Analyst & Investor Meeting Pittsburgh, Pennsylvania March 13, - - PowerPoint PPT Presentation

Analyst & Investor Meeting

Pittsburgh, Pennsylvania

March 13, 2018

Cautionary Language

2

• n them unduly.

• ther matters, pricing volatility or pricing decline for natural gas and NGLs; our operational relationship with other parties, including midstream facilities; operational risks relating to pipeline

• pportunities; our development and exploration projects, as well as CNXM's midstream system development.
• Reserves. Currently, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a

• Title. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to

• completeness. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CNX Resources Corporation or CNX Midstream Partners LP.

Agenda

3

Strategic Overview

Nick DeIuliis, Chief Executive Officer

Operations

Tim Dugan, Chief Operating Officer Andrea Passman, VP – Development

Marketing

Chad Griffith, VP – Marketing

Finance

Don Rush Chuck Hardoby, VP – Finance

Questions & Answers Business Development

Don Rush, Chief Financial Officer

Strategic Overview

Nick DeIuliis

154-Year Legacy is a Competitive Advantage

5 1980 2000 1860 1960 2008 2010 2014 2017 2018

The vast interwoven nature of the CNX acreage holdings has resulted in non-

• perated

well data from more than 800 Marcellus and Utica wells dating back to 1968

The Dominion assets CNX acquired in 2010 trace their roots to the late 1800s and John D. Rockefeller’s Standard Oil Company, which formed Consolidated Natural Gas Industrialist Andrew Mellon financed the consolidation of the coal estate throughout Appalachia leading to the founding of Consolidation Coal Company

Greater than the Sum of the Parts

6

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

Asset Base Creates Compelling Value Creation Opportunity

7

Large Contiguous Acreage Position 531,000 / 652,000 95.5% 18.6 Highly Productive Asset Base 1,116 MMcfe/d 20% 75% Leading Economic Profile $1.01-$1.11 /Mcfe 32% 3.3x

Net Marcellus Acres / Net Utica Acres(1) % Operated Reserves to Production (years) 2017 Average Net Production 5-Year Production CAGR Half-Cycle Portfolio IRR 2018E Total Cash Production and Gathering Costs 2017 EBITDAX Margin 2017 Recycle Ratio

7.6 Tcfe 3.7 Bcfe/1000’ 2.5x

Proved Reserves Current Deep Dry Utica Performance Targeted Leverage Ratio by YE2018

The CNX Strategy is to Grow NAV/Share via Capital Allocation

8

Strategy is reinforced by management philosophy, company values, incentive plans, and ownership

Key drivers of the strategy:

Methodical execution driving IRR and EBITDAX growth Basin disruption through stacked pay development Top-tier balance sheet Opportunistic share count reduction CNXM 15% distribution growth stability and drop inventory

$0 $500 $1,000 $1,500 $2,000 2018E 2022E $ in millions Low High

Methodical Execution Driving IRR and EBITDAX Growth

9

Expected Five-Year Plan Portfolio Economics

Drill Bit Investment Driving EBITDAX Growth

Stacked Pay Development Will Disrupt the Appalachian Basin

10

CNX has a non-replicable asset base allowing for stacked pay development

Stacked pay drives superior IRRs through economies of scale and greater flexibility ▪ Reduces capital ▪ Reduces cycle times ▪ Reduces LOE ▪ Reduces gathering and processing fees ▪ Seismic across acreage hold that de-risks drilling, completion, and production ▪ Increases utilization and efficiencies ▪ Extends growth opportunity

Stacked Pay Pad Economics Example

Stacked pay provides 30% increase to total field NPV

Top Tier Balance Sheet Strength Drives Capital Optionality

11

IRR ANALYSIS DRILL BIT BOLT-ON ACQUISITIONS SHARE COUNT REDUCTION STEADY STATE 2.5X LEVERAGE RATIO ROBUST HEDGE BOOK & FT STRATEGY DISCRETIONARY CASH FLOW ASSET MONETIZATIONS BALANCE SHEET CAPACITY

• 50

Leverage Ratio Capacity Allows for Share Count Reduction

12 Potential to reduce float ~40% by YE2022 under status quo plan

• r ~60% by YE 2022 with deployment
• f potential drop proceeds

Growing EBITDAX Creates Natural Capacity within 2.5x Leverage Ratio Available Capacity Reinvested in Share Count Reduction

Cumulative available capacity of ~$3 billion 2018-2022

Steady State Leverage Ratio: 2.5x

~$70/share

• n baseline

capacity(1) ~$30/share(1)

