Leverage Ratio Capacity Allows for Share Count Reduction Growing EBITDAX Creates Natural Capacity Available Capacity Reinvested within 2.5x Leverage Ratio in Share Count Reduction Cumulative available capacity of 3.0x $2,500 250 $10,000 ~$3 billion 2018-2022 ~$70/share $9,000 Steady State Leverage Ratio: 2.5x on baseline 2.5x capacity (1) $2,000 200 $8,000 2.0x $7,000 EBITDAX ($ in millions) Shares Outstanding (millions) Net Debt / EBITDAX $1,500 Market Cap ($ millions) 150 $6,000 ~$30/share (1) 1.5x $5,000 $1,000 1.0x 100 $4,000 $3,000 $500 0.5x Potential to reduce float ~40% by 50 $2,000 YE2022 under status quo plan or ~60% by YE 2022 with deployment 0.0x $0 of potential drop proceeds $1,000 2018E 2019E 2020E 2021E 2022E Available debt capacity at 2.5x leverage ratio for share buybacks - $- Net Debt / EBITDAX excluding share buybacks or asset sale proceeds 2017 2018E 2019E 2020E 2021E 2022E EBITDAX Range (1) Shares Outstanding Market Cap 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 12 ~$1.6 billion in potential drop proceeds and $0.2 billion in alternative minimum tax refund.
CNXM 15% Distribution Growth De-Risked CNXM Distributable Cash Flows by Source Expected CNXM Distributions to CNX 2017-2022E 2017-2022E $140 $300 $130 $120 $250 $103 $100 $200 $80 $ in millions $80 $ in millions $150 $60 $60 $42 $100 $40 $28 $50 $20 $0 $0 (1) 2017 2018E 2019E 2020E 2021E 2022E 2017 2018 2019 2020 2021 2022 PDPs pre-S/P Drop Shirley-Penns MVC LP Distribution to CNX (as Declared) McQuay Activity Commitments Activity Above MVC & Commitments GP & IDR Distribution (as Declared) Total Distributions (1) 2017 GP IDR at 50% ownership. 13
Compensation Plan Reinforces Strategy Long-Term Incentive Short-Term Incentive Program (PSUs) Compensation Program Compensation plans motivate 2016 Free Cash Flow management to execute on: ▪ Methodical operational execution 2017 Free Cash Flow ▪ Balance sheet discipline 50% 2018 & Adjusted EBITDA/Share ▪ Relative TSR (S&P 500) Basin disruption through stacked pay Beyond development Company-wide short-term 50% incentive plan Absolute Stock Price ▪ CNXM growth stability and upside Governed by 2.5x opportunities leverage ratio target Encourages return of ▪ Share count reduction capital to shareholders CEO compensation 90% at-risk (STIC, RSUs, and PSUs) 14
Importance of Both Numerator and Denominator in NAV/Share DIFFERENTIATED ASSET BASE NAV OPERATIONAL EXECUTION DRIVEN BY GROWING RESERVES VALUE OPTIMIZED VALUE OF MLP the NAV and IRR filters = PRUDENT ASSET MONETIZATION NAV/Share BALANCE SHEET & HEDGE BOOK Accretion & OUTSTANDING Recognition Share count reduction can SHARES be the best capital allocation decision if it passes through 15
Operations Tim Dugan Andrea Passman
Unique Stacked Acreage Portfolio Sets the Stage 531,000 ASSET BASE HIGHLIGHTS Total Net Marcellus Acres Vast multi-formation acreage position built over 150+ years 582 Premier gathering infrastructure Net Undeveloped Marcellus and midstream MLP Locations in SWPA 652,000 Monetization opportunities outside core development plan Total Net Utica Acres SKILL SET 669 Net Undeveloped Utica Modeling, delineation, and innovative Locations in SWPA solutions driven by decades of data ~89% Cutting edge strategic intelligence Total Company Average NRI through extensive acreage position ~90% Multi-basin experience delivered by personnel and joint ventures Total Company HBP 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
Capital Efficiency Continues to Improve Capital Efficiency (Mcfe/$) 160% ▪ NAV growth driven by optimization and 140% stacked pay 120% ▪ Increased EURs from 1.83 Mcfe/$ 2.78 Mcfe/$ 2.78 Mcfe/$ 2.84 Mcfe/$ model-driven spacing, 100% completion design, and BTAX IRR (%) managed pressure 80% Avg BTAX IRR 85% drawdown 60% ▪ Service cost inflation in Avg BTAX IRR 57% Avg BTAX IRR 52% 2017 offset by 40% increased EURs 20% Avg BTAX IRR 25% 0% 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 2015 2016 2017 2018E EUR/CAPEX (Mcfe/$) Note: Bars represent single well-level economics, which includes total D&C capital employed. 19
EUR Increases Driven by Modeling and Optimization Marcellus EURs 3.5 Modeling Maximizes NAV 2.9 3.0 2.7 ▪ 85% increase in proppant loading from EUR (Bcfe/1000') 2.5 pre-2016 to 2018E 2.0 1.7 ▪ Subsurface communication mitigation 1.5 implemented 1.0 ▪ Lateral spacing optimization 0.5 0.0 ▪ Managed pressure drawdown <2016 2016-2017 2018E ▪ Cluster diversion technology ▪ Min/max stress optimization Utica EURs 3.3 3.5 ▪ 3-D seismic guided drill plans 3.0 ▪ Core area delineation 2.6 EUR (Bcfe/1000') 2.5 2.0 1.4 1.5 1.0 0.5 0.0 <2016 2016-2017 2018E 20
PDP Performance Drives Low Maintenance Capital PDP Base Decline % Maintenance Capital $900 35% Possible Cumulative FCF of ~$1.4 billion $800 2019E-2022E 30% $700 $600 25% $ in millions Possible FCF at (1) Maintenance Capital $500 $400 20% $300 15% $200 $100 10% $0 2018E 2019E 2020E 2021E 2022E 5% Maintenance Capital Planned Capital <20% in Q2 <10% in Q2 2019 2021 Possible FCF at Maintenance Capital Average Maintenance Capital ▪ Average maintenance capital of ~$325 million per year to 0% 2018E 2018 2019E 2019 2020E 2020 2021E 2021 2022E 2022 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 Declining Steadily in Every Region Total Marcellus – Average Drilling Days per Well CPA Utica – Average Drilling Days per Well 30 140 120 25 Drilling Days Drilling Days 100 20 80 15 60 10 40 5 20 0 0 2014 2015 2016 2017 2018E 2015 2016 2017 2018E Ohio Wet Utica – Average Drilling Days per Well Ohio Dry Utica – Average Drilling Days per Well 80 35 70 30 60 Drilling Days Drilling Days 25 50 20 40 15 30 10 20 5 10 0 0 2014 2015 2016 2017 2018E 2014 2015 2016 2017 2018E 22
