Cnx Resources Corporation · NYSE:CNX

Cnx Resources — Scotia Howard Weil 2018 Energy Conference

85 slides from Cnx Resources's conference presentation, Mar 27, 2018

  1. Slide 1: Scotia Howard Weil 2018 Energy Conference

    Scotia Howard Weil 2018 Energy Conference Nick DeIuliis March 27, 2018

  2. Slide 2: Cautionary Language

    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

  3. Slide 3: Agenda

    Agenda Strategic Overview Nick DeIuliis Operational Update Chief Executive Officer Business Forecast 3

  4. Slide 4: Strategic Overview

    CNX Strategic Overview

  5. Slide 5: 154-Year Legacy is a Competitive Advantage

    154-Year Legacy is a Competitive Advantage The Dominion The vast Industrialist assets CNX interwoven Andrew Mellon acquired in 2010 financed the nature of trace their roots consolidation of the CNX to the late 1800s the coal estate acreage and John D. throughout Rockefeller’s holdings Appalachia Sta

  6. Slide 6: Asset Base Creates Compelling Value Creation Opportunity

    Asset Base Creates Compelling Value Creation Opportunity Net Marcellus Acres / Reserves to % Operated Proved Reserves Large Net Utica Acres(1) Production (years) Contiguous Acreage 531,000 / 95.5% 18.6 7.6 Tcfe Position 652,000 2017 Average Net 5-Year Half-Cycle Portfolio Current Deep Dry Production

  7. Slide 7: The CNX Strategy is to Grow NAV/Share via Capital Allocation

    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 in

  8. Slide 8: Methodical Execution Driving IRR and EBITDAX Growth

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

  9. Slide 9: Stacked Pay Development Will Disrupt the Appalachian Basin

    Stacked Pay Development Will Disrupt the Appalachian Basin Stacked pay provides 30% CNX has a non-replicable asset base increase to total field NPV allowing for stacked pay development Stacked pay drives superior IRRs through economies of scale and greater flexibility Stacked Pay Pad Economics Examp

  10. Slide 10: Top Tier Balance Sheet Strength Drives Capital Optionality

    Top Tier Balance Sheet Strength Drives Capital Optionality STEADY STATE DRILL BIT 2.5X LEVERAGE RATIO ROBUST HEDGE BOOK & IRR SHARE COUNT REDUCTION FT STRATEGY ANALYSIS DISCRETIONARY CASH FLOW ASSET MONETIZATIONS BOLT-ON ACQUISITIONS BALANCE SHEET CAPACITY 10

  11. Slide 11: Leverage Ratio Capacity Allows for Share Count Reduction

    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 3.0x Cumulative available capacity of $2,500 250 $10,000 ~$3 billion 2018-2022 ~$70/share $9,000 Steady State Leverage R

  12. Slide 12: CNXM 15% Distribution Growth De-Risked

    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 $100 $42 $40 $28 $50 $20 $0 $0 (1) 2017 2018E 2019E 2020E 2021E 2022E 2017

  13. Slide 13: Operational Update

    CNX Operational Update

  14. Slide 14: Richhill (RHL): Stacked Pay Development

    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

  15. Slide 15: CPA Dry Utica Update: Aikens 5J and 5M

    CPA Dry Utica Update: Aikens 5J and 5M Aikens Wells EURs at 3.7 Bcf/1000’ Aikens 5J 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

  16. Slide 16: Peer Firm Transportation Benchmarking

    Peer Firm Transportation Benchmarking Total FT and Processing Commitments Total FT Commitments + 2018E Adjusted Net Debt(1)(2)(3) $18.4 $21.7 $18.7 $11.6 $12.2 $8.9 $10.8 $7.1 $5.6 $3.7 $1.8 $2.1 $2.7 $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 (F

  17. Slide 17: Business Forecast

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  18. Slide 18: Shift to SWPA and Stacked Pay: Surplus Core Marcellus Inventory

    Shift to SWPA and Stacked Pay: Surplus Core Marcellus Inventory 450 3.5 400 TILs 46 350 3.0 Stacked Pay Factory TILs 55 up and running 300 TIL Locations 2.5 Net SWPA TILs 73 250 Central Marcellus 2.0 200 Inventory Bcfe/d 1.5 20% 150 391 Net SWPA Central Production CAGR 100 Marcellus Inventory 1.0 20

  19. Slide 19: Strategy Resulting In Substantial EBITDAX Growth

    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. 19

  20. Slide 20: Drop Inventory Drives Meaningful Upside to CNXM 15% Growth

    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 Existing DevCos $150 Primarily Wadestown in DevCo III $ in millions CPA Utica Gathering System $100