CNXM 15% Distribution Growth De-Risked

13

Expected CNXM Distributions to CNX 2017-2022E

CNXM Distributable Cash Flows by Source 2017-2022E

Compensation Plan Reinforces Strategy

14

Short-Term Incentive Compensation Program Long-Term Incentive Program (PSUs) 2016 2017 50% Relative TSR (S&P 500) 50% Absolute Stock Price Free Cash Flow Free Cash Flow Adjusted EBITDA/Share Company-wide short-term incentive plan Governed by 2.5x leverage ratio target Encourages return of capital to shareholders CEO compensation 90% at-risk (STIC, RSUs, and PSUs)

Compensation plans motivate management to execute on:

▪ Methodical operational execution ▪ Balance sheet discipline ▪ Basin disruption through stacked pay development ▪ CNXM growth stability and upside

• pportunities

▪ Share count reduction

2018 & Beyond

Importance of Both Numerator and Denominator in NAV/Share

15

NAV

SHARES OUTSTANDING

DRIVEN BY OPERATIONAL EXECUTION DIFFERENTIATED ASSET BASE GROWING RESERVES VALUE PRUDENT ASSET MONETIZATION OPTIMIZED VALUE OF MLP

Share count reduction can be the best capital allocation decision if it passes through the NAV and IRR filters =

NAV/Share Accretion & Recognition

BALANCE SHEET & HEDGE BOOK

Operations

Tim Dugan Andrea Passman

Unique Stacked Acreage Portfolio Sets the Stage

17

531,000

Total Net Marcellus Acres

582

Net Undeveloped Marcellus Locations in SWPA

652,000

Total Net Utica Acres

~90%

Total Company HBP

~89%

Total Company Average NRI

669

Net Undeveloped Utica Locations in SWPA Vast multi-formation acreage position built over 150+ years Premier gathering infrastructure and midstream MLP Monetization opportunities outside core development plan Modeling, delineation, and innovative solutions driven by decades of data Cutting edge strategic intelligence through extensive acreage position Multi-basin experience delivered by personnel and joint ventures ASSET BASE HIGHLIGHTS SKILL SET

Type Curve Guidance Areas Refined For Modeling Accuracy

18

▪ 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)

Capital Efficiency Continues to Improve

19

▪ NAV growth driven by

• ptimization and

stacked pay ▪ Increased EURs from model-driven spacing, completion design, and managed pressure drawdown ▪ Service cost inflation in 2017 offset by increased EURs Capital Efficiency (Mcfe/$)

1.83 Mcfe/$ 2.78 Mcfe/$ 2.78 Mcfe/$ 2.84 Mcfe/$

EUR Increases Driven by Modeling and Optimization

20

Modeling Maximizes NAV ▪ 85% increase in proppant loading from pre-2016 to 2018E ▪ Subsurface communication mitigation implemented ▪ Lateral spacing optimization ▪ Managed pressure drawdown ▪ Cluster diversion technology ▪ Min/max stress optimization ▪ 3-D seismic guided drill plans ▪ Core area delineation

1.7 2.7 2.9 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 <2016 2016-2017 2018E EUR (Bcfe/1000') 1.4 2.6 3.3 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 <2016 2016-2017 2018E EUR (Bcfe/1000')

Marcellus EURs Utica EURs

PDP Performance Drives Low Maintenance Capital

PDP Base Decline % Maintenance Capital

▪ Average maintenance capital of ~$325 million per year to hold exit rate flat at 1.39 Bcfe/d(2) ▪ Expected exit-to-exit base decline rate of 32% in FY2018, compared to FY2017

Possible Cumulative FCF of ~$1.4 billion 2019E-2022E

21

<20% in Q2 2019 <10% in Q2 2021

Drilling Days Declining Steadily in Every Region

22

Total Marcellus – Average Drilling Days per Well Ohio Wet Utica – Average Drilling Days per Well Ohio Dry Utica – Average Drilling Days per Well CPA Utica – Average Drilling Days per Well

5 10 15 20 25 30 2014 2015 2016 2017 2018E Drilling Days 5 10 15 20 25 30 35 2014 2015 2016 2017 2018E Drilling Days 10 20 30 40 50 60 70 80 2014 2015 2016 2017 2018E Drilling Days 20 40 60 80 100 120 140 2015 2016 2017 2018E Drilling Days

Completion Cycle Times Driving Capital Efficiency

23

Total Portfolio Completions Cycle Times Marcellus Completions Cycle Times

24

DEVELOPMENT PLAN

Shift to SWPA and Stacked Pay: Surplus Core Marcellus Inventory

Stacked Pay Factory up and running

20%

Production CAGR 2017-2022E(1)

50 100 150 200 250 300 350 400 450 Entering 2018 2018 2019 2020 Year End 2020 TIL Locations

▪ As CNX returns focus to the core SWPA region, the company is expected to consume only a fraction of existing CNXM DevCo I Marcellus locations in the near term

• This creates valuable optionality in the development plan
• Increases activity
• Extends stacked pay development
• Creates asset sale and swap opportunities