Completion Cycle Times Driving Capital Efficiency Total Portfolio Completions Cycle Times Marcellus Completions Cycle Times 5 5 4 4 Average Days/1,0000 ft Average Days/1,0000 ft 3 3 2 2 1 1 0 0 2014 2015 2016 2017 2018E 2014 2015 2016 2017 2018E 23
DEVELOPMENT PLAN 24
Shift to SWPA and Stacked Pay: Surplus Core Marcellus Inventory 450 400 3.5 TILs 46 350 Stacked Pay Factory 3.0 TILs 55 up and running 300 TIL Locations 2.5 Net SWPA TILs 73 250 Central Marcellus 200 2.0 Inventory Bcfe/d 20% 391 150 Net SWPA 1.5 Central Production CAGR Marcellus 100 Inventory 2017-2022E (1) 217 1.0 50 0 0.5 Entering 2018 2018 2019 2020 Year End 2020 ▪ As CNX returns focus to the core SWPA region, the company is 0.0 YE2017 YE2018E YE2019E YE2020E YE2021E YE2022E 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
Stacked Pay Creates Substantial Uplift Beyond Longer Laterals $25,000 140 ▪ Stacked pay PV10 is 4.4x unstacked pay 120 PV10 (1) $20,000 PV10 ($ in thousands) 100 ▪ Longer lateral PV10 is 1.9x shorter lateral $15,000 PV10 (1) 80 IRR (%) ▪ Stacked pay is a more influential 60 $10,000 economic driver than only focusing on 40 lateral length; CNX combines both value $5,000 20 drivers in development $0 0 ▪ Extending laterals delays turn-in-line, $2.00 $2.50 $3.00 Gas Price while stacked pays can be added at a Unstacked 9500' Unstacked 12000' Stacked 9500' later date optimizing IRR and EBITDAX Stacked 12000' Unstacked 9500' ROR Stacked 9500' ROR Unstacked 9500' Unstacked 12000' Stacked 9500' Stacked 12000' LOE ($/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 PORTFOLIO NAV OPTIMIZATION STACKED PAY FACTORY DESIGN ▪ Big data analysis OPTIMIZATION Ensures highest ► ▪ System modeling NPV combination DATA ACQUISTION ▪ Linear of fields while programming balancing risk ▪ Reservoir and frac EARTH MODEL modeling Improves field NPV ► ▪ Managed pressure by 30% ▪ Core, logs, seismic drawdown via rate ▪ Third party data transient analysis ▪ Delineation ▪ Machine learning ▪ Fully integrated ▪ Testing Managed pressure subsurface model ► ▪ Seismic de-risks drawdown Neural net drives ► SWPA stacked pay productivity improves EUR by development and indicators 20% improves NAV by Designs are ► Drove ► $60 million optimized in 3 understanding of wells vs. 13 three Utica areas 27
Three Utica Areas Require Distinct Development Plans CPA UTICA OHIO UTICA ▪ Stacked pay play within the ▪ Utica and Point Pleasant Manufacturing play MARCHAND 3M ▪ 3.5+ Bcf/1,000’ ▪ 3.2 Bcf/1,000’ ▪ 300’ of pay in Utica, Point ▪ 80’ of pay GAUT 4I Pleasant and Lexington ▪ Low fracture intensity ▪ 13,200’ TVD ▪ Optimized 10,500’ laterals 10,500’ TVD ▪ RHL 11 SWPA UTICA GH 9 SWITZ ▪ FIELD 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 Legacy Base Optimized 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 Fracture Conductivity (md-ft) 30
SWPA Utica: Very Strong Early Results from Richhill 11E Richhill 11E SWPA Utica well currently flowing above 3.2 Bcfe/1000’ type curve Most Recent SWPA Utica Well on Path to Target Capital Drilled through series of natural fracture clusters, which were identified in 3D seismic analysis $25 ▪ Required more drilling days than the expected run rate, which $20 elevated drilling costs Capital ($ in millions) - Elevated drilling costs offset by productivity of the well due to $15 natural fracture clusters Other additional costs related to completion design testing drove the $10 RHL11E well to exceed target capital costs, but there is clear line of sight to the projected $14.3 million $5 RHL11E Summary $0 Drilling Completions Water, Total Lateral length (1) 6,200 Construction, and Other Total capital less science $21 million SWPA Utica Target Capital (3) RHL11E Actual AFE, less Science Average flowing pressure 8,445 psig Average production (2) 22.1 MMcf/d Target flowing production @ flat first 12 months 18 MMcf/d (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 Onondaga ▪ Success is consistently hitting repeatable results by: - Drilling on seismic Point Pleasant - 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 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 Morris Field Richhill Field SWPA Greater Marcellus Utica Undeveloped Net Locations 191 231 EUR (Bcf/1000’) (1) 2.7 3.0 Total NRI 91% 91% Total PDPs 12 - Wadestown Net Current Production (Bcfe/d) 0.082 - ▪ ACAA development drives SWPA Greater, with two pads completed to date 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
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 55 60 46 50 TILs 40 30 20 11 10 0 2017 2018E 2019E 2020E ▪ ▪ Average EUR/1,000’ increased 77% from legacy Morris wells (1) SWPA Marcellus comprises a much larger portion of the three- year plan than in 2017 - Morris-30 completed with enhanced stimulated reservoir - Activity in the Morris, Richhill, and Wadestown fields driving design the increase - Increased proppant loading, min/max stress optimization - Plan to run 2-3 rigs in region throughout the time period along with the mechanical diversion testing program ▪ ~80% of three-year plan activity located in SWPA Central - Changed targeted section of Marcellus to be drilled Marcellus/Utica ▪ Morris pads being designed for future stacked pay development ▪ Morris wells expected to make up more than 65% of 2018E SWPA Marcellus TIL activity (1) Legacy Morris comprised of 21 wells TIL March 2012-June 2013; Morris 30 pad comprised of 5 wells TIL mid-2017. 34
Blending Strategy Helps Drive DevCo I Stacked Pay Economics Damp acreage requires processing to meet 1200 Requires Processing Wet Marcellus Gas BTU specifications 1150 Damp Marcellus Gas BTU Content Dry Tariff Line 1110 1100 Blended Gas = Damp Marcellus + Dry Utica/Marcellus Does Not Require Processing ▪ Avoids processing cost of $0.55-0.60/Dth ▪ Meets BTU tariff 1070 - One Utica well required for every 3-4 damp Marcellus wells Dry Utica/Marcellus 1040 Gas 1010 Note: Defined as Dry Utica 1010-1040 BTU; Dry Marcellus 1060-1110 BTU; Damp Marcellus 1110-1150; Wet Marcellus 1150+ BTU . 35
