf/d) Days 3.5 Bcf/1000' Type Curve Days 3.5 Bcf/1000' Type Curve 38

LEXINGTON POINT PLEASANT UTICA Stacked Utica with Utica in CPA Utica, Point Pleasant and Lexington are all gas bearing contributing zones with a total thickness of nearly 300 - Verified by the Marchand core and logs Potential to multiply Utica locations within CPA by stacking multiple wellbores in the 300 section to maximize recovery from the pay zone Simultaneous development of Utica stacked laterals may maximize recovery through pressure shadowing and eliminate future infill drilling 39

Perfect Pad to Create Stacked Pay Benchmark in 2019 Prior Days Target Days 120 90 122 97 142 78 31% Reduction 124 102 119 57 35% Reduction Process 12 Marcellus wells drilled Marcellus completions Dry month construction Subsurface Marcellus well heads 8 Utica wells drilled Utica completions M M M M M M M M M M M M Marcellus wells turned in line M M M M M M M M M M M M U U U U U U U U Utica wells turned in line Low Pressure Line Low Pressure Line High Pressure Line High Pressure Line Cellar technology construction allows for subsurface well heads for faster return 2018 Stacked Pay Baseline Lateral Length Increase Technology Utilization Mineral Purchase Optimization Data Analytics LOE Efficiencies 3D seismic drives well bore optimization Optimal inter-lateral spacing: Marcellus 750 ft, Utica 1200-1500 ft Two pipe system creates flexibility to produce high pressure and low pressure wells simultaneously Combined NPV Gains from Marcellus & Utica in SWPA Perfect Pad 2018 Stacked Pay Baseline $30.0 $10.9 $0.8 $6.4 $2.9 $0.4 Incremental NPV of ~$21 million ($ in millions) 40

Central PA Overview: North and South CPA South Marcellus Utica Undeveloped Net Locations 634 513 EUR (Bcf/1000 ) (1) 1.8 3.5 Total NRI 87% 87% Total PDPs 47 3 Net Current Production (Bcfe/d) 0.034 0.046 Gaut & Aikens wells have proved area for Utica development Potential to stack Marcellus with Utica Continue to explore opportunities to expand gathering infrastructure CPA North Marcellus Utica Undeveloped Net Locations 615 498 EUR (Bcf/1000 ) (1) 1.5 3.5 Total NRI 86% 86% Total PDPs 9 - Net Current Production (Bcfe/d) 0.005 - Currently delineating Utica to define Northern boundary driven from earth model (1) See appendix slides 112 and 113 for complete modeling assumptions and type curve. 41

Development Areas in Three-Year Plan OH Dry Utica CPA South Utica SHR/PENS Marcellus SWPA Central Marcellus and Utica 42

Bcfe Three-Year Drill Schedule and Estimated Reserves Growth Rig 1 Rig Schedule 2018E-2020E 2018 2019 2020 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Reserve Growth and Estimates 2015-2022E 16,000 14,500 14,000 Rig 2 12,000 12,000 12,500 Rig 3 Rig 4 10,000 10,000 10,000 Rig 5 8,000 8,500 Rig 6 6,000 7,582 TD Count 2018 2019 2020 Total SWPA Marcellus 62 60 71 193 SWPA Utica 3 19 27 49 WV Marcellus 5 10 15 30 CPA Utica 4 0 9 13 OH Utica 8 0 0 8 Total 82 89 122 293 4,000 2,000 0 5,643 6,251 2015 2016 2017 2018E 2019E 2020E Low High (1) Based on midpoint. 43

Three-Year Development Plan 2018E 2019E 2020E ($ in millions) TD FRAC TIL Capex TD FRAC TIL Capex TD FRAC TIL Capex SWPA Central WV Shirley-Penns Marcellus 62 48 46 60 52 55 71 78 73 Utica 3 1 1 19 14 14 27 28 28 Marcellus 5 5 5 10 10 7 15 11 11 Utica - - - - - - - - - CPA South Utica 4 4 2-1 3 9 5 3 OH Dry 8 10 15 - - - - - - Utica OH Wet (1) - 5 5 - - - - - - (2) (2) (2) Total 82 73 74 $790-$915 89 77 79 $1,010-$1,150 122 122 115 $1,200-$1,380 Notable Wells Greene County, PA Dry Utica: Richhill 11E TIL Feb. 2018 Indiana County, PA Dry Utica: Marchand 3M TIL set for Q3 2018 14 SWPA Central dry Utica wells 28 SWPA Central dry Utica wells 3 CPA deep dry Utica wells (1) 50% working interest. (2) Non-D&C capital for 2018E-2020E includes between $200-$300 million in each year associated with land, midstream, and water infrastructure. 44

Business Development Don Rush

$ in millions Track Record of Success: History of Monetizing Assets Annual average of ~$600 million in asset monetization from 2014-2017 $414 million in assets sold in 2017 2018 effort continues - Shirley-Pennsboro midstream asset drop netted $265 million in proceeds - Shallow Oil & Gas (SOG) transaction in February: $85 million in cash plus $190 million in liabilities related to gas well plugging (asset retirement obligations) Future opportunities include: Non-core upstream assets Drops to CNX Midstream CNXM LP Units and IDRs Shale acres not in near-term development plan $4,500 $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 Asset Sale Totals by Year Dry powder of ~$4 billion in drop down and other non-core asset sales from 2019-2022 provides substantial upside to current plan 46

SOG Sale Drives Continued Reduction in Legacy Liabilities Conventional Shallow Oil and Gas (SOG) assets sold in West Virginia and Pennsylvania, including CBM (1) Agreement signed mid-february - Expected close by end of March SOG Wells Included in Sale 11,000 wells Cash proceeds of $85 million Buyer assumed plugging and abandonment liabilities of $190 million - Found in asset retirement obligations on balance sheet Associated annual production of ~20 Bcfe Associated EBITDA with transaction of ~$14 million in 2018E due to partial year sale; typical SOG EBITDA between $15-$20 million per year; in addition, reduces annual cash servicing cost by $5 million (1) Excludes wells located in the Murray and CONSOL Energy development area. 47

CapEx ($) EUR (Mcf) Virginia Coalbed Methane (CBM): Upstream Low Risk Proven IRR ~270,000 contiguous acres, 100% WI 88% HBP, 87.5% NRI ~4,000 PDPs at 165 MMcf/d 2017 EBITDA of ~$100 million Future Potential 4,300 potential undeveloped CBM locations 1,532 Bcf Net CBM Resource Potential Lexington & Conasauga shows with a strong supporting analog 391 potential laterals at 10k ft length $400,000 Virginia CBM Capital Efficiency 600,000 $350,000 $300,000 $250,000 $200,000 500,000 400,000 300,000 $150,000 2014 2015 2016 2017 CapEx EUR 200,000 48

Ohio Utica Joint Venture Overview Low Risk, Mature Development 65% fee ownership, 46.5% avg. NRI (93% gross JV NRI) 31 gross operated JV wells (Noble County) 65 gross non-op JV wells, 47 non-op gross 3rd party wells ~85 MMcfe/d net production (~170 MMcfe/d net to JV production) 72% gas, 26% NGL, 2% condensate 36,000 gross acres Future Potential ~39,000 net core acres, 50% WI, (79,000 gross JV acres) 315 locations remaining (1) 3.95 Tcfe estimated total resource (7.9 Tcfe net to JV) 14,000 gross acres Strategic Options Sell the JV asset Divide assets to obtain 100% WI with JV partner Drill the assets per the governing agreements 29,000 gross acres (1) Excludes stranded acreage. 49

CNX MIDSTREAM ASSET AND OPPORTUNITY 50

$ in millions De-Risked CNX Midstream Growth Driving CNX Upside CNXM Distributable Cash Flows by Source 2017-2022E $300 $250 $200 Ability to sustain 15% CNXM distribution growth is projected without additional asset drops $150 $100 $50 $0 2017 2018E 2019E 2020E 2021E 2022E PDPs pre-s/p Drop Shirley-Penns MVC McQuay Activity Commitments(2) Activity Above MVC & Commitments Total Distributions Coverage Ratio (1) 1.25x 1.56x 1.44x 1.31x 1.21x (1) Assumes Shirley-Pennsboro drop effective as of 4/1/2018. (2) Represents activity at an illustrative 140 well development level. 51

$ in millions Drop Inventory Drives Meaningful Upside to CNXM 15% Growth CNX Retained Undropped EBITDA including Potential Drop Candidates 2017 vs. 2020E Potential Candidates 2018E-2020E $200 CONVEY Water Business $150 Existing DevCos Primarily Wadestown in DevCo III CPA Utica Gathering System $100 Cardinal States Gathering System $50 $- 2017 2017PF for S/P Drop 2020E Retained Undropped EBITDA Potential Completed Year-To-Date Shirley-Pennsboro system: February 2018 - $265 million: Expected to add $22-$24 million of pro forma 2018 EBITDA for CNXM growing to $40-$50 million in 2020E 52

Millions of Barrels (MMBbl) CONVEY: CNX s Water Business Projected Water Infrastructure: YE2018 Cumulative Water System CapEx ($ millions) PA WV OH Total $219 $94 $17 $330 Water Pipelines (miles) 189 79 33 301 Water Storage Facilities (MMBbl) 1.2 0.6 0.3 2.1 Total Water Moved (MMBbl) 33 4 8 45 SWPA Buildout Annual Volume of Water Moved 120 100 80 60 Wadestown 40 20-2017(A) 2018(E) 2018E 2019(E) 2019E 2020(E) 2020E PA WV OH 3rd Party 53

CONVEY: Major Projects Wadestown Development SWPA Water Build Out ~$65 million - 5 year CapEx spend NPV ~ $165 million, IRR ~ 120% Initial water infrastructure buildout 38 miles of new water infrastructure Eliminates seasonal water variability Uninterruptable water capacity for single completion crew ~$155 million 5 year CapEx spend NPV ~ $120 million, IRR ~ 80% 24 miles of new water infrastructure Uninterruptable water capacity capable of supplying two completion crews 54