25

Stacked Pay Creates Substantial Uplift Beyond Longer Laterals

26

▪ Stacked pay PV10 is 4.4x unstacked pay PV10(1) ▪ Longer lateral PV10 is 1.9x shorter lateral PV10(1) ▪ Stacked pay is a more influential economic driver than only focusing on lateral length; CNX combines both value drivers in development ▪ Extending laterals delays turn-in-line, while stacked pays can be added at a later date optimizing IRR and EBITDAX

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

Technological Advances Driving Tangible Results

27

EARTH MODEL DATA ACQUISTION DESIGN OPTIMIZATION STACKED PAY FACTORY PORTFOLIO NAV OPTIMIZATION ▪ Fully integrated subsurface model ▪ Neural net drives productivity indicators ▪ Core, logs, seismic ▪ Third party data ▪ Delineation ▪ Testing ▪ Reservoir and frac modeling ▪ Managed pressure drawdown via rate transient analysis ▪ Machine learning ▪ System modeling ▪ Linear programming ▪ Big data analysis

Ensures highest NPV combination

• f fields while

balancing risk

Managed pressure drawdown improves EUR by 20%

Designs are

• ptimized in 3

wells vs. 13

Improves field NPV by 30%

Seismic de-risks SWPA stacked pay development and improves NAV by $60 million

Drove understanding of three Utica areas

Three Utica Areas Require Distinct Development Plans

28

OHIO UTICA ▪ Manufacturing play ▪ 3.2 Bcf/1,000’ ▪ 80’ of pay ▪ Low fracture intensity ▪ Optimized 10,500’ laterals ▪ 10,500’ TVD CPA UTICA ▪ Stacked pay play within the Utica and Point Pleasant ▪ 3.5+ Bcf/1,000’ ▪ 300’ of pay in Utica, Point Pleasant and Lexington ▪ 13,200’ TVD SWPA UTICA ▪ Stacked pay factory with Marcellus ▪ 3.2 Bcf/1,000’ ▪ 80’ of pay ▪ Intermittently fractured ▪ 12,000 TVD

The Utica is a Precision Play

29

Understanding reservoir characteristics in combination with facies drives productivity

OHIO (SWITZ) SWPA (RHL11E) CPA (Marchand3M)

Ohio Utica Model Drove SWPA and CPA Success

30

The model drove early success and eliminated the need for trial and error testing ▪ Ohio Utica is the analogue model for rapid SWPA and CPA Utica optimization ▪ Optimization of variable sand loading up to 3,000 lbs/ft within variable inter-lateral spacing up to 1,500’ ▪ Tail-in ceramic proppant ▪ Landing point defined by area

• Modeling defines target zone in a highly siliceous area

to maximize both drilling efficiency and well productivity

Legacy Base Optimized Fracture Conductivity (md-ft)

SWPA Utica: Very Strong Early Results from Richhill 11E

31

Drilled through series of natural fracture clusters, which were identified in 3D seismic analysis ▪ Required more drilling days than the expected run rate, which elevated drilling costs

• Elevated drilling costs offset by productivity of the well due to

natural fracture clusters Other additional costs related to completion design testing drove the RHL11E well to exceed target capital costs, but there is clear line of sight to the projected $14.3 million

RHL11E Summary

Lateral length(1) 6,200 Total capital less science $21 million Average flowing pressure 8,445 psig Average production(2) 22.1 MMcf/d Target flowing production @ flat first 12 months 18 MMcf/d

Richhill 11E SWPA Utica well currently flowing above 3.2 Bcfe/1000’ type curve Most Recent SWPA Utica Well

• n Path to Target Capital

SWPA Utica Requires Engineered Design

32

▪ Success is consistently hitting repeatable results by:

• Drilling on seismic
• Managed pressure drilling
• Cyber steering to improve in-zone

statistics

• Customized well layouts
• Engineered completion designs to
• ptimize for natural fractures and
• ver-pressured faults

▪ Target well cost in SWPA Utica: $14.3 million

Onondaga

SWPA Region Overview: Greater and Central

33

▪ Core focus area for future development ▪ Stacked pay approach for increased returns

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

SWPA Greater Marcellus Utica

Undeveloped Net Locations 191 231 EUR (Bcf/1000’)(1) 2.7 3.0 Total NRI 91% 91% Total PDPs 12

• Net Current Production (Bcfe/d)

0.082

• ▪

ACAA development drives SWPA Greater, with two pads completed to date

Morris Field Richhill Field Wadestown

SWPA Central: Focus of Activity in Three-Year Plan

34

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

• Morris-30 completed with enhanced stimulated reservoir

design

• Increased proppant loading, min/max stress optimization

along with the mechanical diversion testing program

• Changed targeted section of Marcellus to be drilled

▪ Morris pads being designed for future stacked pay development ▪ Morris wells expected to make up more than 65% of 2018E SWPA Marcellus TIL activity