Two Pipe Gathering System Creates Flexibility in DevCo I Industry Standard One-Pipe System CNX DevCo I Two-Pipe System New Pad New Stacked Pay Pad (High Pressure) (High Pressure and Low Pressure) As new high pressure wells are TIL, higher During stacked pay pressure gas The low pressure pipe development, Marcellus and supplants older low provides the option to Utica wells can be brought pressure wells continue producing online simultaneously or Standard Gathering System choking back total existing wells rather than independently High Pressure Pipe Low Pressure Pipe production interrupt production when ▪ Most Marcellus producers new higher pressure wells lack the ability to rapidly are brought online bring on production as the CHOKED single pipe systems stay near full capacity Existing Pad Existing Pad (Low Pressure) (Low Pressure) Planned compressor stations will create flexibility to customize pressures in specific gathering lines and Compression / Dehydration 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
CPA Dry Utica Update: Aikens 5J and 5M Aikens 5J Aikens Wells EURs at 3.7 Bcf/1000’ 30000 ▪ Located in Westmoreland County, PA (CPA South 25000 region); two wells offsetting successful Gaut 4IH well Rate (Mcf/d) 20000 ▪ Average capital per well: approximately $15 million 15000 ▪ Currently performing above CPA Utica 3.5 Bcf/1000’ EUR with an average lateral length of ~7,000’ (1) 10000 - Cumulative production for combined wells is 3.58 5000 Bcf through first 77 days 0 ▪ Wells averaged 23 MMcf/d during first 77 days of 0 100 200 300 400 500 600 700 production with average flowing pressure of 8,419 Days psig Aikens 5J Actual (Mcf/d) 3.5 Bcf/1000' Type Curve - Expect production to be flat for ~18 months Aikens 5M 40000 ▪ Executing managed pressure drawdown 35000 ▪ Aikens 5J: validating Gaut 4IH results by replicating 30000 completion design and achieving similar results Rate (Mcf/d) 25000 ▪ Aikens 5M: testing higher proppant loading and 20000 model driven ceramic selection 15000 - The Aikens 5M well is on track to be the second 10000 best well in the basin to date 5000 0 0 100 200 300 400 500 600 700 Days Aikens 5M Actual (Mcf/d) 3.5 Bcf/1000' Type Curve (1) Measured in lateral feet from perforation to perforation; average drilled length of 7,500’. 38
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 UTICA ▪ Potential to multiply Utica locations within CPA by stacking multiple wellbores in the 300’ section to maximize recovery from the pay zone PLEASANT POINT ▪ Simultaneous development of Utica stacked laterals may maximize recovery through pressure shadowing and LEXINGTON eliminate future infill drilling 39
“Perfect Pad” to Create Stacked Pay Benchmark in 2019 Process Cellar technology construction allows for subsurface well heads for faster return Prior Target Days Days Dry month construction 120 90 3D seismic drives well bore optimization 12 Marcellus 122 97 wells drilled Low Pressure Optimal inter-lateral spacing: Marcellus 750 ft, Utica 1200-1500 ft Line M M M M M M Two pipe system creates flexibility to produce high pressure and Marcellus M M M M M M 142 78 low pressure wells simultaneously completions 31% High Pressure Line Reduction Combined NPV Gains from Marcellus & Utica in SWPA Perfect Pad Marcellus wells turned in line Subsurface Marcellus well heads 2018 Stacked Pay 8 Utica Baseline 124 102 Incremental NPV wells drilled Low Pressure Lateral Length Increase $10.9 of ~$21 million Line M M M M M M Technology Utilization Utica M M M M M M 2018 Stacked 119 57 Mineral Purchase $6.4 completions Pay Baseline U U U U Optimization $30.0 35% U U U U High Pressure Line Data Analytics Reduction $2.9 Utica wells turned in line LOE Efficiencies $0.4 ($ in millions) $0.8 40
Central PA Overview: North and South CPA South Marcellus Utica Undeveloped Net Locations 634 513 EUR (Bcf/1000’) (1) 1.8 3.5 Total NRI 87% 87% Total PDPs 47 3 Net Current Production (Bcfe/d) 0.034 0.046 ▪ Gaut & Aikens wells have proved area for Utica development ▪ Potential to stack Marcellus with Utica ▪ Continue to explore opportunities to expand gathering infrastructure CPA North Marcellus Utica Undeveloped Net Locations 615 498 EUR (Bcf/1000’) (1) 1.5 3.5 Total NRI 86% 86% Total PDPs 9 - Net Current Production (Bcfe/d) 0.005 - ▪ Currently delineating Utica to define Northern boundary driven from earth model (1) See appendix slides 112 and 113 for complete modeling assumptions and type curve. 41
Development Areas in Three-Year Plan CPA South OH Dry ▪ Utica ▪ Utica SWPA Central SHR/PENS ▪ Marcellus and Utica ▪ Marcellus 42
Three-Year Drill Schedule and Estimated Reserves Growth Rig Schedule 2018E-2020E Reserve Growth and Estimates 2015-2022E 2018 2019 2020 16,000 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 14,500 Rig 1 14,000 Rig 2 12,000 12,000 12,500 Rig 3 10,000 10,000 Rig 4 10,000 Bcfe 8,000 Rig 5 8,500 7,582 Rig 6 6,000 TD Count 2018 2019 2020 Total 4,000 SWPA Marcellus 62 60 71 193 6,251 5,643 3 19 27 SWPA Utica 49 2,000 5 10 15 WV Marcellus 30 4 0 9 CPA Utica 13 8 0 0 OH Utica 8 0 2015 2016 2017 2018E 2019E 2020E Total 82 89 122 293 Low High (1) Based on midpoint. 43
Three-Year Development Plan 2018E 2019E 2020E ($ in millions) TD FRAC TIL Capex TD FRAC TIL Capex TD FRAC TIL Capex Marcellus 62 48 46 60 52 55 71 78 73 SWPA Central Utica 3 1 1 19 14 14 27 28 28 Marcellus 5 5 5 10 10 7 15 11 11 WV Shirley-Penns 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 Greene County, PA Dry Utica: 14 SWPA Central dry Utica wells 28 SWPA Central dry Utica wells Richhill 11E TIL Feb. 2018 Indiana County, PA Dry Utica: 3 CPA deep dry Utica wells Notable Wells Marchand 3M TIL set for Q3 2018 (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
