Cnx Resources Corporation · NYSE:CNX
Cnx Resources — Investor Day (March 2018)
117 slides from Cnx Resources's investor day presentation, Mar 13, 2018
Slide 1: Analyst & Investor Meeting
Analyst & Investor Meeting Pittsburgh, Pennsylvania March 13, 2018
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
Slide 3: Agenda
Agenda Strategic Overview Marketing Nick DeIuliis, Chief Executive Officer Chad Griffith, VP – Marketing Operations Finance Tim Dugan, Chief Operating Officer Don Rush Andrea Passman, VP – Development Chuck Hardoby, VP – Finance Business Development Questions & Answers Don Rush, Chief Financial Offi
Slide 4: Strategic Overview
Strategic Overview Nick DeIuliis
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
Slide 6: Greater than the Sum of the Parts
Greater than the Sum of the Parts Set in motion more than a decade ago, CNX emerged as a premier standalone E&P company on November 29, 2017 The separation of the businesses allows CNX to efficiently deploy its capital allocation strategy 6
Slide 7: 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
Slide 8: 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
Slide 9: 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
Slide 10: 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
Slide 11: 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 11
Slide 12: 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
Slide 13: 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 $0 (1) 2017 2018E 2019E 2020E 2021E 2022E 2017
Slide 14: Compensation Plan Reinforces Strategy
Compensation Plan Reinforces Strategy Long-Term Incentive Short-Term Incentive Program (PSUs) Compensation Program 2016 Free Cash Flow Compensation plans motivate management to execute on: 2017 Free Cash Flow ▪ Methodical operational execution 50% ▪ Balance sheet discipline 2018 & Adjusted EBITDA/Sh
Slide 15: Importance of Both Numerator and Denominator in NAV/Share
Importance of Both Numerator and Denominator in NAV/Share DIFFERENTIATED ASSET BASE NAV OPERATIONAL EXECUTION DRIVEN BY GROWING RESERVES VALUE OPTIMIZED VALUE OF MLP PRUDENT ASSET MONETIZATION NAV/Share BALANCE SHEET & HEDGE BOOK = Accretion & OUTSTANDING Share count reduction can Recognition SHARES
Slide 16: Operations
Operations Tim Dugan Andrea Passman
Slide 17: Unique Stacked Acreage Portfolio Sets the Stage
Unique Stacked Acreage Portfolio Sets the Stage 531,000 ASSET BASE HIGHLIGHTS Total Net Marcellus Acres Vast multi-formation acreage position built over 150+ years 582 Net Undeveloped Marcellus Premier gathering infrastructure Locations in SWPA and midstream MLP 652,000 Monetization opportunities ou
Slide 18: Type Curve Guidance Areas Refined For Modeling Accuracy
Type Curve Guidance Areas Refined For Modeling Accuracy ▪ Type curve (TC) guidance areas refined to present more accurate characteristics of acreage - Went from five TC regions (SWPA, CPA, WV, and OH Dry & Wet) to now eight (SWPA: Central & Greater, WV: SHR/PENS & East, CPA: South & North, and OH: D
Slide 19: Capital Efficiency Continues to Improve
Capital Efficiency Continues to Improve 160% Capital Efficiency (Mcfe/$) ▪ 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 IR
Slide 20: EUR Increases Driven by Modeling and Optimization
EUR Increases Driven by Modeling and Optimization Marcellus EURs Modeling Maximizes NAV 3.5 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 pr
Slide 21: 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
Slide 22: Drilling Days Declining Steadily in Every Region
Drilling Days Declining Steadily in Every Region Total Marcellus – Average Drilling Days per Well CPA Utica – Average Drilling Days per Well 30 140 25 120 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
Slide 23: Completion Cycle Times Driving Capital Efficiency
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
Slide 24: Development Plan
DEVELOPMENT PLAN CNX
Slide 25: 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
Slide 26: 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
Slide 27: Technological Advances Driving Tangible Results
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 ► I
Slide 28: Three Utica Areas Require Distinct Development Plans
Three Utica Areas Require Distinct Development Plans CPA UTICA OHIO UTICA ▪ Stacked pay play within the ▪ Manufacturing play MARCHAND 3M Utica and Point Pleasant ▪ 3.2 Bcf/1,000’ ▪ 3.5+ Bcf/1,000’ ▪ 80’ of pay ▪ 300’ of pay in Utica, Point GAUT 4I Pleasant and Lexington ▪ Low fracture intensity ▪ 13