11 46 55 73

10 20 30 40 50 60 70 80 2017 2018E 2019E 2020E TILs

SWPA Marcellus TILs: 2017 vs. Three-Year Plan ▪ SWPA Marcellus comprises a much larger portion of the three- year plan than in 2017

• Activity in the Morris, Richhill, and Wadestown fields driving

the increase

• Plan to run 2-3 rigs in region throughout the time period

▪ ~80% of three-year plan activity located in SWPA Central Marcellus/Utica Morris Production – Legacy vs. Now

Blending Strategy Helps Drive DevCo I Stacked Pay Economics

35

Requires Processing Does Not Require Processing

BTU Content 1110 1150 1100 1040 1010 1200 1070 Dry Tariff Line Wet Marcellus Gas Damp Marcellus Gas Dry Utica/Marcellus Gas

Damp acreage requires processing to meet BTU specifications

Blended Gas = Damp Marcellus + Dry Utica/Marcellus

▪ Avoids processing cost of $0.55-0.60/Dth ▪ Meets BTU tariff

• One Utica well required for every 3-4 damp Marcellus wells

Two Pipe Gathering System Creates Flexibility in DevCo I

36

Standard Gathering System

Industry Standard One-Pipe System CNX DevCo I Two-Pipe System

High Pressure Pipe Low Pressure Pipe

New Pad

(High Pressure)

Compression / Dehydration

As new high pressure wells are TIL, higher pressure gas supplants older low pressure wells choking back total production Planned compressor stations will create flexibility to customize pressures in specific gathering lines and

• ptimize marketing plans as

the project matures The low pressure pipe provides the option to continue producing existing wells rather than interrupt production when new higher pressure wells are brought online During stacked pay development, Marcellus and Utica wells can be brought

• nline simultaneously or

independently ▪ Most Marcellus producers lack the ability to rapidly bring on production as the single pipe systems stay near full capacity Existing Pad

(Low Pressure)

CHOKED Existing Pad

(Low Pressure)

New Stacked Pay Pad

(High Pressure and Low Pressure)

Richhill (RHL): Stacked Pay Development

37

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% ▪ 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

CPA Dry Utica Update: Aikens 5J and 5M

38

Aikens Wells EURs at 3.7 Bcf/1000’ ▪ Located in Westmoreland County, PA (CPA South region); two wells offsetting successful Gaut 4IH well ▪ Average capital per well: approximately $15 million ▪ Currently performing above CPA Utica 3.5 Bcf/1000’ EUR with an average lateral length of ~7,000’(1)

• Cumulative production for combined wells is 3.58

Bcf through first 77 days ▪ Wells averaged 23 MMcf/d during first 77 days of production with average flowing pressure of 8,419 psig

• Expect production to be flat for ~18 months

▪ Executing managed pressure drawdown ▪ Aikens 5J: validating Gaut 4IH results by replicating completion design and achieving similar results ▪ Aikens 5M: testing higher proppant loading and model driven ceramic selection

• The Aikens 5M well is on track to be the second

best well in the basin to date Aikens 5J Aikens 5M

UTICA

Stacked Utica with Utica in CPA

39

▪ Utica, Point Pleasant and Lexington are all gas bearing contributing zones with a total thickness of nearly 300’

• Verified by the Marchand

core and logs ▪ Potential to multiply Utica locations within CPA by stacking multiple wellbores in the 300’ section to maximize recovery from the pay zone ▪ Simultaneous development

• f Utica stacked laterals may

maximize recovery through pressure shadowing and eliminate future infill drilling

LEXINGTON

2018 Stacked Pay Baseline $30.0 $10.9 $6.4 $2.9 $0.4 $0.8 2018 Stacked Pay Baseline Lateral Length Increase Technology Utilization Mineral Purchase Optimization Data Analytics LOE Efficiencies

“Perfect Pad” to Create Stacked Pay Benchmark in 2019

40

12 Marcellus wells drilled

Process

Dry month construction Subsurface Marcellus well heads Marcellus completions 8 Utica wells drilled Utica completions 3D seismic drives well bore optimization Marcellus wells turned in line

M M M M M M M M M M M M U U U U U U U U

Utica wells turned in line

Cellar technology construction allows for subsurface well heads for faster return Two pipe system creates flexibility to produce high pressure and low pressure wells simultaneously

M M M M M M M M M M M M Prior Days Target Days 120 90 122 97 142 78 124 102 119 57

Optimal inter-lateral spacing: Marcellus 750 ft, Utica 1200-1500 ft Combined NPV Gains from Marcellus & Utica in SWPA Perfect Pad Incremental NPV