Track Record of Success: History of Monetizing Assets ▪ Annual average of ~$600 million in asset monetization Asset Sale Totals by Year from 2014-2017 $4,500 ▪ $414 million in assets sold in 2017 $4,000 ▪ 2018 effort continues $3,500 - Shirley-Pennsboro midstream asset drop netted $3,000 $ in millions $265 million in proceeds $2,500 $2,000 - Shallow Oil & Gas (SOG) transaction in February: $85 million in cash plus $190 million in liabilities $1,500 related to gas well plugging (asset retirement $1,000 obligations) $500 $0 Future opportunities include: ▪ Non-core upstream assets ▪ Drops to CNX Midstream ▪ CNXM LP Units and IDRs Dry powder of ~$4 billion in drop down and other ▪ Shale acres not in near-term development plan 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 SOG Wells Included in Sale West Virginia and Pennsylvania, including CBM (1) ▪ Agreement signed mid-February - Expected close by end of March ▪ 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
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 Virginia CBM – Capital Efficiency $400,000 600,000 $350,000 500,000 EUR (Mcf) CapEx ($) $300,000 400,000 $250,000 300,000 $200,000 $150,000 200,000 2014 2015 2016 2017 CapEx EUR 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 36,000 gross acres ▪ ~85 MMcfe/d net production (~170 MMcfe/d net to JV production) ▪ 72% gas, 26% NGL, 2% condensate 14,000 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) Strategic Options 29,000 gross acres ▪ Sell the JV asset ▪ Divide assets to obtain 100% WI with JV partner ▪ Drill the assets per the governing agreements (1) Excludes stranded acreage. 49
CNX MIDSTREAM ASSET AND OPPORTUNITY 50
De-Risked CNX Midstream Growth Driving CNX Upside CNXM Distributable Cash Flows by Source 2017-2022E $300 Ability to sustain 15% CNXM distribution growth is projected $250 without additional asset drops $200 $ in millions $150 $100 $50 $0 2017 2018E 2019E 2020E 2021E 2022E (2) PDPs pre-S/P Drop Shirley-Penns MVC McQuay Activity Commitments 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
Drop Inventory Drives Meaningful Upside to CNXM 15% Growth CNX Retained Undropped EBITDA including Potential Drop Candidates 2017 vs. 2020E Potential Candidates 2018E-2020E CONVEY Water Business $200 Existing DevCos Primarily Wadestown in DevCo III $150 $ in millions CPA Utica Gathering System $100 Cardinal States Gathering System Completed Year-To-Date $50 ▪ 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 2017 2017PF for S/P Drop 2020E Retained Undropped EBITDA Potential 52
CONVEY: CNX’s Water Business Projected Water Infrastructure: YE2018 PA WV OH Total Cumulative Water System CapEx $219 $94 $17 $330 ($ millions) 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 Millions of Barrels (MMBbl) 100 80 Wadestown 60 40 20 - 2017(A) 2017 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 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 Steady Water EBITDA Growth (1) ▪ Final rates to be determined at time of drop ▪ Produced water accounts for 18% of 2018 proposed EBITDA $140 Over 100 miles of new water infrastructure to begin in 2018 $120 ▪ Ohio River to SWPA fresh water supply line $100 ▪ Richhill and Majorsville infrastructure ▪ Wadestown development infrastructure $80 Fixed rates promote efficiencies for water operations $60 Infrastructure supply ▪ CONVEY will continue to drive down costs to increase margins upgrade complete $40 ▪ CNXM will benefit from cash flow stability $20 Assumed Water Operating Costs ($/Bbl) (2) $- PA WV OH 2017 2018E 2019E 2020E Fresh $0.95 $0.91 $1.62 Reuse $3.48 $4.78 $5.82 Disposal $8.12 $5.89 $7.11 (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). 55 (2) Water operating costs are based on historical averages in region and do not include infrastructure expenses.
Drop Down Inventory: Wadestown Wadestown: Five-Year Investment Outlook Wadestown: Proposed Pipeline Buildout ▪ 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 Expected Midstream Capital and EBITDA 2018E-2020E $160 $140 $120 $ in millions $100 $80 $60 $40 $20 $0 2018E 2019E 2020E 2021E 2022E CapEx EBITDA 56
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 MMcf/d 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 +$0.60/MMBtu Organic Value Creation Opportunity ▪ Premier drop opportunity into CNX Midstream ▪ Upsize throughput capacity from 250 to 385 MMcf/d with relatively minimal capital expenditure. Convert into a FERC regulated system to transport TCO shale gas to southern markets - Open Season 2/19/2018 to 3/2/2018; potential shippers being reviewed - System to be spun into new entity, CNX Transmission LLC, which will then file a certificate application to become an interstate pipeline subject to FERC jurisdiction 58
CNX Midstream Ownership Valuation CNX Midstream drives value CNXM Represents Significant Growth for CNX in CNX Midstream Value to CNX through four main avenues both IDRs and Retained EBITDA ($ in millions, except per share data) 2018E 2020E ▪ IDRs $4,000 IDR cash distributions Cash Flow (1) $ 12.7 $ 40.8 ▪ Ownership of LP units $3,480 Multiple (2) $3,500 60.0x 30.0x ▪ Retained EBITDA Value $ 761 $ 1,223 ▪ $3,000 Future drop downs LP Units Unit Price (3) $ 18.20 $ 30.19 $2,500 (4) Current Yield 7.5% 6.0% $ in millions Units Held 21.69 21.69 $2,000 Value $ 395 $ 655 $1,500 Pro Rata EBITDA Contribution $1,240 Retained EBITDA (5) $ 10 $ 200 $1,000 Market Multiple 8.0x 8.0x Value $ 80 $ 1,600 $500 Total Potential Value $ 1,240 $ 3,480 Value per CNX Share (6) $ 5.60 $ 15.80 $- 2018E 2020E IDRs LP Units Pro Rata Retained EBITDA Contribution (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. 59 (6) Based on pro forma year-to-date share count of 219.8 million on 3/8/2018.