CONVEY: Drives High Distribution Growth Rate ~$55 million water EBITDA at proposed rates in 2018 (1) Driven by margin on CNX fresh, reuse, and disposal rates Final rates to be determined at time of drop Produced water accounts for 18% of 2018 proposed EBITDA Over 100 miles of new water infrastructure to begin in 2018 Ohio River to SWPA fresh water supply line Richhill and Majorsville infrastructure Wadestown development infrastructure Fixed rates promote efficiencies for water operations CONVEY will continue to drive down costs to increase margins CNXM will benefit from cash flow stability Assumed Water Operating Costs ($/Bbl) (2) PA WV OH Fresh $0.95 $0.91 $1.62 Reuse $3.48 $4.78 $5.82 Disposal $8.12 $5.89 $7.11 $140 $120 $100 $80 $60 $40 $20 $- Steady Water EBITDA Growth (1) Infrastructure supply upgrade complete 2017 2018E 2019E 2020E (1) EBITDA assumes water costs above, but subject to change based on final set rates. With exception of third-party sales, CONVEY EBITDA is eliminated in CNX financial statements. Rates are determined based on 50% margin for fresh, 40% margin on reuse, and 30% margin on disposal (example costs below recent peer comparisons). (2) Water operating costs are based on historical averages in region and do not include infrastructure expenses. 55

$ in millions Drop Down Inventory: Wadestown Wadestown: Five-Year Investment Outlook Greenfield Marcellus and Utica dedication in DevCo III Wadestown metering and regulation Facility - New 1.2 Bcf/d Dominion interconnect - Wadestown compressor station - Total buildout horsepower 42,750 Pipelines: 39 miles Wadestown: Proposed Pipeline Buildout Expected Midstream Capital and EBITDA 2018E-2020E $160 $140 $120 $100 $80 $60 $40 $20 $0 2018E 2019E 2020E 2021E 2022E CapEx EBITDA 56

MMcf/d Drop Down Inventory: Central PA Midstream Buildout Central PA Utica: Five-Year Investment Outlook Currently undedicated to any midstream company Recent dry Utica well results proving commercial viability Opportunity to be first-mover midstream company to provide regional solution - Estimated 425,000 Mcf/d of throughput by 2022 Expected CPA Utica Throughput 2018E-2022E 450,000 400,000 350,000 300,000 250,000 200,000 150,000 100,000 50,000 0 2018E 2019E 2020E 2021E 2022E 57

Virginia Coalbed Methane: Midstream (Cardinal States Gathering) Best-in-Class and Location Interconnects TransCanada TCO pipeline to premium Enbridge ETNG pipeline system As is 40% of the 250 MMcf/d capacity available to gather 3 rd party gas and provide significant revenue source Provides premium market outlet for CNX and 3 rd party producers and shippers. Average basis differential of +$0.60/MMBtu Organic Value Creation Opportunity Premier drop opportunity into CNX Midstream Upsize throughput capacity from 250 to 385 MMcf/d with relatively minimal capital expenditure. Convert into a FERC regulated system to transport TCO shale gas to southern markets - Open Season 2/19/2018 to 3/2/2018; potential shippers being reviewed - System to be spun into new entity, CNX Transmission LLC, which will then file a certificate application to become an interstate pipeline subject to FERC jurisdiction 58

$ in millions CNX Midstream Ownership Valuation CNX Midstream drives value through four main avenues IDR cash distributions Ownership of LP units Retained EBITDA Future drop downs CNX Midstream Value to CNX ($ in millions, except per share data) 2018E 2020E IDRs Cash Flow (1) $ 12.7 $ 40.8 Multiple (2) 60.0x 30.0x Value $ 761 $ 1,223 LP Units Unit Price (3) $ 18.20 $ 30.19 Current Yield 7.5% 6.0% Units Held 21.69 21.69 Value $ 395 $ 655 (4) CNXM Represents Significant Growth for CNX in both IDRs and Retained EBITDA $4,000 $3,500 $3,000 $2,500 $2,000 $3,480 Pro Rata EBITDA Contribution Retained EBITDA (5) $ 10 $ 200 Market Multiple 8.0x 8.0x Value $ 80 $ 1,600 Total Potential Value $ 1,240 $ 3,480 $1,500 $1,000 $500 $1,240 Value per CNX Share (6) $ 5.60 $ 15.80 $- 2018E 2020E (1) See detailed IDR Model in appendix slide 100. (2) Reflects recent market comparisons. (3) Unit price as of market close on 3/8/2018. (4) 2020E unit price calculated using expected market yield of 6.0% on FY2020E distributions. (5) 2018E retained EBITDA pro forma for Shirley-Pennsboro drop. (6) Based on pro forma year-to-date share count of 219.8 million on 3/8/2018. IDRs LP Units Pro Rata Retained EBITDA Contribution 59

Marketing Chad Griffith

Marketing Overview FIRM TRANSPORTATION Selective FT commitments - Utilize basis hedges to create synthetic FT Fraction of the FT obligations compared to peers Low FT average demand costs of approximately $0.29 per MMBtu HEDGE STRATEGY Foundation that enables the execution of the company s strategy Differentiates CNX and provides competitive advantage Total hedge: matching basis to NYMEX Programmatic dollar cost averaging Hedge volumes in alignment with capital investment MARKET VIEW Current forward market Supply/demand balance Growing demand and exports Volatility is king 61

Total Obligations ($ in billions) Diff. to NYMEX Firm Transportation Strategy 1 2 3 Three-Filter Test for Taking on New FT Do we need it to get it to a liquid market? Does it get us to a better market at a positive net back? Does it help us manage the volatility of the markets we re in? $20.0 $18.0 $16.0 $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 Transportation, Gathering, & Processing Commitments and Differentials (2) $- $(0.50) $(1.00) $(1.50) $2.0 Project Examples: Future Spreads vs. Demand Charges (1) $0.0 CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 FT, Gathering, and Processing Obligations $(2.00) $0.800 $0.600 Gas Price Diff. to NYMEX Peer Average Gas Price Diff to NYMEX $0.400 $0.200 $0.000 2018 2019 2020 2021 2022 Project A Spread Project B Spread Project A Tariff Project B Tariff CNX realizes average NYMEX differentials with 1/8th of the average take-or-pay FT obligation of peers CNX instead uses a strategic mix of FT, IT, basis hedging, gathering system optionality, and capacity releases Note: Peers include AR, CHK, COG, EQT, GPOR, RRC, and SWN. (1) Project costs obtained from FERC filings; Spreads calculated using futures versus TETCO M2 pricing. (2) TG&P obligations and price differentials from SEC filings and other company reports (Q3 2017). 62

Liquidity of In-Basin Markets Negates Need for FT It is no longer essential to have in-basin FT capacity to sell gas due to the liquidity of the in-basin markets Gas can be reliably sold on M2 without taking on unnecessary and expensive FT commitments CNX expects to continue selling gas into M2 in line with historical proportional averages as seen below - These in-basin sales essentially supplement the low-cost FT book as it stands, as seen below Average Daily Production and Takeaway 2018E-2020E (Bcf/d) 2018E 2019E 2020E CNX Gas Production (1) 1.3 1.5 1.8 Less: Estimated Production Sold Directly into Basin (M2) (2) not requiring FT 0.3 0.3 0.4 Gas Production Sold via FT 1.0 1.2 1.4 Current FT Capacity 1.2 1.5 1.4 (1) Based on midpoint of guided range. (2) Based on recent results. Approximately 80% of CNX production nominated to FT. 63

Peer Firm Transportation Benchmarking Total FT and Processing Commitments $18.4 Total FT Commitments + 2018E Adjusted Net Debt (1)(2)(3) $18.7 $21.7 $7.1 $8.9 $11.6 $10.8 $12.2 $1.1 $1.8 $3.7 $2.1 $2.7 $5.6 CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 (FT Commitments + 2018E Adjusted Net Debt) / (FT Commitments + 2018E Adjusted Net Debt) / 2018E EBITDAX (1)(2)(3)(4) Adjusted EV (1)(2)(3) 11.1x 8.3x 9.0x 180% 198% 5.2x 6.2x 139% 141% 1.7x 3.1x 18% 48% 72% Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Note: Peers include AR, COG, EQT, GPOR, RRC, and SWN. FT and processing commitments are off-balance sheet. (1) CNX commitments as of 12/31/2017. Peer group commitments as of 9/30/2017. (2) CNX debt as of 12/31/2017. Peer group debt as of 9/30/2017. (3) Adjusted for remaining 2017E and 2018E outspend and present value of hedges. Outspend calculated as EBITDAX capex interest. (4) CNX 2018E EBITDAX per company projections. Peer group 2018E EBITDAX per FactSet consensus estimates as of 2/13/2018. 64

000s MMBtu/d Differentiated Firm Transportation Portfolio 1,600 1,400 1,200 1,000 800 600 400 200 M2 WLA M3 ELA Michcon TCO Pool ETNG Dominion South - Jan 18 Jan 19 Jan 20 Jan 21 Jan 22 TCO Pool includes: 200,000 MMBtu/d on TCO s Mountaineer XPress project and 50,000 MMBtu/d of capacity on TCO s Leach XPress project in connection with the Marcellus JV dissolution Avg. Demand Cost ($/Dth) (000s Dth/d) 2018E 2018E DOM South 345 ETNG 201 TCO Pool 475 Michcon 162 TETCO ELA 30 TETCO WLA 50 TETCO M3 100 TETCO M2 125 1,488 $0.29 Unutilized FT (reported in Other Operating Expense ) Approximately 370,000 MMBtu/d in unused FT on Dominion South and TCO - Acquired as part of Dominion transaction in 2010 - Current drilling plans do not consider geographic area where unutilized FT resides Forecasted for 2018E at approximately $36 million - Expect to offset expense by reselling approximately $10 million per year Contracts expire in 2021 and 2022 Note: Not all production requires reserved capacity. For example, certain receipt point sales are sold into gathering systems requiring no interstate FT, certain M2 and M3 sales use capacity held by others, and some production is transported under IT arrangements. 65