• f ~$21 million

31% Reduction 35% Reduction

Central PA Overview: North and South

41

▪ Gaut & Aikens wells have proved area for Utica development ▪ Potential to stack Marcellus with Utica ▪ Continue to explore opportunities to expand gathering infrastructure

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

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

Development Areas in Three-Year Plan

42

CPA South ▪ Utica SWPA Central ▪ Marcellus and Utica SHR/PENS ▪ Marcellus OH Dry ▪ Utica

Three-Year Drill Schedule and Estimated Reserves Growth

43

TD Count 2018 2019 2020 Total SWPA Marcellus 62 60 71 193 SWPA Utica 3 19 27 49 WV Marcellus 5 10 15 30 CPA Utica 4 9 13 OH Utica 8 8 Total 82 89 122 293

Reserve Growth and Estimates 2015-2022E

Rig Schedule 2018E-2020E

Low High

Three-Year Development Plan

44

2018E 2019E 2020E

($ in millions) TD FRAC TIL Capex TD FRAC TIL Capex TD FRAC TIL Capex SWPA Central Marcellus 62 48 46 60 52 55 71 78 73 Utica 3 1 1 19 14 14 27 28 28 WV Shirley-Penns Marcellus 5 5 5 10 10 7 15 11 11 Utica

• CPA South

Utica 4 4 2

• 1

3 9 5 3 OH Dry Utica 8 10 15

• OH Wet(1)
• 5

5

• 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: Richhill 11E TIL Feb. 2018 14 SWPA Central dry Utica wells 28 SWPA Central dry Utica wells Indiana County, PA Dry Utica: Marchand 3M TIL set for Q3 2018 3 CPA deep dry Utica wells

Notable Wells

Business Development

Don Rush

Track Record of Success: History of Monetizing Assets

46

▪ Annual average of ~$600 million in asset monetization from 2014-2017 ▪ $414 million in assets sold in 2017 ▪ 2018 effort continues

• Shirley-Pennsboro midstream asset drop netted

$265 million in proceeds

• Shallow Oil & Gas (SOG) transaction in February:

$85 million in cash plus $190 million in liabilities related to gas well plugging (asset retirement

• bligations)

Future opportunities include: ▪ Non-core upstream assets ▪ Drops to CNX Midstream ▪ CNXM LP Units and IDRs ▪ Shale acres not in near-term development plan

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500

Asset Sale Totals by Year

Dry powder of ~$4 billion in drop down and other non-core asset sales from 2019-2022 provides substantial upside to current plan

SOG Sale Drives Continued Reduction in Legacy Liabilities

47

Conventional Shallow Oil and Gas (SOG) assets sold in West Virginia and Pennsylvania, including CBM(1) ▪ Agreement signed mid-February

• Expected close by end of March

▪ 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 SOG Wells Included in Sale

Virginia Coalbed Methane (CBM): Upstream

48

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

Ohio Utica Joint Venture Overview

49

Low Risk, Mature Development

▪ 65% fee ownership, 46.5% avg. NRI (93% gross JV NRI) ▪ 31 gross operated JV wells (Noble County) ▪ 65 gross non-op JV wells, 47 non-op gross 3rd party wells ▪ ~85 MMcfe/d net production (~170 MMcfe/d net to JV production) ▪ 72% gas, 26% NGL, 2% condensate 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 ▪ Sell the JV asset ▪ Divide assets to obtain 100% WI with JV partner ▪ Drill the assets per the governing agreements 14,000 gross acres 29,000 gross acres 36,000 gross acres

50

CNX MIDSTREAM

ASSET AND OPPORTUNITY

De-Risked CNX Midstream Growth Driving CNX Upside

51

Ability to sustain 15% CNXM distribution growth is projected without additional asset drops

Coverage Ratio(1)

1.25x 1.56x 1.44x 1.31x 1.21x

CNXM Distributable Cash Flows by Source 2017-2022E

Drop Inventory Drives Meaningful Upside to CNXM 15% Growth

52

Completed Year-To-Date

▪ Shirley-Pennsboro system: February 2018

• $265 million: Expected to add $22-$24 million of pro

forma 2018 EBITDA for CNXM growing to $40-$50 million in 2020E

CNX Retained Undropped EBITDA including Potential Drop Candidates 2017 vs. 2020E

Potential Candidates 2018E-2020E

CONVEY Water Business Existing DevCos Primarily Wadestown in DevCo III CPA Utica Gathering System Cardinal States Gathering System

$- $50 $100 $150 $200 2017 2017PF for S/P Drop 2020E $ in millions Retained Undropped EBITDA Potential

CONVEY: CNX’s Water Business

53

Annual Volume of Water Moved Projected Water Infrastructure: YE2018

PA WV OH Total Cumulative Water System CapEx ($ millions) $219 $94 $17 $330 Water Pipelines (miles) 189 79 33 301 Water Storage Facilities (MMBbl) 1.2 0.6 0.3 2.1 Total Water Moved (MMBbl) 33 4 8 45