  21. Slide 21: Appendix

    CNX Appendix

  22. Slide 22: Three-Year Drill Schedule and Estimated Reserves Growth

    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 Rig 5 8,000 8,500 7,582 Rig 6 6,000

  23. Slide 23: Three-Year Development Plan

    Three-Year Development Plan 2018E 2019E 2020E ($ in millions) TD FRAC TIL Capex TD FRAC TIL Capex TD FRAC TIL Capex SWPA Marcellus 62 48 46 60 52 55 71 78 73 Central Utica 3 1 1 19 14 14 27 28 28 WV Marcellus 5 5 5 10 10 7 15 11 11 Shirley-Penns Utica - - - - - - - - - CPA South Utica 4 4 2 - 1 3 9

  24. Slide 24: Type Curve Guidance Areas Refined For Modeling Accuracy

    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: D

  25. Slide 25: Development Areas in Three-Year Plan

    Development Areas in Three-Year Plan OH Dry CPA South ▪ Utica ▪ Utica SHR/PENS SWPA Central ▪ Marcellus ▪ Marcellus and Utica 25

  26. Slide 26: PDP Performance Drives Low Maintenance Capital

    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 $ in millions 25% Possible FCF at (1) $500 Maintenance Capital 20% $400 $300 15% $200 $100 10% $0 2018E 2019E 2020E 2021E 2022E 5% Ma

  27. Slide 27: SWPA Central: Focus of Activity in Three-Year Plan

    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 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 large

  28. Slide 28: "Perfect Pad" to Create Stacked Pay Benchmark in 2019

    “Perfect Pad” to Create Stacked Pay Benchmark in 2019 Process Cellar technology construction allows for subsurface well heads Prior Target for faster return Days Days 120 90 Dry month construction 3D seismic drives well bore optimization 12 Marcellus 122 97 wells drilled Low Pressure Optimal inter-l

  29. Slide 29: Two Pipe Gathering System Creates Flexibility in DevCo I

    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 develop

  30. Slide 30: Blending Strategy Helps Drive DevCo I Stacked Pay Economics

    Blending Strategy Helps Drive DevCo I Stacked Pay Economics 1200 Damp acreage requires processing to meet Requires Processing Wet Marcellus Gas BTU specifications 1150 Damp Marcellus Gas BTU Content 1110 Dry Tariff Line 1100 Blended Gas = Damp Marcellus + Dry Utica/Marcellus Does Not Require Process

  31. Slide 31: SWPA Utica: Very Strong Early Results from Richhill 11E

    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 Drilled through series of natural fracture clusters, which were on Path to Target Capital identified in 3D seismic analysis $25 ▪ Require

  32. Slide 32: Stacked Pay Creates Substantial Uplift Beyond Longer Laterals

    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 $10,000 60 economic driver tha

  33. Slide 33: Stacked Pay: Pad Level Benefits

    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

  34. Slide 34: Stacked Pay: What are the Main Advantages?

    Stacked Pay: What are the Main Advantages? ▪ Reduces capital - Pre-spud capital nearly eliminated for second formation Stacked Pay Pad Economics Example $350 140% - Use existing fuel gas to power D&C operations ▪ Reduces cycle times $300 120% NPV ($ in millions) - Pad & facilities already constructe

  35. Slide 35: Track Record of Success: History of Monetizing Assets

    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 millio

  36. Slide 36: SOG Sale Drives Continued Reduction in Legacy Liabilities

    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 ▪

  37. Slide 37: Virginia Coalbed Methane (CBM): Upstream

    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 & Conasaug

  38. Slide 38: Ohio Utica Joint Venture Overview

    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 produc

  39. Slide 39: De-Risked CNX Midstream Growth Driving CNX Upside

    De-Risked CNX Midstream Growth Driving CNX Upside CNXM Distributable Cash Flows by Source 2017-2022E $300 Ability to sustain 15% CNXM $250 distribution growth is projected without additional asset drops $200 $ in millions $150 $100 $50 $0 2017 2018E 2019E 2020E 2021E 2022E PDPs pre-S/P Drop Shirley-

  40. Slide 40: CONVEY: CNX's Water Business

    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 Wa

  41. Slide 41: CONVEY: Major Projects

    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 co

  42. Slide 42: CONVEY: Drives High Distribution Growth Rate

    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 O

  43. Slide 43: Drop Down Inventory: Wadestown

    Drop Down Inventory: Wadestown Wadestown: Five-Year Investment Outlook ▪ Greenfield Marcellus and Utica dedication in DevCo III Wadestown: Proposed Pipeline Buildout ▪ Wadestown metering and regulation Facility - New 1.2 Bcf/d Dominion interconnect - Wadestown compressor station - Total buildout hor