Natural Gas Basis Risk and Financial Reporting Clarity Fully-hedged volumes provide revenue certainty and de-risks capital expenditures CNX hedges basis in addition to NYMEX Peers primarily only hedge NYMEX, which is a partial hedge - Completely exposed to floating basis risk $- Historical Basis Volatility Basis hedging and hedge reporting example October NYMEX settles @ $3.30 & M2 Basis settles @ ($1.10); M2 price of $2.20 Hedge Reporting Example CNX Company A NYMEX Hedge $3.00 $3.00 Basis Hedge ($0.50) None $(0.50) $(1.00) $(1.50) $(2.00) $(2.50) TETCO M2 Basis Dominion South Basis Historical basis derived by first of month settle prices indicates extreme volatility over the past two years - Basis varies between $(0.39) and $(2.11) over two year stretch (1) Henry Hub Settle $3.30 $3.30 M2 Basis Settle ($1.10) ($1.10) NYMEX Hedge Payout ($0.30) ($0.30) M2 Basis Hedge Payout +$0.60 n/a Physical Gas Sale Price +$2.20 +$2.20 Actual Realized Sale Price $2.50 $1.90 CNX would report fully-hedged price of $2.50 and receive $2.50 Company A would report hedged price of $3.00, but receive only $1.90 (1) IFERC First of Month pricing. 66

Bcf/d Bcf/d Power Plants and LNG Driving Demand Growth 14.7 Bcf/d incremental demand from gas fuel type power plants by 2025 CNX acreage in the center of the largest growth market, PJM An additional 14.6 Bcf/d is proposed 16 14 12 10 8 6 4 2 Increased Gas Demand from Planned Power Plants 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 2017 2018 2019 2020 2021 2022 2023 2024 2025 13.9 Bcf/d LNG Export capacity by 2022 An additional 11.6 Bcf/d is proposed without a target in-service date (1) Natural gas exports to Mexico via pipeline increased to 4.2 Bcf/d in 2017 (2) 20 18 16 14 12 10 8 6 4 2 0 LNG Expected Growth 2018-2022 1Q2018 3Q2018 1Q2019 3Q2019 1Q2020 3Q2020 1Q2021 3Q2021 1Q2022 3Q2022 In-Service Exports to Mexico 2018 2019 2020 2021 2022 (1) SNL (2) EIA 67

Bcf/d NE Expansion Projects Remove Export Bottleneck 20 Pipeline Expansion Project Takeaway Capacity 18 16 14 12 10 8 6 4 2 Supply Header Project Atlantic Coast Pipeline WB Xpress Mountaineer Xpress PennEast Nexus Project Atlantic Sunrise Rover Phase 2 Leach Xpress Other 0 Projected 18.7 Bcf/d basin takeaway capacity expected by 2019 Expected NE market takeaway projects to increase capacity by 12.2 Bcf/d in 2018 and an additional 6.5 Bcf/d in 2019 (1) (1) Company analysis. 68

Supply/Demand Fundamentals 2018 gas consumption expected to increase 3.5 Bcf/d to 77.5 Bcf/d and increase an additional 2.2 Bcf/d in 2019 (1) - 2018 HDD expected to be 11% higher than 2017 (1) - Power generation expected to increase 3.2 Bcf/d in 2018 Net exports expected to increase 1.9 Bcf/d in 2018 and an additional 2.3 Bcf/d in 2019 (1) - LNG exports expected to increase from 1.9 Bcf/d in 2017 to 3.0 Bcf/d in 2018 and ramp up to 5.5 Bcf/d by end of 2019 (1) - Natural gas exports to Mexico rose 0.4 Bcf/d in 2017 and expected to continue on same trajectory (1) - Natural gas imports expected to drop 0.3 Bcf/d in 2018 (1) - US was net exporter of natural gas in 2017 for first time since 1957 (1) 2017 storage dropped 6% below the five year average and is expected to be roughly 6% below five year average by end of 2019 (1) 2017 production of 73.5 Bcf/d remained flat relative to 2016 levels, but an increase of 6.9 Bcf/d is expected for 2018 (1) - Increase fueled by pipeline takeaway projects (1) Basin Demand Expected to Increase Roughly 6 GW of natural-gas fired power plant capacity in Pennsylvania in 2018 (1) 20 GW capacity in 2018 across US Percentage of electricity generation from natural gas expected to increase to 33.1% in 2018 from 31.7% in 2017 (1) Regional Basis Narrows as Takeaway Capacity and Demand Increase $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Henry Hub and Dominion South Pricing (Historical First of Month and Forward Strip) Henry Hub Dominion S (1) EIA Short-Term Energy Outlook. 69

Liquids and Processing Summary ACAA MarkWest Blue Racer Contracted Processing Capacity 365 MMcf/d Dominion Noble County Utica MarkWest Majorsville CNXM and other wet gathering systems provide optionality for CNX wet production Blue Racer Berne Blue Racer Natrium Shirley/Penns Dominion Hastings Richhill MarkWest Mobley Optionality provides many benefits, including: - Residue market optimization - Access to existing, excess processing capacity - Avoids being captive customer NGLs are generally marketed by processing companies more efficient to outsource NGL pricing guidance based on contracts in place, NGL forward market, CNX view of supply/demand/transportation fundamentals, and certain hedging programs of processing companies $13 million in unutilized processing commitments forecasted for 2018E 70

Finance Don Rush Chuck Hardoby

CNX ASSET BASE AND KNOWLEDGE SET Corporate Values Guide Decision Making NAV/SHARE FOCUS RESPONSIBILITY OWNERSHIP EXCELLENCE CORPORATE VALUES DISCIPLINED CAPITAL ALLOCATION STRATEGY ALIGNMENT OF STAKEHOLDER INTERESTS 31% FIVE YEAR EBITDAX CAGR (1) (1) 2017-2022E based on midpoint of financial guidance. 72

$ in millions Strategy Resulting In Substantial EBITDAX Growth Expected EBITDAX 2018E-2022E (1) $2,000 $1,800 $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 2018E 2019E 2020E 2021E 2022E Low High (1) Based on midpoint of financial guidance. Base plan assumes no additional drops or asset sales. 73

$ in millions Balance Sheet Capacity and Dry Powder Upside through 2022E $8,000 $7,000 $6,000 $5,000 $4,000 Balance Sheet Capacity ~$3 billion Dry powder of ~$4 billion through 2022E consists of potential drop proceeds, tax refunds, CNXM LP/GP monetization, and non-core asset sales $3,000 $2,000 $1,000 $- Drop Candidates Retained EBITDA @ 8x Multiple YE2017 Alternative Minimum Tax Refund ~$5 billion CNXM LP Unit/IDR Monetization Dry Powder ~$4 billion Non-Core Asset Sales Total Dry Powder + B/S Capacity @ 2.5x Leverage Ratio Balance sheet capacity at a steady 2.5x leverage ratio comprises another ~$3 billion in available capital 74

Gas Volumes Hedged (Bcf) Marketing: Natural Gas Hedging and Basis Protection 400 350 300 43.3 250 200 150 100 50 0 375.9 290.6 44 12.1 182 181.9 2018 2019 2020 2021 2022 NYMEX + Basis (2) NYMEX Only Hedges Exposed to Basis Hedge Volumes and Pricing Q1 2018 2018 2019 2020 2021 2022 NYMEX Hedges Volumes (Bcf) 88.4 358.6 321.0 215.0 172.6 153.4 Average Prices ($/Mcf) $3.14 $3.14 $3.02 $3.09 $3.00 $3.05 Physical Fixed Price Sales Volumes (Bcf) 4.3 17.3 12.9 11.0 21.4 13.8 Average Prices ($/Mcf) $2.61 $2.61 $2.49 $2.44 $2.45 $2.54 Total Volumes Hedged (Bcf) (1) 92.7 375.9 333.9 226.0 194.0 167.2 NYMEX + Basis (fully-covered volumes) (2) Volumes (Bcf) 92.7 375.9 290.6 182.0 181.9 94.9 Average Prices ($/Mcf) $2.76 $2.76 $2.69 $2.76 $2.53 $2.48 NYMEX Hedges Exposed to Basis Volumes (Bcf) - - 43.3 44.0 12.1 72.3 Average Prices ($/Mcf) - - $3.02 $3.09 $3.00 $3.05 Total Volumes Hedged (Bcf) (1) 92.7 375.9 333.9 226.0 194.0 167.2 (1) Hedge positions as of 2/20/2018. Q1 2018 and 2018 exclude 6.4 Bcf and 13.9 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. 72.3 94.9 Systematically layering in hedges out to 2022 to protect margins on proved developed production and a portion of PUDs (capex) Locking-in revenue and derisking 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) 75

Financial Guidance: 2018E-2020E 2018E 2019E 2020E Revenue and Other Operating Income E&P Consolidated E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 450-475 505-575 610-700 NGLs (MBbls) 7,500-7,700 6,800-7,400 6,800-7,400 Oil (MBbls) 15-20 15-20 15-20 Condensate (MBbls) 590-610 430-480 420-480 Total Production (Bcfe) 500-525 550-630 650-750 % Liquids 9%-10% 8%-9% 6%-7% Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40) ($0.35)-($0.45) ($0.40)-($0.50) NGL Realized Price ($/Bbl) $23.00-$24.00 $22.00-$23.00 $20.00-$21.00 Condensate Realized Price % of WTI 70% 70% 70% Oil Realized Price % of WTI 100% 100% 100% Realized Hedging Gain/(Loss) ($ in millions) (1) $85-$90 $30-$40 $30-$40 Other Operating Income (3 rd party water income and resold FT) ($ in millions) $15-$20 $15-$20 $15-$20 CNXM 3rd Party Gathering Revenue $80-$85 $65-$70 $60-$65 Costs Average per unit operating expenses ($/Mcfe): Lease Operating Expense $0.15-$0.18 $0.11-$0.13 $0.11-$0.12 Production, Ad Valorem, and Other Fees $0.06-$0.08 $0.05-$0.06 $0.07-$0.08 Transportation, Gathering and Compression $0.80-$0.85 $0.60-$0.65 $0.90-$0.97 $0.60-$0.65 $0.85-$0.95 $0.50-$0.60 Total Cash Production and Gathering Costs $1.01-$1.11 $0.81-$0.91 $1.06-$1.16 $0.76-$0.84 $1.03-$1.15 $0.68-$0.80 ($ in millions) Selling, General, and Administrative Costs (2) $85-$95 $95-$110 $85-$100 $100-$115 $85-$100 $100-$115 Exploration Expense $10-$15 $5-$10 $5-$10 Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70 $55-$60 $50-$55 Other Non-Operating Expense $15-$20 $10-$15 $10-$15 Total Capital Expenditures $790-$915 $875-$1,005 $1,010-$1,150 $1,335-$1,525 $1,200-$1,380 $1,275-$1,465 CNXM EBITDA Attributable to CNX $60-$65 $85-$95 $145-$165 EBITDAX $825-$850 $840-$1,000 $1,040-$1,200 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. 76