Slide 29: The Utica is a Precision Play
The Utica is a Precision Play OHIO (SWITZ) SWPA (RHL11E) CPA (Marchand3M) Understanding reservoir characteristics in combination with facies drives productivity 29
Slide 30: Ohio Utica Model Drove SWPA and CPA Success
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
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
Slide 32: SWPA Utica Requires Engineered Design
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 fr
Slide 33: SWPA Region Overview: Greater and Central
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 Mo
Slide 34: 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
Slide 35: 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
Slide 36: 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
Slide 37: 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
Slide 38: 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 $15 million 15000 ▪ Currently performing
Slide 39: Stacked Utica with Utica in CPA
Stacked Utica with Utica in CPA ▪ Utica, Point Pleasant and Lexington are all gas bearing contributing zones with a total thickness of nearly 300’ - Verified by the Marchand core and logs UTICA ▪ Potential to multiply Utica locations within CPA by stacking multiple wellbores in the 300’ section to m
Slide 40: "Perfect Pad" to Create Stacked Pay Benchmark in 2019
“Perfect Pad” to Create Stacked Pay Benchmark in 2019 Process Cellar technology construction allows for subsurface well heads Prior Target for faster return Days Days 120 90 Dry month construction 3D seismic drives well bore optimization 12 Marcellus 122 97 wells drilled Low Pressure Optimal inter-l
Slide 41: Central PA Overview: North and South
Central PA Overview: North and South CPA South Marcellus Utica Undeveloped Net Locations 634 513 EUR (Bcf/1000’)(1) 1.8 3.5 Total NRI 87% 87% Total PDPs 47 3 Net Current Production (Bcfe/d) 0.034 0.046 ▪ Gaut & Aikens wells have proved area for Utica development ▪ Potential to stack Marcellus with U
Slide 42: Development Areas in Three-Year Plan
Development Areas in Three-Year Plan OH Dry CPA South ▪ Utica ▪ Utica SHR/PENS SWPA Central ▪ Marcellus ▪ Marcellus and Utica 42
Slide 43: Three-Year Drill Schedule and Estimated Reserves Growth
Three-Year Drill Schedule and Estimated Reserves Growth Rig Schedule 2018E-2020E Reserve Growth and Estimates 2015-2022E 2018 2019 2020 16,000 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 14,500 Rig 1 14,000 Rig 2 12,000 12,000 12,500 Rig 3 10,000 10,000 Rig 4 10,000 Bcfe Rig 5 8,000 8,500 7,582 Rig 6 6,000
Slide 44: Three-Year Development Plan
Three-Year Development Plan 2018E 2019E 2020E ($ 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
Slide 45: Business Development
Business Development Don Rush
Slide 46: 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
Slide 47: 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 ▪
Slide 48: 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
Slide 49: 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
Slide 50: CNX Midstream Asset and Opportunity
CNX MIDSTREAM ASSET AND OPPORTUNITY 50
Slide 51: 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-
Slide 52: 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
Slide 53: 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
Slide 54: 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
Slide 55: 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 $140 O
Slide 56: Drop Down Inventory: Wadestown
Drop Down Inventory: Wadestown Wadestown: Five-Year Investment Outlook ▪ Greenfield Marcellus and Utica dedication in DevCo III Wadestown: Proposed Pipeline Buildout ▪ Wadestown metering and regulation Facility - New 1.2 Bcf/d Dominion interconnect - Wadestown compressor station - Total buildout hor
Slide 57: Drop Down Inventory: Central PA Midstream Buildout
Drop Down Inventory: Central PA Midstream Buildout Central PA Utica: Five-Year Investment Outlook ▪ Currently undedicated to any midstream company ▪ Recent dry Utica well results proving commercial viability ▪ Opportunity to be first-mover midstream company to provide regional solution - Estimated 4
Slide 58: Virginia Coalbed Methane: Midstream (Cardinal States Gathering)