Marketing Chad Griffith
Marketing Overview FIRM TRANSPORTATION HEDGE STRATEGY MARKET VIEW ▪ Selective FT commitments ▪ Foundation that enables the ▪ Current forward market execution of the company’s ▪ Supply/demand balance - Utilize basis hedges to create strategy synthetic FT ▪ Growing demand and exports ▪ Differentiates CNX and provides ▪ Fraction of the FT obligations ▪ Volatility is king competitive advantage compared to peers ▪ “Total” hedge: matching basis to ▪ Low FT average demand costs NYMEX of approximately $0.29 per ▪ Programmatic – dollar cost MMBtu averaging ▪ Hedge volumes in alignment with capital investment 61
Firm Transportation Strategy Three-Filter Test for Taking on New FT Transportation, Gathering, & Processing Commitments and Differentials (2) $20.0 $- $18.0 Total Obligations ($ in billions) 1 Do we need it to get it to a liquid market? $16.0 $(0.50) $14.0 Diff. to NYMEX Does it get us to a better market at a positive net $12.0 2 back? $10.0 $(1.00) $8.0 Does it help us manage the volatility of the 3 $6.0 markets we’re in? $(1.50) $4.0 $2.0 $0.0 $(2.00) Project Examples: Future Spreads vs. CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Demand Charges (1) FT, Gathering, and Processing Obligations Gas Price Diff. to NYMEX $0.800 Peer Average Gas Price Diff to NYMEX $0.600 $0.400 ▪ CNX realizes average NYMEX differentials with 1/8th of the $0.200 average “take -or- pay” FT obligation of peers $0.000 ▪ CNX instead uses a strategic mix of FT, IT, basis hedging, 2018 2019 2020 2021 2022 gathering system optionality, and capacity releases Project A Spread Project B Spread Project A Tariff Project B Tariff 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 0.3 0.3 0.4 into Basin (M2) (2) not requiring FT 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 Commitments + 2018E Adjusted Net Debt (1)(2)(3) Total FT and Processing Commitments $18.4 $21.7 $18.7 $11.6 $12.2 $8.9 $10.8 $7.1 $5.6 $3.7 $2.7 $1.8 $2.1 $1.1 CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 (FT Commitments + 2018E Adjusted Net Debt) / (FT Commitments + 2018E Adjusted Net Debt) / 2018E EBITDAX (1)(2)(3)(4) Adjusted EV (1)(2)(3) 11.1x 198% 9.0x 180% 8.3x 141% 139% 6.2x 5.2x 72% 3.1x 48% 1.7x 18% Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Note: Peers include AR, COG, EQT, GPOR, RRC, and SWN. FT and processing commitments are off-balance sheet. (1) CNX commitments as of 12/31/2017. Peer group commitments as of 9/30/2017. (2) CNX debt as of 12/31/2017. Peer group debt as of 9/30/2017. (3) Adjusted for remaining 2017E and 2018E outspend and present value of hedges. Outspend calculated as EBITDAX – capex – interest. 64 (4) CNX 2018E EBITDAX per company projections. Peer group 2018E EBITDAX per FactSet consensus estimates as of 2/13/2018.
Differentiated Firm Transportation Portfolio Avg. Demand Cost ($/Dth) 1,600 2018E 2018E (000s Dth/d) M2 1,400 DOM South 345 M3 ETNG 201 WLA ELA 1,200 TCO Pool 475 Michcon 1,000 Michcon 162 000s MMBtu/d TETCO ELA 30 800 TCO Pool TETCO WLA 50 TETCO M3 100 600 TETCO M2 125 ETNG 400 1,488 $0.29 Unutilized FT (reported in “Other Operating Expense”) 200 Dominion South ▪ Approximately 370,000 MMBtu/d in unused FT on Dominion - South and TCO Jan 18 Jan 19 Jan 20 Jan 21 Jan 22 - Acquired as part of Dominion transaction in 2010 ▪ TCO Pool includes: 200,000 MMBtu/d on TCO’s - Current drilling plans do not consider geographic area Mountaineer XPress project and 50,000 MMBtu/d of where unutilized FT resides capacity on TCO’s Leach XPress project in connection with ▪ Forecasted for 2018E at approximately $36 million the Marcellus JV dissolution - 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 syste ms 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 Basis hedging and hedge reporting example Fully-hedged volumes provide revenue certainty and de-risks capital expenditures ▪ October NYMEX settles @ $3.30 & M2 Basis settles @ ($1.10); M2 price of $2.20 ▪ CNX hedges basis in addition to NYMEX ▪ Peers primarily only hedge NYMEX, which is a partial hedge Hedge Reporting Example CNX Company A - Completely exposed to floating basis risk NYMEX Hedge $3.00 $3.00 Historical Basis Volatility Basis Hedge ($0.50) None $- Henry Hub Settle $3.30 $3.30 $(0.50) M2 Basis Settle ($1.10) ($1.10) $(1.00) NYMEX Hedge Payout ($0.30) ($0.30) $(1.50) $(2.00) M2 Basis Hedge Payout +$0.60 n/a $(2.50) Physical Gas Sale Price +$2.20 +$2.20 Actual Realized Sale Price $2.50 $1.90 TETCO M2 Basis Dominion South Basis ▪ CNX would report fully-hedged price of $2.50 and receive $2.50 ▪ Historical basis derived by first of month settle prices indicates ▪ Company A would report hedged price of $3.00, but receive only extreme volatility over the past two years $1.90 - Basis varies between $(0.39) and $(2.11) over two year stretch (1) (1) IFERC First of Month pricing. 66
Power Plants and LNG Driving Demand Growth 13.9 Bcf/d LNG Export capacity by 2022 14.7 Bcf/d incremental demand from gas fuel type power plants by 2025 ▪ An additional 11.6 Bcf/d is proposed without a target in-service date (1) ▪ CNX acreage in the center of the largest growth market, PJM Natural gas exports to Mexico via pipeline increased An additional 14.6 Bcf/d is proposed to 4.2 Bcf/d in 2017 (2) Increased Gas Demand from Planned Power Plants LNG Expected Growth 2018-2022 16 20 18 14 16 12 14 10 12 Bcf/d Bcf/d 8 10 8 6 6 4 4 2 2 0 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 1Q2018 3Q2018 1Q2019 3Q2019 1Q2020 3Q2020 1Q2021 3Q2021 1Q2022 3Q2022 2017 2018 2019 2020 2021 2022 2023 2024 2025 In-Service Exports to Mexico 2018 2019 2020 2021 2022 (1) SNL (2) EIA 67