Financial Guidance: E&P 2018E 2018E Revenue and Other Operating Income E&P 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-$90 Other Operating Income (3 rd party water income and resold FT) ($ in millions) $15-$20 CNXM 3rd Party Gathering Revenue Costs Average per unit operating expenses ($/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 Total Cash Production and Gathering Costs $1.01-$1.11 ($ in millions) Selling, General, and Administrative Costs (2) $85-$95 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 CNXM EBITDA Attributable to CNX $60-$65 Basis calculated on 2018 market mix. Hedge gain/(loss) calculated on NYMEX and financial basis hedges 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 Royalty income, right of way sales, interest income and other all netted against bank fees, other corporate expense, and other land rental expense EBITDAX $825-$850 Note: Base plan assumes NYMEX as of 2/16/2017 of $2.78 per MMBtu + weighted average basis of ($0.36) per MMBtu. 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. No future hedging in forecast. (2) Excludes stock-based compensation. 77

Financial Guidance: 2018E E&P Revenue Buildup Volumes 2018E Revenue Realized Price Revenue ($ in millions) Natural Gas 462.5 Bcf $2.55 /Mcf $1,180 NGLs 7,600.0 MBbls $23.50 /Bbl $179 Condensate 602.5 MBbls $42.00 /Bbl $25 Oil 17.5 MBbls $60.00 /Bbl $1 Realized Hedging Gain/(Loss) $87 Total 512.0 Bcfe $2.87 /Mcfe $1,471 Average Daily 1,410.0 MMcfe/d Purchased Gas Sales $58 Other Operating Income Water Income (3rd party sales) $8 Gathering Income (resold unutilized FT) $9 Total Revenue and Operating Income $1,545 Note: See appendix for assumptions. Base plan assumes NYMEX as of 2/16/2018 of $2.78 per MMBtu + weighted average basis of ($0.36) per MMBtu. 78

Financial Guidance: 2018E Natural Gas Marketing Mix and Basis Michcon 2018E Gas: 6% CY18 Basis: ($0.21) DOM South Dawn Pipeline Projects 2018E Gas: 10% CY18 Basis: ($0.67) TCO Pool TETCO M2 2018E Gas: 10% 2018E Gas: 52% CY18 Basis: ($0.26) CY18 Basis: ($0.67) Northeast Pipeline Projects TETCO M3 2018E Gas: 6% CY18 Basis: $0.23 Market Volumes 2018E CY 2018 (000 MMBtu) Gas Sold (%) Basis DOM South 45,074 9% ($0.67) ETNG/Cascade Creek TZ5 9,097 2% $0.34 TCO Pool 46,899 10% ($0.26) TETCO ELA & WLA 6,112 1% ($0.09) TETCO M3 29,235 6% $0.23 TETCO M2 209,567 43% ($0.67) Michcon 28,315 6% ($0.21) Physical basis sales 112,945 23% $0.02 Total (000 MMBtu) 487,244 100% ($0.36) Total (MMcf) 463,000 TETCO ELA & WLA 2018E Gas: 5% CY18 Basis: ($0.09) Gulf Market Pipelines Southeast Pipeline Projects ETNG/Cascade Creek TZ5 2018E Gas: 11% CY18 Basis: $0.34 NYMEX $2.78 Weighted Average Basis (Not considering hedging) ($0.36) 2018E Average Realized Price (per MMBtu) $2.42 Conversion Factor (MMBtu/Mcf) 1.054 2018E Average Realized Price (per Mcf) $2.55 BTU Uplift $0.13 Percentages include physical sales Note: Forward market prices are as of 2/16/2018. 79

Financial Guidance: 2018E NGL Barrel Composition and Pricing Approximately $200 million in revenue 2018E 2018E liquids sold: - NGLs: 7,600 MBbls - Condensate: 603 MBbls - Oil: 18 MBbls 2018E: 9-10% total production expected to be liquids Total expected price for NGLs in 2018E of $23-$24/Bbl I-Butane 5% NGL Barrel Composition N-Butane 9% Natural gasoline 8% Propane 30% Ethane 48% Total weighted average price of liquids in 2017 was $25.53/Bbl Contractual obligations to recover ethane (INEOS) - Those contracts currently yield better pricing for the ethane than selling it as a natural gas equivalent Weighted Average NGL ($/Bbl) Low High Midpoint NGL $23.00 $24.00 $23.50 Condensate (% of WTI) Oil (% of WTI) 70% 100% 80

Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections CY2018 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (000 MMBtu) Price (1) Market ($/MMBtu) ($ in 000's) ($/MMBtu) NYMEX 377,775 $2.98 $2.78 $0.20 $74,668 Basis: DOM South (DOM) 30,100 ($0.60) ($0.67) $0.07 $2,030 ETNG Cascade Creek TZ5 0 $0.00 $0.45 $0.00 $0 ETNG Mainline 0 $0.00 $0.23 $0.00 $0 Chicago 0 $0.00 ($0.12) $0.00 $0 TCO Pool (TCO) 36,500 ($0.27) ($0.26) ($0.01) ($239) Michcon (NMC) 14,448 ($0.03) ($0.21) $0.18 $2,609 TETCO ELA (TEB) 5,475 ($0.09) ($0.09) $0.00 $27 TETCO WLA (TWB) 0 $0.00 ($0.08) $0.00 $0 TETCO M3 (TMT) 19,895 ($0.05) $0.23 ($0.28) ($5,547) TETCO M2 (BM2) 191,613 ($0.60) ($0.67) $0.07 $13,173 Total Financial basis 298,030 $12,053 In addition to NYMEX and basis financial hedges, CNX has physical fixed basis sales and physical fixed price sales with customers CY 2018 physical fixed basis sales: 89.6 Bcf CY 2018 physical fixed price sales: 17.3 Bcf Physical sales provide additional basis hedge - Flows through gas sales in financials Total Projected Gain/(Loss) $86,721 Note: Forward market prices are as of 2/16/2018. Hedged volumes and prices are as of 2/20/2018. Anticipated hedging activity is not included in projections. See Appendix for Q1 2018, 2019, and 2020 hedging gain/loss projections. (1) January and February are settled prices. 81

Financial Guidance: 2018E E&P EBITDAX Buildup $1,800 $1,600 Other Operating Income $1,400 $1,200 $1,000 $800 Purchased Gas Sales Realized Hedging Gain/(Loss) Natural Gas And Liquids Revenue $0.15-$0.18 / Mcfe $0.06-$0.08 / Mcfe $0.80-$0.85 / Mcfe $85-$95 million $50-$60 million $65-$70 million $15-$20 million E&P EBITDAX + Attributable CNXM EBITDA $825-$850 million CNXM EBITDA Attributable to CNX $60-$65 million $600 $400 E&P EBITDAX $200 $0 Total Revenue LOE Production, ad valorem Transportation, gathering, compression SG&A Purchased gas costs Other operating expense Other non-operating expense Total Adjusted EBITDAX Note: Based on midpoint of production and financial guidance range. Base plan assumes NYMEX as of 2/16/2018 of $2.78 per MMBtu + weighted average basis of ($0.36) per MMBtu. 82

$ in millions Financial Guidance: 2018E CNXM EBITDA Attributable to CNX $250 $200 $150 $100 Non-Controlling Interest $50 $60-$65 million $0 Total Revenue (100% of CNXM) Operating Expense General & Administrative EBITDA EBITDA Attributable to CNX 83

CAPITAL ALLOCATION OPTIONALITY DRIVING VALUE 84

Capital Allocation Optionality Drives NAV/Share In late 2015, committed to strengthening the balance sheet through focusing on NAV/share - Positioned company for significant growth as a premier E&P company in the Appalachian Basin Transitioned from a defensive posture to an offensive strategy as the strong balance sheet sets the platform for growth Buchanan Mine Sale January 2016 Balance Sheet Stabilization Marcellus JV Dissolution Capital Allocation Driven Non-Core Asset Divestitures Asset Optimization & Production Growth Coal Spin-Off Share Repurchases CONE GP Acquisition Debt Repurchases Balance sheet strength and financial flexibility allow CNX to choose its path forward via strategic capital allocation 85

Target Leverage Ratio Provides Capital Allocation Optionality IRR ANALYSIS Drill bit Share count reduction Balance sheet Bolt-on acquisitions 86

IRR Capital Allocation Optionality: Drill Bit IRR Opportunities Summary Assumptions Gas pricing: $2.50/MMBtu NGL pricing: $25/Bbl CND pricing: $45/Bbl Full Cycle Assumptions (1) Capital Expenditures (2) : - Includes D&C, midstream, water infrastructure and land Operating Expenses: - Includes lifting, gathering (3), utilized FT, general & administrative and production taxes Half Cycle Assumptions (1) Capital Expenditures (2) : - Includes only D&C and midstream Operating Expenses: - Includes only lifting, gathering (3) and production taxes 140% 120% 100% 80% 60% 40% 20% 0% 38% Full Cycle Portfolio IRR Summary: Five Year Plan 73% Half Cycle 36% Full Cycle 67% Half Cycle 138% Full Cycle 300% Half Cycle 25% Full Cycle Transaction Volume 36% 38% Half Cycle Full Cycle 75% Half Cycle SWPA CPA OH WV CNX Weighted Average Five-Year Plan Capital Allocation by Region SWPA 82% CPA 10% WV 6% OH 2% (1) See appendix slide 115 for full detailed assumptions for both half and full cycle economics. (2) Excludes sunk capex primarily applicable to OH. (3) Includes net CNXM gathering rates. 87