• 20

Wadestown SWPA Buildout

CONVEY: Major Projects

54

Wadestown Development

▪ ~$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 54

SWPA Water Build Out

▪ ~$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

$- $20 $40 $60 $80 $100 $120 $140 2017 2018E 2019E 2020E

CONVEY: Drives High Distribution Growth Rate

55

~$55 million water EBITDA at proposed rates in 2018(1)

▪ Driven by margin on CNX fresh, reuse, and disposal rates ▪ Final rates to be determined at time of drop ▪ Produced water accounts for 18% of 2018 proposed EBITDA

Over 100 miles of new water infrastructure to begin in 2018

▪ Ohio River to SWPA fresh water supply line ▪ Richhill and Majorsville infrastructure ▪ Wadestown development infrastructure

Fixed rates promote efficiencies for water operations

▪ CONVEY will continue to drive down costs to increase margins ▪ CNXM will benefit from cash flow stability

Steady Water EBITDA Growth(1)

Assumed Water Operating Costs ($/Bbl)(2)

PA WV OH Fresh $0.95 $0.91 $1.62 Reuse $3.48 $4.78 $5.82 Disposal $8.12 $5.89 $7.11

Infrastructure supply upgrade complete

Drop Down Inventory: Wadestown

56

Wadestown: Five-Year Investment Outlook ▪ Greenfield Marcellus and Utica dedication in DevCo III ▪ Wadestown metering and regulation Facility

• New 1.2 Bcf/d Dominion interconnect
• Wadestown compressor station
• Total buildout horsepower 42,750

▪ Pipelines: 39 miles Expected Midstream Capital and EBITDA 2018E-2020E

Wadestown: Proposed Pipeline Buildout

Drop Down Inventory: Central PA Midstream Buildout

57

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

Virginia Coalbed Methane: Midstream (Cardinal States Gathering)

58

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 premium market outlet for CNX and 3rd 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

CNX Midstream Ownership Valuation

59

CNX Midstream drives value through four main avenues ▪ IDR cash distributions ▪ Ownership of LP units ▪ Retained EBITDA ▪ Future drop downs CNXM Represents Significant Growth for CNX in both IDRs and Retained EBITDA

CNX Midstream Value to CNX ($ in millions, except per share data) 2018E 2020E IDRs Cash Flow(1) 12.7 $ 40.8 $ Multiple(2) 60.0x 30.0x Value 761 $ 1,223 $ LP Units Unit Price(3) 18.20 $ 30.19 $ Current Yield 7.5% 6.0% Units Held 21.69 21.69 Value 395 $ 655 $ Pro Rata EBITDA Contribution Retained EBITDA(5) 10 $ 200 $ Market Multiple 8.0x 8.0x Value 80 $ 1,600 $ Total Potential Value 1,240 $ 3,480 $ Value per CNX Share(6) 5.60 $ 15.80 $

$1,240 $3,480 $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 2018E 2020E $ in millions IDRs LP Units Pro Rata Retained EBITDA Contribution

Marketing

Chad Griffith

MARKET VIEW

▪ Current forward market ▪ Supply/demand balance ▪ Growing demand and exports ▪ Volatility is king

Marketing Overview

61

FIRM TRANSPORTATION

▪ Selective FT commitments

• Utilize basis hedges to create

synthetic FT ▪ Fraction of the FT obligations compared to peers ▪ Low FT average demand costs

• f approximately $0.29 per

MMBtu

HEDGE STRATEGY

▪ Foundation that enables the execution of the company’s strategy ▪ Differentiates CNX and provides competitive advantage ▪ “Total” hedge: matching basis to NYMEX ▪ Programmatic – dollar cost averaging ▪ Hedge volumes in alignment with capital investment

Firm Transportation Strategy

62

▪ CNX realizes average NYMEX differentials with 1/8th of the average “take-or-pay” FT obligation of peers ▪ CNX instead uses a strategic mix of FT, IT, basis hedging, gathering system optionality, and capacity releases

• Diff. to NYMEX

Transportation, Gathering, & Processing Commitments and Differentials(2)

Three-Filter Test for Taking on New FT

1 2 3

Do we need it to get it to a liquid market? Does it get us to a better market at a positive net back? Does it help us manage the volatility of the markets we’re in?