NE Expansion Projects Remove Export Bottleneck Pipeline Expansion Project Takeaway Capacity 20 18 16 Supply Header Project 14 Atlantic Coast Pipeline WB Xpress 12 Mountaineer Xpress Bcf/d 10 PennEast 8 Nexus Project Atlantic Sunrise 6 Rover Phase 2 4 Leach Xpress 2 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 Basin Demand Expected to Increase Bcf/d and increase an additional 2.2 Bcf/d in 2019 (1) ▪ Roughly 6 GW of natural-gas fired power plant capacity in 2018 HDD expected to be 11% higher than 2017 (1) - Pennsylvania in 2018 (1) - Power generation expected to increase 3.2 Bcf/d in 2018 ▪ 20 GW capacity in 2018 across US ▪ Net exports expected to increase 1.9 Bcf/d in 2018 and an ▪ Percentage of electricity generation from natural gas expected to additional 2.3 Bcf/d in 2019 (1) increase to 33.1% in 2018 from 31.7% in 2017 (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) Regional Basis Narrows as Takeaway Capacity and Demand Increase - Natural gas exports to Mexico rose 0.4 Bcf/d in 2017 and Henry Hub and Dominion South Pricing expected to continue on same trajectory (1) (Historical First of Month and Forward Strip) Natural gas imports expected to drop 0.3 Bcf/d in 2018 (1) - $4.50 - US was net exporter of natural gas in 2017 for first time $4.00 $3.50 since 1957 (1) $3.00 ▪ 2017 storage dropped 6% below the five year average and is $2.50 $2.00 expected to be roughly 6% below five year average by end of $1.50 2019 (1) $1.00 $0.50 ▪ 2017 production of 73.5 Bcf/d remained flat relative to 2016 $0.00 levels, but an increase of 6.9 Bcf/d is expected for 2018 (1) - Increase fueled by pipeline takeaway projects (1) Henry Hub Dominion S (1) EIA Short-Term Energy Outlook. 69
Liquids and Processing Summary MarkWest Contracted Processing Capacity ACAA 365 MMcf/d Blue Racer Dominion MarkWest Majorsville Noble County ▪ CNXM and other wet gathering systems provide optionality for CNX wet production Utica ▪ Optionality provides many benefits, including: Richhill - Residue market optimization Blue Racer Blue Racer - Access to existing, excess processing capacity Berne Natrium - Avoids being captive customer MarkWest Mobley ▪ NGLs are generally marketed by processing companies – more efficient to outsource Dominion Hastings ▪ 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 Shirley/Penns ▪ $13 million in unutilized processing commitments forecasted for 2018E 70
Finance Don Rush Chuck Hardoby
Corporate Values Guide Decision Making AND KNOWLEDGE SET CNX ASSET BASE NAV/SHARE FOCUS 31% RESPONSIBILITY CORPORATE VALUES DISCIPLINED CAPITAL OWNERSHIP ALLOCATION STRATEGY FIVE YEAR EXCELLENCE EBITDAX CAGR (1) ALIGNMENT OF STAKEHOLDER INTERESTS (1) 2017-2022E based on midpoint of financial guidance. 72
Strategy Resulting In Substantial EBITDAX Growth Expected EBITDAX 2018E-2022E (1) $2,000 $1,800 $1,600 $1,400 $1,200 $ in millions $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
Balance Sheet Capacity and Dry Powder Upside through 2022E $8,000 $7,000 Dry powder of ~$4 billion through 2022E $6,000 consists of potential Balance Sheet drop proceeds, tax Capacity $5,000 refunds, CNXM LP/GP ~$3 billion $ in millions monetization, and $4,000 non-core asset sales $3,000 ~$5 billion Dry Powder $2,000 Balance sheet capacity ~$4 billion at a steady 2.5x $1,000 leverage ratio comprises another ~$3 billion in $- available capital Drop Candidates YE2017 Alternative CNXM LP Unit/IDR Non-Core Asset Sales Total Dry Powder + Retained EBITDA @ Minimum Tax Refund Monetization B/S Capacity @ 2.5x 8x Multiple Leverage Ratio 74
Marketing: Natural Gas Hedging and Basis Protection 400 350 Gas Volumes Hedged (Bcf) 43.3 300 250 ▪ Systematically layering in 44 200 12.1 375.9 hedges out to 2022 to protect 150 290.6 72.3 margins on proved developed 100 182 181.9 production and a portion of 50 94.9 PUDs (capex) 0 2018 2019 2020 2021 2022 ▪ Locking-in revenue and de- (2) NYMEX + Basis (2) NYMEX Only Hedges Exposed to Basis risking capital decisions by Hedge Volumes and Pricing Q1 2018 2018 2019 2020 2021 2022 matching NYMEX and basis NYMEX Hedges Volumes (Bcf) 88.4 358.6 321.0 215.0 172.6 153.4 hedge volumes Average Prices ($/Mcf) $3.14 $3.14 $3.02 $3.09 $3.00 $3.05 ▪ Protecting from in-basin blowout Physical Fixed Price Sales Volumes (Bcf) 4.3 17.3 12.9 11.0 21.4 13.8 through regional basis hedges Average Prices ($/Mcf) $2.61 $2.61 $2.49 $2.44 $2.45 $2.54 ▪ Approximately 81% of total Total Volumes Hedged (Bcf) (1) 92.7 375.9 333.9 226.0 194.0 167.2 2018E gas volumes hedged (3) NYMEX + Basis (fully-covered volumes) (2) Volumes (Bcf) 92.7 375.9 290.6 182.0 181.9 94.9 Average Prices ($/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 $3.05 Total Volumes Hedged (Bcf) (1) 92.7 375.9 333.9 226.0 194.0 167.2 (1) Hedge positions as of 2/20/2018. Q1 2018 and 2018 exclude 6.4 Bcf and 13.9 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total gas production guidance of 450-475 Bcf in 2018E. 75
Financial Guidance: 2018E-2020E 2018E 2019E 2020E Revenue and Other Operating Income E&P Consolidated E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 450-475 505-575 610-700 7,500-7,700 NGLs (MBbls) 6,800-7,400 6,800-7,400 15-20 15-20 15-20 Oil (MBbls) 590-610 430-480 420-480 Condensate (MBbls) Total Production (Bcfe) 500-525 550-630 650-750 % Liquids 9%-10% 8%-9% 6%-7% Natural Gas Basis Differential to NYMEX ($/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-$1,200 CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. 76 (1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 2/16/2018. Anticipated hedging activity is not included in projections. (2) Excludes stock-based compensation.
Financial Guidance: E&P 2018E 2018E Revenue and Other Operating Income E&P Production Volumes: Natural Gas (Bcf) 450-475 NGLs (MBbls) 7,500-7,700 Oil (MBbls) 15-20 Condensate (MBbls) 590-610 Total Production (Bcfe) 500-525 Basis calculated on 2018 market mix. % Liquids 9%-10% Hedge gain/(loss) calculated on Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40) NYMEX and financial basis hedges NGL Realized Price ($/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-$20 CNXM 3rd Party Gathering Revenue Costs Transportation, gathering and compression costs Average per unit operating expenses ($/Mcfe): expected to decline $0.15-$0.20 year-over-year Lease Operating Expense $0.15-$0.18 Production, Ad Valorem, and Other Fees $0.06-$0.08 primarily due to increased contribution of lower Transportation, Gathering and Compression $0.80-$0.85 cost dry Utica volumes in Monroe County, OH Total Cash Production and Gathering Costs $1.01-$1.11 ($ in millions) Selling, General, and Administrative Costs (2) $85-$95 Unutilized FT and Processing Fees: $50 million Exploration Expense $10-$15 Idle Rig Fees: $5 million Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70 Other Non-Operating Expense $15-$20 Royalty income, right of way sales, interest income Total Capital Expenditures $790-$915 and ‘other’ all netted against bank fees, other CNXM EBITDA Attributable to CNX $60-$65 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 ($0.36) per MMBtu. CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. (1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 2/16/2018. No future hedging in forecast. 77 (2) Excludes stock-based compensation.