Virginia Coalbed Methane: Midstream (Cardinal States Gathering) Best-in-Class and Location ▪ Interconnects TransCanada TCO pipeline to premium Enbridge ETNG pipeline system ▪ “As is” 40% of the 250 MMcf/d capacity available to gather 3rd party gas and provide significant revenue source ▪ Provides pr
Slide 59: CNX Midstream Ownership Valuation
CNX Midstream Ownership Valuation CNX Midstream drives value CNX Midstream Value to CNX CNXM Represents Significant Growth for CNX in through four main avenues ($ in millions, except per share data) 2018E 2020E both IDRs and Retained EBITDA ▪ IDR cash distributions IDRs $4,000 (1) Cash Flow $ 12.7 $
Slide 60: Marketing
CNX Marketing Chad Griffith
Slide 61: Marketing Overview
Marketing Overview FIRM TRANSPORTATION HEDGE STRATEGY MARKET VIEW ▪ Selective FT commitments ▪ Foundation that enables the ▪ Current forward market - Utilize basis hedges to create execution of the company’s ▪ Supply/demand balance synthetic FT strategy ▪ Growing demand and exports ▪ Fraction of the
Slide 62: 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
Slide 63: 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
Slide 64: 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 $1.1 CNX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 (F
Slide 65: Differentiated Firm Transportation Portfolio
Differentiated Firm Transportation Portfolio Avg. Demand 1,600 Cost ($/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
Slide 66: 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 ▪
Slide 67: 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
Slide 68: 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
Slide 69: 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
Slide 70: 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
Slide 71: Finance
Finance Don Rush Chuck Hardoby
Slide 72: Corporate Values Guide Decision Making
Corporate Values Guide Decision Making AND KNOWLEDGE SET CNX ASSET BASE NAV/SHARE FOCUS RESPONSIBILITY CORPORATE 31% VALUES DISCIPLINED CAPITAL OWNERSHIP ALLOCATION STRATEGY EXCELLENCE FIVE YEAR ALIGNMENT OF EBITDAX CAGR(1) STAKEHOLDER INTERESTS (1) 2017-2022E based on midpoint of financial guidance
Slide 73: 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. 73
Slide 74: 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 ~$5 billio
Slide 75: Marketing: Natural Gas Hedging and Basis Protection
Marketing: Natural Gas Hedging and Basis Protection 400 350 Gas Volumes Hedged (Bcf) 43.3 300 250 200 375.9 44 12.1 ▪ Systematically layering in 150 290.6 72.3 hedges out to 2022 to protect 100 182 181.9 margins on proved developed 50 94.9 production and a portion of 0 PUDs (capex) 2018 2019 2020 20
Slide 76: Financial Guidance: 2018E-2020E
Financial Guidance: 2018E-2020E 2018E 2019E 2020E Revenue and Other Operating Income E&P Consolidated E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 450-475 505-575 610-700 NGLs (MBbls) 7,500-7,700 6,800-7,400 6,800-7,400 Oil (MBbls) 15-20 15-20 15-20 Condensate (MBbls) 590-
Slide 77: Financial Guidance: E&P 2018E
Financial Guidance: E&P 2018E 2018E Revenue and Other Operating Income E&P Production Volumes: Natural Gas (Bcf) 450-475 NGLs (MBbls) 7,500-7,700 Oil (MBbls) 15-20 Condensate (MBbls) 590-610 Total Production (Bcfe) 500-525 Basis calculated on 2018 market mix. % Liquids 9%-10% Hedge gain/(loss) calcu
Slide 78: Financial Guidance: 2018E E&P Revenue Buildup
Financial Guidance: 2018E E&P Revenue Buildup 2018E Revenue Revenue Volumes Realized Price ($ 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
Slide 79: 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
Slide 80: Financial Guidance: 2018E NGL Barrel Composition and Pricing
Financial Guidance: 2018E NGL Barrel Composition and Pricing Approximately $200 million in revenue 2018E “NGL Barrel” Composition ▪ 2018E liquids sold: Natural N-Butane gasoline - NGLs: 7,600 MBbls 9% 8% - Condensate: 603 MBbls I-Butane 5% - Oil: 18 MBbls Ethane 48% ▪ 2018E: 9-10% total production e
Slide 81: Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections
Financial Guidance: 2018E Natural Gas Hedging Gain/Loss Projections CY2018 CY2019 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (1) (000 MMBtu) Price Market ($/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
Slide 82: 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
Slide 83: 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 83
Slide 84: Capital Allocation Optionality Driving Value
CAPITAL ALLOCATION OPTIONALITY DRIVING VALUE 84
Slide 85: Capital Allocation Optionality Drives NAV/Share