Project Examples: Future Spreads vs. Demand Charges(1)

Liquidity of In-Basin Markets Negates Need for FT

63

Average Daily Production and Takeaway 2018E-2020E (Bcf/d) 2018E 2019E 2020E CNX Gas Production(1) 1.3 1.5 1.8 Less: Estimated Production Sold Directly into Basin (M2)(2) not requiring FT 0.3 0.3 0.4 Gas Production Sold via FT 1.0 1.2 1.4 Current FT Capacity 1.2 1.5 1.4

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

Peer Firm Transportation Benchmarking

64

Total FT and Processing Commitments

(FT Commitments + 2018E Adjusted Net Debt) / 2018E EBITDAX(1)(2)(3)(4) (FT Commitments + 2018E Adjusted Net Debt) / Adjusted EV(1)(2)(3)

Total FT Commitments + 2018E Adjusted Net Debt(1)(2)(3)

Differentiated Firm Transportation Portfolio

65

• 200

ETNG TCO Pool Michcon

WLA M3 M2

Dominion South

• Avg. Demand

Cost ($/Dth)

(000s Dth/d)

2018E 2018E

DOM South 345 ETNG 201 TCO Pool 475 Michcon 162 TETCO ELA 30 TETCO WLA 50 TETCO M3 100 TETCO M2 125 1,488 $0.29

Unutilized FT (reported in “Other Operating Expense”)

▪

Approximately 370,000 MMBtu/d in unused FT on Dominion South and TCO

• Acquired as part of Dominion transaction in 2010
• Current drilling plans do not consider geographic area

where unutilized FT resides

▪

Forecasted for 2018E at approximately $36 million

• Expect to offset expense by reselling approximately $10

million per year

▪

Contracts expire in 2021 and 2022

▪

TCO Pool includes: 200,000 MMBtu/d on TCO’s Mountaineer XPress project and 50,000 MMBtu/d of capacity on TCO’s Leach XPress project in connection with the Marcellus JV dissolution

Natural Gas Basis Risk and Financial Reporting Clarity

66

▪ Historical basis derived by first of month settle prices indicates extreme volatility over the past two years

• Basis varies between $(0.39) and $(2.11) over two year

stretch(1)

Historical Basis Volatility

Fully-hedged volumes provide revenue certainty and de-risks capital expenditures

▪ CNX hedges basis in addition to NYMEX ▪ Peers primarily only hedge NYMEX, which is a partial hedge

• Completely exposed to floating basis risk

Basis hedging and hedge reporting example

▪ October NYMEX settles @ $3.30 & M2 Basis settles @ ($1.10); M2 price of $2.20 Hedge Reporting Example CNX Company A NYMEX Hedge $3.00 $3.00 Basis Hedge ($0.50) None Henry Hub Settle $3.30 $3.30 M2 Basis Settle ($1.10) ($1.10) NYMEX Hedge Payout ($0.30) ($0.30) M2 Basis Hedge Payout +$0.60 n/a Physical Gas Sale Price +$2.20 +$2.20 Actual Realized Sale Price $2.50 $1.90 ▪ CNX would report fully-hedged price of $2.50 and receive $2.50 ▪ Company A would report hedged price of $3.00, but receive only $1.90

Power Plants and LNG Driving Demand Growth

67

14.7 Bcf/d incremental demand from gas fuel type power plants by 2025

▪ CNX acreage in the center of the largest growth market, PJM

An additional 14.6 Bcf/d is proposed

Increased Gas Demand from Planned Power Plants

2 4 6 8 10 12 14 16 18 20

Bcf/d

LNG Expected Growth 2018-2022

13.9 Bcf/d LNG Export capacity by 2022

▪ An additional 11.6 Bcf/d is proposed without a target in-service date (1)

Natural gas exports to Mexico via pipeline increased to 4.2 Bcf/d in 2017(2)

NE Expansion Projects Remove Export Bottleneck

68

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)

Pipeline Expansion Project Takeaway Capacity

Supply/Demand Fundamentals

69

Basin Demand Expected to Increase ▪ Roughly 6 GW of natural-gas fired power plant capacity in Pennsylvania in 2018 (1) ▪ 20 GW capacity in 2018 across US ▪ Percentage of electricity generation from natural gas expected to increase to 33.1% in 2018 from 31.7% in 2017 (1)

Regional Basis Narrows as Takeaway Capacity and Demand Increase

Henry Hub and Dominion South Pricing (Historical First of Month and Forward Strip)

▪ 2018 gas consumption expected to increase 3.5 Bcf/d to 77.5 Bcf/d and increase an additional 2.2 Bcf/d in 2019(1)

• 2018 HDD expected to be 11% higher than 2017(1)
• Power generation expected to increase 3.2 Bcf/d in 2018

▪ Net exports expected to increase 1.9 Bcf/d in 2018 and an additional 2.3 Bcf/d in 2019 (1)

• LNG exports expected to increase from 1.9 Bcf/d in 2017 to

3.0 Bcf/d in 2018 and ramp up to 5.5 Bcf/d by end of 2019 (1)

• Natural gas exports to Mexico rose 0.4 Bcf/d in 2017 and

expected to continue on same trajectory (1)