  44. Slide 44: Drop Down Inventory: Central PA Midstream Buildout

    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 4

  45. Slide 45: Virginia Coalbed Methane: Midstream (Cardinal States Gathering)

    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 3rd party gas and provide significant revenue source ▪ Provides pr

  46. Slide 46: CNX Midstream Ownership Valuation

    CNX Midstream Ownership Valuation CNX Midstream drives value CNX Midstream Value to CNX CNXM Represents Significant Growth for CNX in through four main avenues ($ in millions, except per share data) 2018E 2020E both IDRs and Retained EBITDA ▪ IDR cash distributions IDRs $4,000 (1) Cash Flow $ 12.7 $

  47. Slide 47: Firm Transportation Strategy

    Firm Transportation Strategy Three-Filter Test for Taking on New FT Transportation, Gathering, & Processing $20.0 Commitments and Differentials(2) $- $18.0 Total Obligations ($ in billions) 1 Do we need it to get it to a liquid market? $16.0 $14.0 $(0.50) Diff. to NYMEX Does it get us to a better ma

  48. Slide 48: Liquidity of In-Basin Markets Negates Need for FT

    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

  49. Slide 49: Differentiated Firm Transportation Portfolio

    Differentiated Firm Transportation Portfolio Avg. Demand 1,600 Cost ($/Dth) (000s Dth/d) 2018E 2018E 1,400 M2 DOM South 345 M3 WLA ETNG 201 1,200 ELA Michcon TCO Pool 475 1,000 Michcon 162 000s MMBtu/d TETCO ELA 30 800 TCO Pool TETCO WLA 50 600 TETCO M3 100 ETNG TETCO M2 125 400 1,488 $0.29 200 Domi

  50. Slide 50: Natural Gas Basis Risk and Financial Reporting Clarity

    Natural Gas Basis Risk and Financial Reporting Clarity Fully-hedged volumes provide revenue certainty and Basis hedging and hedge reporting example de-risks capital expenditures ▪ October NYMEX settles @ $3.30 & M2 Basis settles @ ($1.10); ▪ CNX hedges basis in addition to NYMEX M2 price of $2.20 ▪

  51. Slide 51: Power Plants and LNG Driving Demand Growth

    Power Plants and LNG Driving Demand Growth 14.7 Bcf/d incremental demand from gas fuel type 13.9 Bcf/d LNG Export capacity by 2022 power plants by 2025 ▪ An additional 11.6 Bcf/d is proposed without a target in-service ▪ CNX acreage in the center of the largest growth market, PJM date (1) An additio

  52. Slide 52: NE Expansion Projects Remove Export Bottleneck

    NE Expansion Projects Remove Export Bottleneck Pipeline Expansion Project Takeaway Capacity 20 18 16 Supply Header Project 14 Atlantic Coast Pipeline 12 WB Xpress Mountaineer Xpress Bcf/d 10 PennEast 8 Nexus Project 6 Atlantic Sunrise Rover Phase 2 4 Leach Xpress 2 Other 0 Projected 18.7 Bcf/d basin

  53. Slide 53: Supply/Demand Fundamentals

    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

  54. Slide 54: Liquids and Processing Summary

    Liquids and Processing Summary ACAA MarkWest Contracted Processing Capacity Blue Racer 365 MMcf/d Dominion MarkWest Majorsville Noble County Utica ▪ CNXM and other wet gathering systems provide optionality for CNX wet production Richhill ▪ Optionality provides many benefits, including: - Residue mar

  55. Slide 55: Balance Sheet Capacity and Dry Powder Upside through 2022E

    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 Capacity drop proceeds, tax $5,000 ~$3 billion refunds, CNXM LP/GP $ in millions monetization, and $4,000 non-core asset sales $3,000 ~$5 billio

  56. Slide 56: Marketing: Natural Gas Hedging and Basis Protection

    Marketing: Natural Gas Hedging and Basis Protection 400 350 Gas Volumes Hedged (Bcf) 43.3 300 250 200 375.9 44 12.1 ▪ Systematically layering in 150 290.6 72.3 hedges out to 2022 to protect 100 182 181.9 margins on proved developed 50 94.9 production and a portion of 0 PUDs (capex) 2018 2019 2020 20