Financial Guidance: 2018E E&P Revenue Buildup 2018E Revenue Revenue Volumes Realized Price ($ 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 Volumes 2018E CY 2018 Market (000 MMBtu) Gas Sold (%) Basis Northeast Pipeline Projects DOM South 45,074 9% ($0.67) Michcon ETNG/Cascade Creek TZ5 9,097 2% $0.34 2018E Gas: 6% TCO Pool 46,899 10% ($0.26) CY18 Basis: ($0.21) TETCO ELA & WLA 6,112 1% ($0.09) DOM South TETCO M3 2018E Gas: 10% TETCO M3 29,235 6% $0.23 Dawn Pipeline Projects 2018E Gas: 6% CY18 Basis: ($0.67) TETCO M2 209,567 43% ($0.67) CY18 Basis: $0.23 Michcon 28,315 6% ($0.21) TETCO M2 TCO Pool Physical basis sales 112,945 23% $0.02 2018E Gas: 52% 2018E Gas: 10% Total (000 MMBtu) 487,244 100% ($0.36) CY18 Basis: ($0.67) CY18 Basis: ($0.26) Total (MMcf) 463,000 Southeast Pipeline Projects NYMEX $2.78 Weighted Average Basis (Not considering hedging) ($0.36) 2018E Average Realized Price (per MMBtu) $2.42 ETNG/Cascade Creek TZ5 TETCO ELA & WLA Conversion Factor (MMBtu/Mcf) 1.054 2018E Gas: 11% 2018E Gas: 5% 2018E Average Realized Price (per Mcf) $2.55 CY18 Basis: $0.34 CY18 Basis: ($0.09) BTU Uplift $0.13 Gulf Market Pipelines 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 “NGL Barrel” Composition ▪ 2018E liquids sold: Natural gasoline N-Butane - NGLs: 7,600 MBbls 8% 9% I-Butane - Condensate: 603 MBbls 5% Ethane - Oil: 18 MBbls 48% ▪ 2018E: 9-10% total production expected to be liquids Propane 30% ▪ Total expected price for NGLs in 2018E of $23-$24/Bbl ▪ Total weighted average price of liquids in 2017 was $25.53/Bbl ▪ Contractual obligations to recover ethane (INEOS) Weighted Average NGL ($/Bbl) - Those contracts currently yield better pricing for the ethane Low High Midpoint than selling it as a natural gas equivalent NGL $23.00 $24.00 $23.50 Condensate 70% (% of WTI) Oil 100% (% of WTI) 80
Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections CY2018 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (1) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's) ($/MMBtu) ▪ In addition to NYMEX and basis financial NYMEX 377,775 $2.98 $2.78 $0.20 $74,668 hedges, CNX has physical fixed basis sales and Basis: physical fixed price sales with customers 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 ▪ CY 2018 physical fixed basis sales: 89.6 Bcf ETNG Mainline 0 $0.00 $0.23 $0.00 $0 ▪ CY 2018 physical fixed price sales: 17.3 Bcf Chicago 0 $0.00 ($0.12) $0.00 $0 TCO Pool (TCO) 36,500 ($0.27) ($0.26) ($0.01) ($239) ▪ Physical sales provide additional basis hedge Michcon (NMC) 14,448 ($0.03) ($0.21) $0.18 $2,609 TETCO ELA (TEB) 5,475 ($0.09) ($0.09) $0.00 $27 - Flows through gas sales in financials 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 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. 81 (1) January and February are settled prices.
Financial Guidance: 2018E E&P EBITDAX Buildup $1,800 $1,600 Other Operating Income Purchased Gas Sales Realized Hedging $0.15-$0.18 / Gain/(Loss) $1,400 $0.06-$0.08 / Mcfe Mcfe E&P EBITDAX + $1,200 Attributable CNXM EBITDA $825-$850 million $1,000 $0.80-$0.85 / CNXM EBITDA Mcfe $85-$95 million Attributable to CNX $50-$60 million $60-$65 million $800 Natural Gas And $65-$70 million $15-$20 million Liquids Revenue $600 $400 E&P EBITDAX $200 $0 Total Revenue LOE Production, ad Transportation, SG&A Purchased gas Other operating Other non-operating Total Adjusted valorem gathering, costs expense expense EBITDAX compression 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
Financial Guidance: 2018E CNXM EBITDA Attributable to CNX $250 $200 $150 $ in millions Non-Controlling Interest $100 $50 $60-$65 million $0 Total Revenue Operating Expense General & EBITDA EBITDA Attributable (100% of CNXM) Administrative 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 Balance sheet Asset Optimization strength and Buchanan Mine Marcellus JV Share Debt & Production Sale Dissolution financial flexibility Repurchases Repurchases Growth allow CNX to January 2016 Capital Allocation Driven choose its path forward via CONE GP Non-Core Asset Balance Sheet Coal Spin-Off strategic capital Acquisition Divestitures Stabilization allocation 85
Target Leverage Ratio Provides Capital Allocation Optionality IRR ANALYSIS Share count Bolt-on Drill bit Balance sheet reduction acquisitions 86
Capital Allocation Optionality: Drill Bit IRR Opportunities Portfolio IRR Summary: Five Year Plan Summary Assumptions ▪ Gas pricing: $2.50/MMBtu 300% 140% 138% ▪ 120% NGL pricing: $25/Bbl 100% ▪ CND pricing: $45/Bbl IRR 80% Full Cycle Assumptions (1) 60% 75% 73% 67% 40% ▪ Capital Expenditures (2) : 38% 38% 36% 36% 20% 25% - Includes D&C, midstream, water 0% Full Cycle Half Full Cycle Half Full Cycle Half Full Cycle Half Full Cycle Half infrastructure and land Cycle Cycle Cycle Cycle Cycle ▪ Operating Expenses: SWPA CPA OH WV CNX Weighted Average Includes lifting, gathering (3) , utilized FT, - Five-Year Plan Capital Allocation by Region general & administrative and production taxes CPA OH Half Cycle Assumptions (1) 10% 2% WV ▪ Capital Expenditures (2) : 6% - Includes only D&C and midstream Transaction Volume ▪ Operating Expenses: SWPA Includes only lifting, gathering (3) and - 82% production taxes (1) See appendix slide 115 for full detailed assumptions for both half and full cycle economics. (2) Excludes sunk capex primarily applicable to OH. 87 (3) Includes net CNXM gathering rates.
Capital Allocation Optionality: Share Buybacks 2018E-2022E As of: Q3 2017 End Year-End 2017 As of 3/6/2018 Buyback Potential Additional Share Reduction S/O: 90+ million share 230.1 million 223.8 million 219.8 million reduction (2) ▪ Prior to spin: 250 $10,000 - 6.4 million shares repurchased at average price $9,000 of $16.08 (3) ~$110/share Shares Outstanding (millions) 200 $8,000 with drop Market Cap ($ in millions) - Accounting for value of associated CEIX shares, proceeds (1) $7,000 repurchased shares have appreciated 36% compared to recent market prices (3) 150 $6,000 ▪ Since spin: $5,000 - 4.0 million shares repurchased at an average 100 $4,000 price of $13.95 appreciated 28% compared to $3,000 recent market prices (3) ▪ 50 $2,000 Approximately $300 million remaining on share Potential share count reduction of ~60% repurchase authorization for 2018 $1,000 by year-end 2022 including additional drop proceeds ▪ CNX refused to issue equity during the downturn - $- when most of its peers did 2017 2018E 2019E 2020E 2021E 2022E - As a result, longer term shareholders are seeing Market Cap the benefit of the discipline compounded by the Shares Outstanding - Including Drop Proceeds share repurchases happening now Shares Outstanding - No Additional Sales/Drops (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. 88 (3) Shares repurchased as of market close 3/8/2018. Return calculation based on CNX and CEIX closing prices on 3/8/2018.