Shares Outstanding (millions) Market Cap ($ in millions) Capital Allocation Optionality: Share Buybacks As of: Q3 2017 End Year-End 2017 As of 3/6/2018 2018E-2022E Buyback Potential Share Reduction S/O: 230.1 million 223.8 million 219.8 million Additional 90+ million share reduction (2) 250 200 150 100 ~$110/share with drop proceeds (1) $10,000 $9,000 $8,000 $7,000 $6,000 $5,000 $4,000 $3,000 Prior to spin: - 6.4 million shares repurchased at average price of $16.08 (3) - Accounting for value of associated CEIX shares, repurchased shares have appreciated 36% compared to recent market prices (3) Since spin: - 4.0 million shares repurchased at an average price of $13.95 appreciated 28% compared to recent market prices (3) 50 - Potential share count reduction of ~60% by year-end 2022 including additional drop proceeds 2017 2018E 2019E 2020E 2021E 2022E Market Cap Shares Outstanding - Including Drop Proceeds Shares Outstanding - No Additional Sales/Drops $2,000 $1,000 $- Approximately $300 million remaining on share repurchase authorization for 2018 CNX refused to issue equity during the downturn when most of its peers did - As a result, longer term shareholders are seeing the benefit of the discipline compounded by the share repurchases happening now (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.. (2) Not including deployment of ~$1.8 billion of potential drop proceeds and tax refunds. (3) Shares repurchased as of market close 3/8/2018. Return calculation based on CNX and CEIX closing prices on 3/8/2018. 88

Long-Term Liabilities ($ in millions) Annual Cash Servicing Costs ($ in millions) Rehabilitated Balance Sheet Sets New Beginning Long-Term Liabilities Reduced by More than $4 Billion Over last Six Years $5,000 $500 $4,000 $3,000 $2,000 $400 $300 $200 2018E hedge book and production ramp sets clear path to <2.5x net debt / EBITDAX $1,000 $100 Long-term liabilities now <$60 million with annual cash servicing costs of <$5 million $0 2012 2013 2014 2015 2016 2017 2018E $0 Long-Term Liabilities Total Annual Cash Servicing Cost 89

Henry Hub EBITDAX Sensitivity ($ in millions) Capital Allocation: Balance Sheet CNX EBITDAX Less Sensitive to Commodity Swings Balance Sheet Highlights (1) YE 2017 YE 2018E $3.50 $3.00 Each $0.25 decline in HH price yields only a $35 million decline in 2018E EBITDAX $1,400 Total Debt Cash Net Debt $2,232 $1,980 $509 $25 $1,723 $1,960 $2.50 $2.00 $1,200 $1,000 $800 Leverage Ratio (2)(3) NTM 2.1x 2.1x $1.50 $600 Leverage Ratio (2)(4) LQA 2.5x - $1.00 $400 Leverage Ratio (3) - TTM 3.6x 2.4x $0.50 $200 $ in millions Total Liquidity $1,770 $1,700 $- $3.00 $2.75 $2.50 $2.25 $- Henry Hub EBITDA 2018E EBITDAX at $2.85 per MMBtu HH (1) Debt balances exclude portions attributable to CNXM. (2) Based on midpoint of financial guidance. (3) Based on guided EBITDAX for next twelve month period and current period net debt. (4) Last quarter annualized demonstrates EBITDA ramp in Q42017 impact on leverage ratio. Not shown for YE 2018E as CNX does not give quarterly guidance. 90

Tax Reform and NOLs Create Tailwind Tax reform law states that Alternative Minimum Tax (AMT) amounts can be refunded at 50% in first year - Expect to receive first proceeds in 2019: ~$95 million - Remainder of $188 million AMT refund expected over subsequent years - Total figure is an estimate and could increase Following the spin transaction, CNX retained the corporate tax attributes - Approximately $475 million in federal net operating losses (NOLs) with a cash value of about $95 million - NOLs prior to 2018 can be used to offset 100% of future taxable income - As a result, expect to pay no cash taxes for roughly 4-5 years Additional NOLs projected with sale of SOG that are likely to further delay cash tax obligation Intangible drilling costs (IDCs) will be 100% deductible in year one or can be amortized over five years - In conjunction with NOLs, IDCs create flexibility to minimize cash tax burden for many years Note: Deferred tax liability table from 2017 10-K p. 92. Deferred Tax Assets: December 31, 2017 2016 Alternative minimum tax $ 188,080 $ 219,872 Net operating loss - State 107,756 74,310 Net operating loss - Federal 99,524 144,450 Foreign tax credit 44,402 39,850 Gas well closing 16,648 20,512 Salary retirement 9,404 16,928 Capital lease 2,020 3,210 Gas derivatives 72,105 Other 33,697 48,961 Total Deferred Tax Assets 501,531 640,198 Valuation Allowance (136,576) (282,778) Net Deferred Tax Assets 364,955 357,420 Deferred Tax Liabilities: Property, plant and equipment (385,366) (450,695) Gas derivatives (15,248) Advance gas royalties (3,648) (5,824) Equity Partnerships (1,251) (2,237) Other (3,815) (3,760) Total Deferred Tax Liabilities (409,328) (462,516) Net Deferred Tax Liability $ (44,373) $ (105,096) 91

Ongoing Hedge Program Locking in Revenue and Returns IRR Analysis Growing NAV/Share Finance Summary: 2014-2018+ 2018+ 2014-2017 Company Transformation and Balance Sheet Repair Growing EBITDAX Drill Bit 2017 Share Repurchases Begin Drilling Program Expanded Balance Sheet Optionality Continued Share Repurchases Bolt-On Acquisitions 92

CNX is Designed and Managed Differently What about CNX s distinctive strategy drives value? Growing IRRs based on steady and reliable execution Early movers on stacked pay development Target 2.5x leverage ratio and balance sheet optionality Continued commitment to share count reduction CNXM growth opportunity beyond de-risked15% Strategy is reinforced by management philosophy, company values, incentive plans, and ownership 93

Q&A 94

Appendix

Stacked Pay: Pad Level Benefits SWPA Central stacked pay development of Utica and Marcellus yields the highest NAV/share Pay zone specific drilling & completion assignment reduces capital and increase efficiencies Pay zone development timing flexibility Increased pad utilization & efficiency - Planning work-flow delivers safe and efficient pad designs for high value stacked pay development - 6-10 wells per visit demonstrates the highest NAV/share Value loss mitigation utilizing refined development strategy - Sequential corridor development prevents subsurface reservoir interruption Reduces surface footprint of development by ~1000 acres 96

NPV ($ in millions) IRR (%) Stacked Pay: What are the Main Advantages? Reduces capital - Pre-spud capital nearly eliminated for second formation - Use existing fuel gas to power D&C operations Reduces cycle times - Pad & facilities already constructed - Midstream and water infrastructure already in place Reduces LOE - Driven by higher well count & concentrated volume - Maintenance efficiency on infrastructure Reduces gathering fees - Dry and wet gas can be blended to avoid processing fees - Combining formations reduces gathering rate on Utica - Processing flexibility to capture NGL upside in market 3D seismic de-risks & optimizes D&C across all pay zones Stacked Pay Pad Economics Example $350 140% $300 120% $250 100% $200 80% $150 60% $100 40% $50 20% $0 0% $2.00 $2.50 $3.00 Gas Price Unstacked NPV Stacked NPV Unstacked IRR % Stacked IRR % Marcellus Utica Unstacked Stacked Unstacked Stacked LOE ($/Mcf) 0.10 0.05 0.04 0.04 Gath. Rate ($/Mcf) 0.96 0.38 0.37 0.24 CapEx ($ in millions) 8.4 8.3 14.6 14.3 (1) Assumes six Marcellus laterals at 9,500 and six Utica laterals at 8,500. 97

Lateral Length (ft) Stacked Pay: Gas Blending Driving NAV/Share Midstream pipeline tariffs require Marcellus gas above 1110 BTU be processed Processing damp gas between 1100-1150 BTU range is NPV destructive Lateral Feet to Blend by BTU to Equal 1100 Solution: Develop dry Utica concurrent to damp Marcellus and blend to avoid processing - Avoids processing & increases gathering efficiency - Allows capture of BTU value of damp gas - Blending solutions drive long term synergies with CNXM Unstacked Stacked Delta Well Count 240 240 - CapEx ($ in millions) $2,761 $2,700 ($61) NPV ($ in millions) $1,306 $1,616 +$310 BTAX IRR 48.4% 59.4% +11.0% 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 1110 1120 1130 1140 1150 Marcellus BTU Utica Lateral Length Marcellus Lateral Length 98

PV10 ($ in millions/ft) Stacked Pay: Marcellus/Utica vs. Marcellus/Upper Devonian Normalized NPV (NPV/Foot) Stacked Pay with Marcellus and Utica yields a higher NPV than stacking Marcellus with Upper Devonian wells Stacking wet gas Marcellus wells with dry gas Utica wells gives the optionality to blend or process the gas depending on NGL market conditions An Upper Devonian well yields ~60% of the production of a Marcellus well for similar capital 4.50 4.00 3.50 3.00 2.50 2.00 1.50 1.00 0.50 - $2.00 $2.50 $3.00 Gas Price CNX Marcellus/Utica Stack Company A Marcellus/Upper Devonian Stack Stacked Pay CNX Marcellus/Utica Stack Company A Marcellus/Upper Devonian Stack LL 9500'/8500' 12000'/15000' EUR/Ft 2.8 / 3.2 2.4 / 1.5 LOE ($/Mcf) 0.10 0.10 CapEx ($ in millions) 8.3/14.1 11.0/10.8 Gathering Rate ($/Mcf) 0.46 0.46 99