  57. Slide 57: Financial Guidance: 2018E-2020E

    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-

  58. Slide 58: Financial Guidance: E&P 2018E

    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) calcu

  59. Slide 59: Financial Guidance: 2018E E&P Revenue Buildup

    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 Bcf

  60. Slide 60: Financial Guidance: 2018E Natural Gas Marketing Mix and Basis

    Financial Guidance: 2018E Natural Gas Marketing Mix and Basis Volumes 2018E CY 2018 Market (000 MMBtu) Gas Sold (%) Basis Michcon Northeast Pipeline Projects DOM South 45,074 9% ($0.67) 2018E Gas: 6% ETNG/Cascade Creek TZ5 9,097 2% $0.34 CY18 Basis: ($0.21) TCO Pool 46,899 10% ($0.26) DOM South TETC

  61. Slide 61: Financial Guidance: 2018E NGL Barrel Composition and Pricing

    Financial Guidance: 2018E NGL Barrel Composition and Pricing Approximately $200 million in revenue 2018E “NGL Barrel” Composition ▪ 2018E liquids sold: Natural N-Butane gasoline - NGLs: 7,600 MBbls 9% 8% - Condensate: 603 MBbls I-Butane 5% - Oil: 18 MBbls Ethane 48% ▪ 2018E: 9-10% total production e

  62. Slide 62: Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections

    Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections CY2018 CY2019 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (1) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's) ($/MMBtu) NYMEX 377,775 $2.98 $2.78 $0.20 $74,668 ▪ In addition to NYMEX and basis financial Basis: hedges, CNX h

  63. Slide 63: Guidance: Natural Gas Hedging – Gain/Loss Projections

    Guidance: Natural Gas Hedging – Gain/Loss Projections Q1 2018 CY2018 CY2019 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) ($/MMBtu) NYMEX

  64. Slide 64: Financial Guidance: 2018E E&P EBITDAX Buildup

    Financial Guidance: 2018E E&P EBITDAX Buildup $1,800 $1,600 Other Operating Income Purchased Gas Sales Realized Hedging $1,400 Gain/(Loss) $0.15-$0.18 / $0.06-$0.08 / Mcfe Mcfe E&P EBITDAX + $1,200 Attributable CNXM EBITDA $1,000 $825-$850 million $0.80-$0.85 / CNXM EBITDA Mcfe $85-$95 million Attri

  65. Slide 65: Financial Guidance: 2018E CNXM EBITDA Attributable to CNX

    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 65

  66. Slide 66: Capital Allocation Optionality: Drill Bit IRR Opportunities

    Capital Allocation Optionality: Drill Bit IRR Opportunities Summary Assumptions Portfolio IRR Summary: Five Year Plan ▪ Gas pricing: $2.50/MMBtu 140% 300% 138% ▪ NGL pricing: $25/Bbl 120% 100% ▪ CND pricing: $45/Bbl IRR 80% Full Cycle Assumptions(1) 60% 73% 75% 67% 40% ▪ Capital Expenditures(2): 20%

  67. Slide 67: Half Cycle and Full Cycle Modeling Assumptions

    Half Cycle and Full Cycle Modeling Assumptions Portfolio Single Well Assumption Half Cycle Full Cycle Half Cycle Realized Pricing 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 Fl

  68. Slide 68: Capital Allocation Optionality: Share Buybacks

    Capital Allocation Optionality: Share Buybacks 2018E-2022E As of: Q3 2017 End Year-End 2017 As of 3/6/2018 Buyback Potential Share Reduction Additional S/O: 230.1 million 223.8 million 219.8 million 90+ million share reduction(2) 250 $10,000 ▪ Prior to spin: $9,000 - 6.4 million shares repurchased a

  69. Slide 69: Rehabilitated Balance Sheet Sets New Beginning

    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) $3,000 $300 ramp sets clear path to <2.5x

  70. Slide 70: Capital Allocation: Balance Sheet

    Capital Allocation: Balance Sheet CNX EBITDAX Less Sensitive to Commodity Swings $3.50 Each $0.25 decline in HH price yields only a $35 million $1,400 Balance Sheet Highlights(1) YE 2017 YE 2018E $3.00 decline in 2018E EBITDAX $1,200 Total Debt $2,232 $1,980 $2.50 EBITDAX Sensitivity ($ in millions)

  71. Slide 71: Tax Reform and NOLs Create Tailwind

    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: - Expect to receive first proceeds in 2019: ~$95 million Alternative minimum tax $ 188,080 $ 219,872 Net operating l

  72. Slide 72: Detailed IDR Model: Assuming 15% Distribution Growth

    Detailed IDR Model: Assuming 15% Distribution Growth GP + Floor Ceiling LP Share IDR Share IDR 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 0.2656