Rehabilitated Balance Sheet Sets New Beginning Long-Term Liabilities Reduced by More than $4 Billion Over last Six Years $5,000 $500 Annual Cash Servicing Costs ($ in millions) $4,000 $400 2018E hedge book and production Long-Term Liabilities ($ in millions) ramp sets clear path to $3,000 $300 <2.5x net debt / EBITDAX $2,000 $200 $1,000 $100 Long-term liabilities now <$60 million with annual cash servicing costs of <$5 million $0 $0 2012 2013 2014 2015 2016 2017 2018E Long-Term Liabilities Total Annual Cash Servicing Cost 89
Capital Allocation: Balance Sheet CNX EBITDAX Less Sensitive to Commodity Swings $3.50 Each $0.25 decline in HH $1,400 price yields only a $35 million Balance Sheet Highlights (1) YE 2017 YE 2018E decline in 2018E EBITDAX $3.00 $1,200 Total Debt $2,232 $1,980 $2.50 EBITDAX Sensitivity ($ in millions) $1,000 Cash $509 $25 $2.00 Henry Hub $800 Net Debt $1,723 $1,960 $1.50 Leverage Ratio (2)(3) – NTM $600 2.1x 2.1x Leverage Ratio (2)(4) – LQA $1.00 2.5x - $400 Leverage Ratio (3) - TTM 3.6x 2.4x $0.50 $200 $1,770 $1,700 Total Liquidity $- $- $ in millions $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. 90 (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.
Tax Reform and NOLs Create Tailwind December 31, ▪ Tax reform law states that Alternative Minimum Tax (AMT) 2017 2016 amounts can be refunded at 50% in first year Deferred Tax Assets: Alternative minimum tax $ 188,080 $ 219,872 - Expect to receive first proceeds in 2019: ~$95 million Net operating loss - State 107,756 74,310 - Remainder of $188 million AMT refund expected over Net operating loss - Federal 99,524 144,450 subsequent years Foreign tax credit 44,402 39,850 - Total figure is an estimate and could increase Gas well closing 16,648 20,512 ▪ Following the spin transaction, CNX retained the corporate Salary retirement 9,404 16,928 tax attributes Capital lease 2,020 3,210 — - Approximately $475 million in federal net operating losses Gas derivatives 72,105 (NOLs) with a cash value of about $95 million Other 33,697 48,961 Total Deferred Tax Assets 501,531 640,198 - NOLs prior to 2018 can be used to offset 100% of future Valuation Allowance (136,576) (282,778) taxable income Net Deferred Tax Assets 364,955 357,420 - As a result, expect to pay no cash taxes for roughly 4-5 years Deferred Tax Liabilities: ▪ Additional NOLs projected with sale of SOG that are likely to Property, plant and equipment (385,366) (450,695) — further delay cash tax obligation Gas derivatives (15,248) Advance gas royalties (3,648) (5,824) ▪ Intangible drilling costs (IDCs) will be 100% deductible in Equity Partnerships (1,251) (2,237) year one or can be amortized over five years Other (3,815) (3,760) - In conjunction with NOLs, IDCs create flexibility to Total Deferred Tax Liabilities (409,328) (462,516) minimize cash tax burden for many years Net Deferred Tax Liability $ (44,373) $ (105,096) Note: Deferred tax liability table from 2017 10-K p. 92. 91
Finance Summary: 2014-2018+ 2018+ Growing NAV/Share 2014- Company Transformation Growing EBITDAX Locking in Revenue and Returns and Balance Sheet Repair 2017 Ongoing Hedge Program Drill Bit IRR Analysis Continued Balance Sheet Share 2017 Optionality Repurchases Share Drilling Repurchases Program Bolt-On Begin Expanded 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
Stacked Pay: What are the Main Advantages? ▪ Reduces capital Stacked Pay Pad Economics Example - Pre-spud capital nearly eliminated for second formation $350 140% - Use existing fuel gas to power D&C operations $300 120% ▪ Reduces cycle times NPV ($ in millions) $250 100% - Pad & facilities already constructed IRR (%) $200 80% - Midstream and water infrastructure already in place ▪ Reduces LOE $150 60% - Driven by higher well count & concentrated volume $100 40% - Maintenance efficiency on infrastructure $50 20% ▪ Reduces gathering fees $0 0% $2.50 $2.00 $3.00 - Dry and wet gas can be blended to avoid processing fees Gas Price Unstacked NPV Stacked NPV Unstacked IRR % Stacked IRR % - Combining formations reduces gathering rate on Utica - Processing flexibility to capture NGL upside in market Marcellus Utica ▪ 3D seismic de-risks & optimizes D&C across all pay zones Unstacked Stacked Unstacked Stacked LOE ($/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
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 140,000 Marcellus and blend to avoid processing 120,000 - Avoids processing & increases gathering 100,000 Lateral Length (ft) efficiency 80,000 - Allows capture of BTU value of damp gas 60,000 - Blending solutions drive long term synergies 40,000 with CNXM 20,000 0 Unstacked Stacked Delta 1110 1120 1130 1140 1150 Marcellus BTU Well Count 240 240 - Utica Lateral Length Marcellus Lateral Length CapEx ($ in millions) $2,761 $2,700 ($61) NPV ($ in millions) $1,306 $1,616 +$310 BTAX IRR 48.4% 59.4% +11.0% 98
Stacked Pay: Marcellus/Utica vs. Marcellus/Upper Devonian Normalized NPV (NPV/Foot) 4.50 ▪ Stacked Pay with Marcellus and Utica 4.00 yields a higher NPV than stacking 3.50 PV10 ($ in millions/Ft) Marcellus with Upper Devonian wells 3.00 2.50 ▪ Stacking wet gas Marcellus wells with dry 2.00 gas Utica wells gives the optionality to 1.50 blend or process the gas depending on 1.00 NGL market conditions 0.50 ▪ An Upper Devonian well yields ~60% of - $2.00 $2.50 $3.00 the production of a Marcellus well for Gas Price similar capital CNX Marcellus/Utica Stack Company A Marcellus/Upper Devonian Stack Stacked Pay CNX Marcellus/Utica Stack Company A Marcellus/Upper Devonian Stack LL 9500'/8500' 12000'/15000' EUR/Ft 2.8 / 3.2 2.4 / 1.5 LOE ($/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
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