Detailed IDR Model: Assuming 15% Distribution Growth GP + Floor Ceiling LP ShareIDR ShareIDR Share Minimum Quarterly Distribution (MQD) 0.212500 98% 2% 0% First Target Distribution 0.212500 0.244375 98% 2% 0% Second Target Distribution 0.244375 0.265625 85% 15% 13% Third Target Distribution 0.265625 0.318750 75% 25% 23% Thereafter 0.318750 50% 50% 48% Total LP Units 21.7 million 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22 Distribution Per LP Unit 0.2450 0.2540 0.2630 0.2724 0.2821 0.2921 0.3025 0.3133 0.3245 0.3360 0.3480 0.3604 0.3732 0.3865 0.4003 0.4145 0.4293 0.4446 0.4604 0.4768 0.4938 0.5114 0.5296 0.5484 0.5680 0.5882 0.6091 0.6308 Distribution Growth % 3.7% 3.5% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% 3.6% LP Take by Tier Minimum Quarterly Distribution (MQD) 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 0.2125 First Target Distribution 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 0.0319 Second Target Distribution 0.0006 0.0096 0.0186 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 0.0213 Third Target Distribution 0.0000 0.0000 0.0000 0.0068 0.0165 0.0265 0.0369 0.0477 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 Thereafter 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0057 0.0173 0.0292 0.0416 0.0545 0.0678 0.0815 0.0958 0.1105 0.1258 0.1417 0.1581 0.1750 0.1926 0.2108 0.2297 0.2492 0.2694 0.2904 0.3121 Total 0.2450 0.2540 0.2630 0.2724 0.2821 0.2921 0.3025 0.3133 0.3245 0.3360 0.3480 0.3604 0.3732 0.3865 0.4003 0.4145 0.4293 0.4446 0.4604 0.4768 0.4938 0.5114 0.5296 0.5484 0.5680 0.5882 0.6091 0.6308 GP Take by Tier Minimum Quarterly Distribution (MQD) 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 0.0043 Tier 1 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 0.0007 Tier 2 0.0001 0.0017 0.0033 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 0.0038 Tier 3 0.0000 0.0000 0.0000 0.0023 0.0055 0.0088 0.0123 0.0159 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 0.0177 Tier 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0057 0.0173 0.0292 0.0416 0.0545 0.0678 0.0815 0.0958 0.1105 0.1258 0.1417 0.1581 0.1750 0.1926 0.2108 0.2297 0.2492 0.2694 0.2904 0.3121 Total 0.0051 0.0067 0.0083 0.0110 0.0142 0.0176 0.0210 0.0246 0.0322 0.0437 0.0557 0.0681 0.0809 0.0942 0.1080 0.1222 0.1370 0.1523 0.1681 0.1845 0.2015 0.2191 0.2373 0.2561 0.2757 0.2959 0.3168 0.3385 Total Distributions 0.2501 0.2607 0.2713 0.2834 0.2963 0.3097 0.3236 0.3380 0.3567 0.3798 0.4037 0.4285 0.4541 0.4807 0.5083 0.5368 0.5663 0.5969 0.6285 0.6613 0.6953 0.7304 0.7669 0.8046 0.8436 0.8841 0.9260 0.9694 GP Take 2.0% 2.6% 3.1% 3.9% 4.8% 5.7% 6.5% 7.3% 9.0% 11.5% 13.8% 15.9% 17.8% 19.6% 21.2% 22.8% 24.2% 25.5% 26.7% 27.9% 29.0% 30.0% 30.9% 31.8% 32.7% 33.5% 34.2% 34.9% LP Take 98.0% 97.4% 96.9% 96.1% 95.2% 94.3% 93.5% 92.7% 91.0% 88.5% 86.2% 84.1% 82.2% 80.4% 78.8% 77.2% 75.8% 74.5% 73.3% 72.1% 71.0% 70.0% 69.1% 68.2% 67.3% 66.5% 65.8% 65.1% LP Units O/S 58.34 58.34 58.34 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 63.53 GP + IDR Distributions ($MM) 0.30 0.39 0.48 0.70 0.90 1.12 1.34 1.57 2.04 2.78 3.54 4.33 5.14 5.98 6.86 7.76 8.70 9.67 10.68 11.72 12.80 13.92 15.07 16.27 17.51 18.80 20.13 21.51 Annual GP+IDR Distribution ($MM) $1.87 $4.92 $12.69 $25.75 $40.78 $58.06 $77.94 Annual LP Distribution ($MM) $29.71 $34.17 $39.30 $45.20 $52.00 Total Distributions to CNX $42.39 $59.92 $80.08 $103.27 $129.94 Note: Distribution targets found on page 79 of CNX Midstream 2017 10-K. 100

Guidance: Natural Gas Hedging Gain/Loss Projections ($/MMBtu) Q1 2018 CY2018 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (000 MMBtu) Price Market (1) ($/MMBtu) ($ in 000's) (000 MMBtu) Price Market (1) ($/MMBtu) ($ in 000's) NYMEX 93,150 $2.98 $2.98 ($0.00) ($274) 377,775 $2.98 $2.78 $0.20 $74,668 Basis: DOM South (DOM) 8,100 ($0.61) ($0.57) ($0.04) ($351) 30,100 ($0.60) ($0.67) $0.07 $2,030 ETNG Cascade Creek TZ5 0 $0.00 $1.10 $0.00 $0 0 $0.00 $0.45 $0.00 $0 ETNG Mainline 0 $0.00 $0.55 $0.00 $0 0 $0.00 $0.23 $0.00 $0 Chicago 0 $0.00 $0.28 $0.00 $0 0 $0.00 ($0.12) $0.00 $0 TCO Pool (TCO) 9,000 ($0.27) ($0.25) ($0.02) ($164) 36,500 ($0.27) ($0.26) ($0.01) ($239) Michcon (NMC) 3,600 ($0.03) ($0.11) $0.08 $282 14,448 ($0.03) ($0.21) $0.18 $2,609 TETCO ELA (TEB) 1,350 ($0.09) ($0.09) ($0.00) ($2) 5,475 ($0.09) ($0.09) $0.00 $27 TETCO WLA (TWB) 0 $0.00 ($0.06) $0.06 $0 0 $0.00 ($0.08) $0.00 $0 TETCO M3 (TMT) 6,145 $0.09 $2.33 ($2.24) ($13,762) 19,895 ($0.05) $0.23 ($0.28) ($5,547) TETCO M2 (BM2) 47,925 ($0.60) ($0.52) ($0.08) ($3,827) 191,613 ($0.60) ($0.67) $0.07 $13,173 Total Financial basis 76,120 ($17,824) 298,030 $12,053 Total Projected Gain/(Loss) ($18,098) $86,721 CY2019 CY2020 ($/MMBtu) 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) NYMEX 341,275 $2.84 $2.76 $0.09 $29,256 231,495 $2.87 $2.77 $0.10 $22,455 Basis: DOM South (DOM) 32,850 ($0.58) ($0.59) $0.00 $71 16,470 ($0.59) ($0.60) $0.01 $105 ETNG Cascade Creek TZ5 0 $0.00 $0.45 $0.00 $0 0 $0.00 $0.45 $0.00 $0 ETNG Mainline 0 $0.00 $0.23 $0.00 $0 0 $0.00 $0.23 $0.00 $0 Chicago 0 $0.00 ($0.27) $0.00 $0 0 $0.00 ($0.20) $0.00 $0 TCO Pool (TCO) 43,800 ($0.33) ($0.37) $0.04 $1,911 32,940 ($0.35) ($0.43) $0.08 $2,530 Michcon (NMC) 20,683 ($0.13) ($0.31) $0.18 $3,622 24,553 ($0.13) ($0.25) $0.13 $3,075 TETCO ELA (TEB) 7,300 ($0.09) ($0.09) $0.00 $0 7,320 ($0.09) ($0.08) ($0.01) ($49) TETCO WLA (TWB) 7,300 ($0.08) ($0.09) $0.01 $61 7,320 ($0.08) ($0.09) $0.00 $32 TETCO M3 (TMT) 4,563 $0.07 $0.03 $0.04 $187 0 $0.00 ($0.02) $0.00 $0 TETCO M2 (BM2) 83,950 ($0.59) ($0.59) ($0.01) ($431) 42,090 ($0.58) ($0.61) $0.03 $1,297 Total Financial basis 200,445 $5,421 130,693 $6,990 Total Projected Gain/(Loss) $34,676 $29,444 Note: Forward market prices are as of 2/16/2018. Hedged volumes and prices are as of 2/20/2018. Anticipated hedging activity is not included in projections. (1) January and February are settled prices. 101

Asset Portfolio Overview Marcellus Utica SWPA WV CPA OH Total SWPA WV CPA OH Total Total Net Acres 117,000 95,000 303,000 16,000 531,000 157,000 135,000 235,000 125,000 652,000 Net Developed Acres 21,600 5,900 6,100 200 33,800 100 0 400 20,000 20,500 Net Undeveloped Locations 582 190 1,249 102 2,123 669 511 1,011 161 2,394 PDP 194 42 56 1 293 1 0 3 114 118 2017 Exit Rate (Bcfe/d) 0.494 0.178 0.039 0 0.711 0.004 0 0.046 0.399 0.449 Virginia CBM ~270,000 contiguous acres, 100% WI 88% HBP, 87.5% NRI ~4,000 PDPs at 165 MMcf/d Note: 2017 Exit Rate is the average production per day for the month of December 102

Shirley-Pennsboro: Asset and Development Overview System Operating Area Shirley-Pennsboro Capital Efficiency Shirley Pennsboro (1) Assumes ethane extraction for forecasts and type curves. (2) CNX operated wells, legacy JV construction and drilling capital included in capital efficiency. Capital Efficiency (Mcfe/$) (1) 4 3 2 1 0 1.90 Mcfe/$ 2.33 Mcfe/$ 2.79 Mcfe/$ Legacy JV CNX (2) CNX Future Development Shirley-Pennsboro Wells CNX s future development represents a 47% increase in capital efficiency (Mcfe/$) compared to legacy wells - 28% increase in EUR/1000 driven by enhanced stimulated reservoir design and optimization of inter-lateral spacing - EUR/1,000 : Shirley 3.0 Bcfe; Pennsboro 2.6 Bcfe - BTAX IRR at $2.50 realized price: Shirley 38%; Pennsboro 35% - 18% decrease in fully-loaded D&C capital per lateral foot compared to the legacy JV wells Reduced capital driven by operational excellence: - Achieved record completion speed of 2,250 ft/day or 10+ stages in a 24 hour period - Achieved record drill-out speed of 8,400 ft/day The Shirley-Pennsboro field contains 50+ future wells that will be part of the core development plan Expected to add $22-$24 million of pro forma 2018 EBITDA for CNXM growing to $40-$50 million in 2020E 103