  73. Slide 73: Asset Portfolio Overview

    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

  74. Slide 74: SWPA Overview: Greater and Central

    SWPA 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 Fi

  75. Slide 75: Central PA Overview: North and South

    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 U

  76. Slide 76: WV Overview: Shirley-Pennsboro and East

    WV 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

  77. Slide 77: Ohio Overview: Wet and Dry

    Ohio Overview: Wet and Dry OH Wet Marcellus Utica Undeveloped Net Locations - 135 EUR (Bcfe/1000’) - 2.1 Total NRI - 42% 59 (Hess) Total PDPs - 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 Tot

  78. Slide 78: SWPA Central Modeling Inputs and Economics

    SWPA Central Modeling Inputs and Economics Reserves Detail Assumptions Gross EUR (bcfe) 26.8 SWPA Central SWPA Marcellus Central Type Marcellus Curve Type (2.8 Curve (2.8Bcf/1000’) Bcf/1000') IP (MMcf/d) (3 mo. flat) 15.9 Inlet BTU 1075 Decline 57% 600,000 BTAX IRR% Outlet BTU N/A B-factor 1.5 Price

  79. Slide 79: SWPA Greater Modeling Inputs and Economics

    SWPA Greater Modeling Inputs and Economics Reserves Detail Assumptions SWPASWPA Greater Marcellus Greater Type Marcellus Curve Type (2.7 Curve Bcfe/1000’) (2.7 Bcfe/1000') Gross EUR (bcfe) 25.8 IP (MMcf/d) (3 mo. flat) 11.8 Inlet BTU 1144 Decline 52% 500,000 BTAX IRR% Outlet BTU 1081 B-factor 1.59 P

  80. Slide 80: WV SHR/PENS Modeling Inputs and Economics

    WV SHR/PENS Modeling Inputs and Economics Reserves Detail Assumptions WV SHR/PENS Marcellus TypeType Curve (2.8 (2.8 Bcfe/1000’) WV SHR/PENS Marcellus Curve Bcfe/1000') Gross EUR (bcfe) 22.2 IP (MMcf/d) 14.5 Inlet BTU 1260 Decline 69% 400,000 50,000 BTAX IRR% NGL/CND Production (BBL/month) Gas Outle

  81. Slide 81: WV East Modeling Inputs and Economics

    WV East Modeling Inputs and Economics Reserves Detail Assumptions WV East WV Marcellus TypeType East Marcellus Curve (2.5 (2.5 Curve Bcfe/1000’) Bcfe/1000') Gross EUR (bcfe) 19.4 IP (MMcf/d) 13.5 Inlet BTU 1230 Decline 69% 400,000 50,000 BTAX IRR% NGL/CND Production (BBL/month) Gas Outlet BTU 1113 B

  82. Slide 82: CPA South Modeling Inputs and Economics

    CPA South Modeling Inputs and Economics Reserves Detail Assumptions Gross EUR (bcfe) 16.1 IP (MMcf/d) 13.6 CPA South Marcellus CPA South TypeType Marcellus Curve (1.8(1.8 Curve Bcf/1000’) Bcf/1000') Inlet BTU 1040 Decline 69% 400,000 BTAX IRR% Outlet BTU N/A B-factor 1.65 Price 9,000' Gas Production

  83. Slide 83: CPA North Modeling Inputs and Economics

    CPA North Modeling Inputs and Economics Reserves Detail Assumptions CPA CPA NorthNorth Marcellus Type Marcellus Curve Type (1.5 Curve Bcf/1000’) (1.5 Bcf/1000') Gross EUR (bcfe) 13.1 IP (MMcf/d) 11.1 Inlet BTU 1012 Decline 69% 400,000 BTAX IRR% Outlet BTU N/A B-factor 1.65 Price 9,000' Gas Productio

  84. Slide 84: Ohio Modeling Inputs and Economics

    Ohio Modeling Inputs and Economics Reserves Detail Assumptions OH WetOH Utica WetType Type Curve (2.1 Bcfe/1000') Curve (2.1 Bcfe/1000’) Gross EUR (bcfe) 17.1 IP (MMcf/d) 11.9 Inlet BTU 1170 Decline 62% 400,000 30,000 BTAX IRR% NGL/CND Production (BBL/month) Gas Outlet BTU 1098 B-factor 1.38 Price 8

  85. Slide 85: CNX Midstream Partners Governance

    CNX Midstream Partners Governance NYSE: CNX 100% CNX Gathering LLC 33.4% LP Interest 100% CNX Midstream GP LLC The “General Partner” Incentive Distribution Rights Public 41.9mm Common Units 2% GP Interest 95% LP Interest 64.6% LP Interest NYSE: CNXM 100% 5% GP Interest 5% GP Interest Anchor Systems

CNX Resources — Scotia Howard Weil 2018 Energy Conference on 6ix