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
Slide 86: Target Leverage Ratio Provides Capital Allocation Optionality
Target Leverage Ratio Provides Capital Allocation Optionality IRR ANALYSIS Share count Bolt-on Drill bit Balance sheet reduction acquisitions 86
Slide 87: 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%
Slide 88: 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
Slide 89: 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
Slide 90: 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)
Slide 91: 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
Slide 92: Finance Summary: 2014-2018+
Finance Summary: 2014-2018+ 2018+ Growing NAV/Share 2014- Company Transformation Growing EBITDAX Locking in Revenue and Returns 2017 and Balance Sheet Repair Ongoing Hedge Program Drill Bit IRR Analysis Continued Balance Sheet Share 2017 Optionality Repurchases Share Drilling Repurchases Program Beg
Slide 93: CNX is Designed and Managed Differently
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 o
Slide 94: Q&A
Q&A 94
Slide 95: Appendix
CNX Appendix
Slide 96: 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
Slide 97: 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
Slide 98: Stacked Pay: Gas Blending Driving NAV/Share
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 Marcellu
Slide 99: Stacked Pay: Marcellus/Utica vs. Marcellus/Upper Devonian
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
Slide 100: 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
Slide 101: 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) ($/MMBtu) NYMEX
Slide 102: Asset Portfolio Overview
Asset Portfolio Overview Marcellus Utica SWPA WV CPA OH Total SWPA WV CPA OH Total Total Net Acres 117,000 95,000 303,000 16,000 531,000 157,000 135,000 235,000 125,000 652,000 Net Developed Acres 21,600 5,900 6,100 200 33,800 100 0 400 20,000 20,500 Net Undeveloped Locations 582 190 1,249 102 2,123
Slide 103: Shirley-Pennsboro: Asset and Development Overview
Shirley-Pennsboro: Asset and Development Overview System Operating Area Shirley-Pennsboro – Capital Efficiency 4 Capital Efficiency (Mcfe/$)(1) 3 2.79 Mcfe/$ 2.33 Mcfe/$ 2 1.90 Mcfe/$ 1 0 Legacy JV CNX(2) CNX Future Development Shirley-Pennsboro Wells Pennsboro ▪ CNX’s future development represents
Slide 104: Leading Capital Efficiency in SWPA Marcellus
Leading Capital Efficiency in SWPA Marcellus Capital EUR Lateral Company Well Capital Total EUR Efficiency (Bcf/1000’) Length (Mcfe/$) CNX 2.8 $8,300,000 9,500 26.79 3.23 Peer 1 2.4 $9,050,000 9,500 22.80 2.52 SWPA Capital Efficiency 3.500 3.000 Capital Efficiency (Mcfe/$) 2.500 2.000 1.500 1.000 0.
Slide 105: WV Region Overview: Shirley-Pennsboro and East
WV Region Overview: Shirley-Pennsboro and East WV Shirley-Penns Marcellus Utica Undeveloped Net Locations 85 77 EUR (Bcfe/1000’) 3.0 2.8 Total NRI 85% 87% Total PDPs 42 - Net Current Production (Bcfe/d) 0.178 - ▪ Strong well results from enhanced completion techniques ▪ High BTU area that supplies l
Slide 106: Asset Region 4: Ohio Overview
Asset Region 4: Ohio Overview 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
Slide 107: Peer Benchmarking: Ohio Region - Dry
Peer Benchmarking: Ohio Region - Dry Capital EUR Lateral Total EUR Company Well Capital Efficiency (Bcf/1000’) Length (BCF) (Mcfe/$) CNX 3.2 $10,500,000 9,000 28.71 2.73 Peer 1 2.2 $9,056,250 9,000 19.80 2.19 Peer 2 2.6 $9,990,000 9,000 23.40 2.34 Peer 3 2.1 $10,832,000 9,000 18.90 1.75 Ohio Dry Uti
Slide 108: 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
Slide 109: 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
Slide 110: 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
Slide 111: 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
Slide 112: 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
Slide 113: 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
Slide 114: 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
Slide 115: 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
Slide 116: 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
Slide 117: Post-Spin Company Names and Stock Trading Symbols
Post-Spin Company Names and Stock Trading Symbols Effective November 28, 2017, the company known as CONSOL Energy Inc. (NYSE: CNX) separated its gas business (GasCo or RemainCo) and its coal business (CoalCo or SpinCo) into two independent, publicly traded companies by means of a separation of CoalC