Capital Efficiency (Mcfe/$) Leading Capital Efficiency in SWPA Marcellus Company EUR (Bcf/1000 ) Well Capital Lateral Length Total EUR Capital Efficiency (Mcfe/$) CNX 2.8 $8,300,000 9,500 26.79 3.23 Peer 1 2.4 $9,050,000 9,500 22.80 2.52 3.500 SWPA Capital Efficiency 3.000 2.500 2.000 1.500 1.000 0.500 - CNX Peer EQT1 Note: Peer data from company filings. 104

WV Region Overview: Shirley-Pennsboro and East WV Shirley-Penns Marcellus Utica Undeveloped Net Locations 85 77 EUR (Bcfe/1000 ) 3.0 2.8 Total NRI 85% 87% Total PDPs 42 - Net Current Production (Bcfe/d) 0.178 - Strong well results from enhanced completion techniques High BTU area that supplies liquids to portfolio WV East Marcellus Utica Undeveloped Net Locations 105 434 EUR (Bcfe/1000 ) 2.4 2.8 Total NRI 90% 88% Total PDPs - - Net Current Production (Bcfe/d) - - Utica delineation can unlock tremendous value based on acreage held 105

Asset Region 4: Ohio Overview OH Wet Marcellus Utica Undeveloped Net Locations - 135 EUR (Bcfe/1000 ) - 2.1 Total NRI - 42% Total PDPs - 59 (Hess) 31 (CNX) Net Current Production (Bcfe/d) - 0.086 Joint Venture with Hess OH Dry Marcellus Utica Undeveloped Net Locations 100 26 EUR (Bcf/1000 ) - 3.2 Total NRI 85% 85% Total PDPs 1 24 Net Current Production (Bcfe/d) - 0.313 Fueling current growth with four pads remaining Increased type curves and returns driven by wider spacing OH Dry Utica Locations decreased due to Jefferson County sale in Q1 2017, increased spacing assumptions, and increased activity in 2017 106

Capital Efficiency ($/Mcfe) Peer Benchmarking: Ohio Region - Dry Company EUR (Bcf/1000 ) Well Capital Lateral Length Total EUR (BCF) Capital Efficiency (Mcfe/$) CNX 3.2 $10,500,000 9,000 28.71 2.73 Peer 1 2.2 $9,056,250 9,000 19.80 2.19 Peer 2 2.6 $9,990,000 9,000 23.40 2.34 Peer 3 2.1 $10,832,000 9,000 18.90 1.75 3.000 Ohio Dry Utica Capital Efficiency 2.500 2.000 1.500 1.000 0.500 - CNX Eclipse Peer 1 Gulfport Peer 2 EQT Peer 3 Note: Peer data from company filings. 107

Gas Production (Mcf/m) Gas Production (Mcf/m) SWPA Central Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 26.8 Inlet BTU 1075 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 87% Net Locations ~391 Wells Online (12/31/17) 182 Reserves Detail Gross EUR (bcfe) 26.8 Inlet BTU 1020 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 89% Net Locations ~438 Wells Online (12/31/17) 1 Assumptions IP (MMcf/d) (3 mo. flat) 15.9 Decline 57% B-factor 1.5 EUR/1000' (Bcfe) 2.8 Lateral Length 9500' Wells Per Pad 6 NGL Yield (Bbl/MMcf) - CND Yield (Bbl/MMcf) - Well Capital ($MM) $8.3 CNXM Sponsor Capital ($MM) $0.87 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Net Gathering ($/Mcf) $0.24 NGL OpEx ($/Bbl) - CND OpEx ($/Bbl) - Assumptions IP (MMcf/d) (11 mo. flat) 17.9 Decline 60% B-factor 1.2 EUR/1000' (Bcfe) 3.2 Lateral Length 8,500' Wells Per Pad 6 Well Capital ($MM) $14.3 CNXM Sponsor Capital ($MM) $0.58 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.16 SWPA SWPA Central Central Marcellus Type Type Curve (2.8 (2.8 Bcf/1000 ) Bcf/1000') 600,000 500,000 400,000 300,000 200,000 100,000 0 600,000 500,000 400,000 300,000 200,000 100,000 9500' LL 0 12 24 36 48 Months After TIL SWPA SWPA Central Utica Type Curve (3.2 Bcf/1000 ) Bcf/1000') (1) Assuming 9,500 ft lateral @ 750 ft inter-lateral spacing 0 (2) Assuming 8,500 ft lateral @ 1,200 ft inter-lateral spacing 0 12 24 (3) Escalation not applied to gas pricing, capex, and LOE Months After TIL (4) Escalation of 2.5%/year applied to gathering and compressor fees per contract 36 48 (5) Tier I Net Comp. fee of $0.040 applied after 1 year (Marcellus) (18 mo. for Utica) & Tier II (Marcellus only) additional fee of $0.040 applied after 3 years (6) Assuming NGL & CND pricing at $25/bbl & $45/bbl (7) See NGL and CND assumptions on type curve data file located at http://investors.cnx.com/events-and-presentations/events/2018. Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 8500' LL BTAX IRR% Price 9,500' $2.00 45% $2.50 75% $3.00 113% BTAX IRR% Price 8,500' $2.00 37% $2.50 64% $3.00 95% 108

Gas Production (Mcf/m) Gas Production (Mcf/m) SWPA Greater Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 25.8 Inlet BTU 1144 Outlet BTU 1081 Interest / Net Locations WI / NRI (%) 100% / 91% Net Locations ~191 Wells Online (12/31/17) 12 Reserves Detail Gross EUR (bcfe) 25.1 Inlet BTU 1023 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 91% Net Locations ~231 Wells Online (12/31/17) 0 Assumptions IP (MMcf/d) (3 mo. flat) 11.8 Decline 52% B-factor 1.59 EUR/1000' (Bcfe) 2.7 Lateral Length 9500' Wells Per Pad 6 NGL Yield (Bbl/MMcf) 23.6 CND Yield (Bbl/MMcf) - Well Capital ($MM) $8.3 CNXM Sponsor Capital ($MM) $0.22 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.07 Net Gathering ($/Mcf) $0.28 Processing ($/Mcf) $0.58 NGL OpEx ($/Bbl) $6.25 CND OpEx ($/Bbl) - Assumptions IP (MMcf/d)(7 mo. @7.5% exp de.) 18.1 Decline 61% B-factor 1.2 EUR/1000' (Bcfe) 3.0 Lateral Length 8,500' Wells Per Pad 6 Well Capital ($MM) $14.3 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.23 SWPA SWPA Greater Greater Marcellus Marcellus Type Type Curve Curve (2.7 (2.7 Bcfe/1000 ) Bcfe/1000') 500,000 400,000 300,000 200,000 100,000 0 700,000 600,000 500,000 400,000 300,000 200,000 100,000 9500' LL 0 12 24 36 48 Months After TIL SWPA SWPA Greater Greater Utica Utica Type Type Curve Curve (3.0 Bcf/1000 ) (3.0 Bcf/1000') (1) Assuming 9,500 ft lateral @ 750 ft inter-lateral spacing 0 (2) Assuming 8,500 ft lateral @ 1,200 ft inter-lateral spacing 0 12 24 36 48 (3) Escalation not applied to gas pricing, capex, and LOE Months After TIL (4) Escalation of 2.5%/year applied to gathering fees per contract (5) Assuming NGL & CND pricing at $25/bbl & $45/bbl (6) See NGL and CND assumptions on type curve data file located at http://investors.cnx.com/events-and-presentations/events/2018. Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 8500' LL BTAX IRR% Price 9,500' $2.00 26% $2.50 47% $3.00 72% BTAX IRR% Price 8,500' $2.00 33% $2.50 59% $3.00 91% 109

Gas Production (Mcf/m) Gas Production (Mcf/m NGL/CND Production (BBL/month) WV SHR/PENS Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 22.2 Inlet BTU 1260 Outlet BTU 1126 Interest / Net Locations WI / NRI (%) 100% / 85% Net Locations ~85 Wells Online (12/31/17) 42 Reserves Detail Gross EUR (bcfe) 19.7 Inlet BTU 1030 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 87% Net Locations ~77 Wells Online (12/31/17) 0 Assumptions IP (MMcf/d) 14.5 Decline 69% B-factor 1.65 EUR/1000' (Bcfe) 2.8 Lateral Length 8,000' Wells Per Pad 6 NGL Yield (Bbl/MMcf) 62.6 CND Yield (Bbl/MMcf) 25-7 Well Capital ($MM) $7.9 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.10 Net Gathering ($/Mcf) $0.61 Processing ($/Mcf) $0.51 NGL OpEx ($/Bbl) $4.75 CND OpEx ($/Bbl) $5.25 Assumptions IP (MMcf/d)(10 mo. @25% exp de.) 17.8 Decline 63% B-factor 1.2 EUR/1000' (Bcfe) 2.8 Lateral Length 7,000' Wells Per Pad 6 Well Capital ($MM) $14.4 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.23 WV SHR/PENS WV SHR/PENS Marcellus Marcellus Type Type Curve Curve (2.8 (2.8 Bcfe/1000 ) Bcfe/1000') 400,000 300,000 200,000 100,000 600,000 500,000 400,000 300,000 200,000 100,000 0 0 0 12 24 36 48 Months After TIL Gas NGL CND 50,000 40,000 30,000 20,000 10,000 WV SHR/PENS WV SHR/PENS Utica Type Utica Curve Type Curve (2.8 Bcf/1000 ) (2.8 Bcf/1000') (1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing 0 (2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing 0 12 24 36 48 (3) Escalation not applied to gas pricing, capex, and LOE Months After TIL (4) Escalation of 2.5%/year applied to gathering fees per contract (5) Assuming NGL & CND pricing at $25/bbl & $45/bbl (6) See NGL and CND assumptions on type curve data file located at http://investors.cnx.com/events-and-presentations/events/2018. Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 7000' LL BTAX IRR% Price 8,000' $2.00 29% $2.50 46% $3.00 65% BTAX IRR% Price 7,000' $2.00 14% $2.50 30% $3.00 50% 110

Gas Production (Mcf/m) Gas Production (Mcf/m) NGL/CND Production (BBL/month) WV East Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 19.4 Inlet BTU 1230 Outlet BTU 1113 Interest / Net Locations WI / NRI (%) 100% / 90% Net Locations ~105 Wells Online (12/31/17) 0 Reserves Detail Gross EUR (bcfe) 19.7 Inlet BTU 1030 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 88% Net Locations ~434 Wells Online (12/31/17) 0 Assumptions IP (MMcf/d) 13.5 Decline 69% B-factor 1.65 EUR/1000' (Bcfe) 2.5 Lateral Length 8,000' Wells Per Pad 6 NGL Yield (Bbl/MMcf) 54 CND Yield (Bbl/MMcf) 7-2 Well Capital ($MM) $7.9 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.10 Net Gathering ($/Mcf) $0.61 Processing ($/Mcf) $0.51 NGL OpEx ($/Bbl) $4.75 CND OpEx ($/Bbl) $5.25 Assumptions IP (MMcf/d)(10 mo. @25% exp de.) 17.8 Decline 63% B-factor 1.2 EUR/1000' (Bcfe) 2.8 Lateral Length 7,000' Wells Per Pad 6 Well Capital ($MM) $14.4 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.23 WV East WV Marcellus East Marcellus Type Type Curve Curve (2.5 (2.5 Bcfe/1000 ) Bcfe/1000') 400,000 300,000 200,000 100,000 600,000 500,000 400,000 300,000 200,000 100,000 0 0 0 12 24 36 48 Months After TIL Gas NGL CND 50,000 40,000 30,000 20,000 10,000 WV East WV East Utica Utica Type Type Curve Curve (2.8 (2.8 Bcf/1000 ) Bcf/1000') (1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing 0 (2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing 0 12 24 36 48 (3) Escalation not applied to gas pricing, capex, and LOE Months After TIL (4) Escalation of 2.5%/year applied to gathering fees per contract (5) Assuming NGL & CND pricing at $25/bbl & $45/bbl (6) See NGL and CND assumptions on type curve data file located at file located at http://investors.cnx.com/events-and-presentations/events/2018. Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 7000' LL BTAX IRR% Price 8,000' $2.00 18% $2.50 30% $3.00 46% BTAX IRR% Price 7,000' $2.00 15% $2.50 31% $3.00 52% 111

Gas Production (Mcf/m) Gas Production (Mcf/m) CPA South Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 16.1 Inlet BTU 1040 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 87% Net Locations ~634 Wells Online (12/31/17) 47 Assumptions IP (MMcf/d) 13.6 Decline 69% B-factor 1.65 EUR/1000' (Bcfe) 1.8 Lateral Length 9,000' Wells Per Pad 6 NGL Yield (Bbl/MMcf) - CND Yield (Bbl/MMcf) - Well Capital ($MM) $7.4 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Net Gathering ($/Mcf) $0.37 NGL OpEx ($/Bbl) - CND OpEx ($/Bbl) - CPA South CPA South Marcellus Marcellus Type Type Curve Curve (1.8 (1.8 Bcf/1000 ) Bcf/1000') 400,000 300,000 200,000 100,000 0 9000' LL 0 12 24 36 48 Months After TIL BTAX IRR% Price 9,000' $2.00 18% $2.50 33% $3.00 50% Reserves Detail Gross EUR (bcfe) 24.5 Inlet BTU 1010 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 87% Net Locations ~513 Wells Online (12/31/17) 3 Assumptions IP (MMcf/d)(14 mo. flat) 21.5 Decline 74% B-factor 1.2 EUR/1000' (Bcfe) 3.5 Lateral Length 7,000' Wells Per Pad 4 Well Capital ($MM) $13.1 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.23 CPA South CPA South Utica Utica Type Type Curve Curve (3.5 (3.5 Bcf/1000 ) Bcf/1000') 700,000 600,000 500,000 400,000 300,000 200,000 7000' LL 100,000 BTAX IRR% Price 7,000' $2.00 58% $2.50 104% $3.00 157% (1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and LOE (4) Escalation of 2.5%/year applied to gathering fees per contract Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 0 0 12 24 36 48 Months After TIL 112

Gas Production (Mcf/m) Gas Production (Mcf/m) CPA North Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 13.1 Inlet BTU 1012 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 86% Net Locations ~615 Wells Online (12/31/17) 9 Assumptions IP (MMcf/d) 11.1 Decline 69% B-factor 1.65 EUR/1000' (Bcfe) 1.5 Lateral Length 9,000' Wells Per Pad 6 NGL Yield (Bbl/MMcf) - CND Yield (Bbl/MMcf) - Well Capital ($MM) $7.4 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Net Gathering ($/Mcf) $0.36 NGL OpEx ($/Bbl) - CND OpEx ($/Bbl) - CPA CPA North North Marcellus Type Type Curve Curve (1.5 (1.5 Bcf/1000 ) Bcf/1000') 400,000 300,000 200,000 100,000 9000' LL 0 0 12 24 36 48 Months After TIL BTAX IRR% Price 9,000' $2.00 10% $2.50 19% $3.00 31% Reserves Detail Gross EUR (bcfe) 24.5 Inlet BTU 1010 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 86% Net Locations ~498 Wells Online (12/31/17) 0 Assumptions IP (MMcf/d)(14 mo. flat) 21.5 Decline 74% B-factor 1.2 EUR/1000' (Bcfe) 3.5 Lateral Length 7,000' Wells Per Pad 4 Well Capital ($MM) $13.1 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.23 CPA North CPA North Utica Utica Type Type Curve Curve (3.5 Bcf/1000 ) (3.5 Bcf/1000') 700,000 600,000 500,000 400,000 300,000 200,000 7000' LL 100,000 BTAX IRR% Price 7,000' $2.00 56% $2.50 100% $3.00 151% 0 0 12 24 36 48 (1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,200 ft inter-lateral spacing Months After TIL (3) Escalation not applied to gas pricing, capex, and LOE (4) Escalation of 2.5%/year applied to gathering fees per contract Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 113

Gas Production (Mcf/m) Gas Production (Mcf/m) NGL/CND Production (BBL/month) Ohio Modeling Inputs and Economics Reserves Detail Gross EUR (bcfe) 17.1 Inlet BTU 1170 Outlet BTU 1098 Interest / Net Locations WI / NRI (%) 50% / 42% Net Locations ~135 Wells Online (12/31/17) 90 Assumptions IP (MMcf/d) 11.9 Decline 62% B-factor 1.38 EUR/1000' (Bcfe) 2.1 Lateral Length 8,000' Wells Per Pad 4 NGL Yield (Bbl/MMcf) 36.8 CND Yield (Bbl/MMcf) 14-3 Well Capital ($MM) $8.0 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $1,000 LOE ($/Mcf) $0.19 Net Gathering/Processing ($/Mcf) $0.94 NGL OpEx ($/Bbl) $5.00 CND OpEx ($/Bbl) $5.75 400,000 300,000 200,000 100,000 OH Wet OH Utica Wet Type Curve (2.1 Bcfe/1000') Bcfe/1000 ) 0 0 0 12 24 36 48 Months After TIL Gas NGL CND 30,000 20,000 10,000 BTAX IRR% Price 8,000' $2.00 19% $2.50 33% $3.00 50% Reserves Detail Gross EUR (bcfe) 28.8 Inlet BTU 1030 Outlet BTU N/A Interest / Net Locations WI / NRI (%) 100% / 85% Net Locations ~26 Wells Online (12/31/17) 24 Assumptions IP (MMcf/d)(10 mo. @25% exp. de.) 22.5 Decline 60% B-factor 1.37 EUR/1000' (Bcfe) 3.2 Lateral Length 9,000' Wells Per Pad 4 Well Capital ($MM) $10.5 CNXM Sponsor Capital ($MM) - Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.04 Net Gathering ($/Mcf) $0.22 OH Dry OH Utica Dry Type Utica Curve Type Curve (3.2 Bcf/1000 ) (3.2 Bcf/1000') 800,000 700,000 600,000 500,000 400,000 300,000 200,000 9000' LL 100,000 BTAX IRR% Price 9,000' $2.00 74% $2.50 126% $3.00 189% (1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 9,000 ft lateral @ 1,350 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and LOE Note: NRI excludes potential amendments to existing leases and adverse or third party acreage within drilling units. 0 0 12 24 36 48 Months After TIL 114

Operating Expense CapEx Per Well Ownership Realized Pricing Half Cycle and Full Cycle Modeling Assumptions Portfolio Single Well Assumption Half Cycle Full Cycle Half Cycle Gas Price - $/MMBtu $2.50 Flat $2.50 Flat See Regional Detail NGL Price - $/Bbl $25.00 Flat $25.00 Flat See Regional Detail Condensate Price - $/Bbl $45.00 Flat $45.00 Flat See Regional Detail Hedging Excluded Excluded Excluded Working Interest See Regional Detail See Regional Detail See Regional Detail Net Revenue Interest See Regional Detail See Regional Detail See Regional Detail Well Capital See Regional Detail See Regional Detail See Regional Detail Midstream See Regional Detail See Regional Detail See Regional Detail Water Infrastructure Excluded $525,000 Per Well Excluded Land Excluded $700,000 Per Well Excluded Fixed Cost ($/mo./well) See Regional Detail See Regional Detail See Regional Detail LOE $/Mcf See Regional Detail See Regional Detail See Regional Detail Net Gathering ($/Mcf) - Adjusted for CNXM See Regional Detail See Regional Detail See Regional Detail NGL OpEx ($/Bbl) See Regional Detail See Regional Detail See Regional Detail CND OpEx ($/Bbl) See Regional Detail See Regional Detail See Regional Detail Utilized Firm Transportation Excluded $0.19/Mcf 5 yr weighted Avg. Excluded General and Administrative Costs Excluded $975,000 Per Well Excluded Production Taxes (Severance & Ad Valorem, PA Impact Fee) Applied Per State Applied Per State Applied Per State 115

CNX Midstream Partners Governance NYSE: CNX 100% CNX Gathering LLC 33.4% LP Interest 100% Public 41.9mm Common Units CNX Midstream GP LLC The General Partner Incentive Distribution Rights 2% GP Interest 95% LP Interest 64.6% LP Interest NYSE: CNXM 100% 5% GP Interest 5% GP Interest Anchor Systems (Development Co. 1) Growth Systems (Development Co. 2) Additional Systems (Development Co. 3) 116