• Natural gas imports expected to drop 0.3 Bcf/d in 2018 (1)
• US was net exporter of natural gas in 2017 for first time

since 1957 (1) ▪ 2017 storage dropped 6% below the five year average and is expected to be roughly 6% below five year average by end of 2019 (1) ▪ 2017 production of 73.5 Bcf/d remained flat relative to 2016 levels, but an increase of 6.9 Bcf/d is expected for 2018 (1)

• Increase fueled by pipeline takeaway projects (1)

Liquids and Processing Summary

▪ CNXM and other wet gathering systems provide optionality for CNX wet production ▪ Optionality provides many benefits, including:

• Residue market optimization
• Access to existing, excess processing capacity
• Avoids being captive customer

▪ NGLs are generally marketed by processing companies – more efficient to outsource ▪ NGL pricing guidance based on contracts in place, NGL forward market, CNX view of supply/demand/transportation fundamentals, and certain hedging programs of processing companies ▪ $13 million in unutilized processing commitments forecasted for 2018E

Contracted Processing Capacity

MarkWest Blue Racer Dominion

365 MMcf/d

70

Finance

Don Rush Chuck Hardoby

Corporate Values Guide Decision Making

72

CORPORATE VALUES RESPONSIBILITY OWNERSHIP EXCELLENCE

CNX ASSET BASE AND KNOWLEDGE SET

NAV/SHARE FOCUS DISCIPLINED CAPITAL ALLOCATION STRATEGY ALIGNMENT OF STAKEHOLDER INTERESTS

31%

FIVE YEAR EBITDAX CAGR(1)

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 2018E 2019E 2020E 2021E 2022E

Low High

Strategy Resulting In Substantial EBITDAX Growth

73

Expected EBITDAX 2018E-2022E(1)

Balance Sheet Capacity and Dry Powder Upside through 2022E

74

Dry powder of ~$4 billion through 2022E consists of potential drop proceeds, tax refunds, CNXM LP/GP monetization, and non-core asset sales

~$5 billion

$- $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 Drop Candidates Retained EBITDA @ 8x Multiple YE2017 Alternative Minimum Tax Refund CNXM LP Unit/IDR Monetization Non-Core Asset Sales Total Dry Powder + B/S Capacity @ 2.5x Leverage Ratio

Balance sheet capacity at a steady 2.5x leverage ratio comprises another ~$3 billion in available capital

Dry Powder ~$4 billion Balance Sheet Capacity ~$3 billion

Marketing: Natural Gas Hedging and Basis Protection

75

▪ Systematically layering in hedges out to 2022 to protect margins on proved developed production and a portion of PUDs (capex) ▪ Locking-in revenue and de- risking capital decisions by matching NYMEX and basis hedge volumes ▪ Protecting from in-basin blowout through regional basis hedges ▪ Approximately 81% of total 2018E gas volumes hedged(3)

Hedge Volumes and Pricing Q1 2018 2018 2019 2020 2021 2022 NYMEX Hedges Volumes (Bcf) 88.4 358.6 321.0 215.0 172.6 153.4 Average Prices ($/Mcf) $3.14 $3.14 $3.02 $3.09 $3.00 $3.05 Physical Fixed Price Sales Volumes (Bcf) 4.3 17.3 12.9 11.0 21.4 13.8 Average Prices ($/Mcf) $2.61 $2.61 $2.49 $2.44 $2.45 $2.54 Total Volumes Hedged (Bcf)(1) 92.7 375.9 333.9 226.0 194.0 167.2 NYMEX + Basis (fully-covered volumes)(2) Volumes (Bcf) 92.7 375.9 290.6 182.0 181.9 94.9 Average Prices ($/Mcf) $2.76 $2.76 $2.69 $2.76 $2.53 $2.48 NYMEX Hedges Exposed to Basis Volumes (Bcf)

• 43.3

44.0 12.1 72.3 Average Prices ($/Mcf)

• $3.02

$3.09 $3.00 $3.05 Total Volumes Hedged (Bcf)(1) 92.7 375.9 333.9 226.0 194.0 167.2

Financial Guidance: 2018E-2020E

76

2018E 2019E 2020E

Financial Guidance: E&P 2018E

77 Transportation, gathering and compression costs expected to decline $0.15-$0.20 year-over-year primarily due to increased contribution of lower cost dry Utica volumes in Monroe County, OH Unutilized FT and Processing Fees: $50 million Idle Rig Fees: $5 million Basis calculated on 2018 market mix. Hedge gain/(loss) calculated on NYMEX and financial basis hedges

2018E

Royalty income, right of way sales, interest income and ‘other’ all netted against bank fees, other corporate expense, and other land rental expense

Financial Guidance: 2018E E&P Revenue Buildup

78

2018E Revenue Volumes Realized Price Revenue

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

Financial Guidance: 2018E Natural Gas Marketing Mix and Basis

Northeast Pipeline Projects Southeast Pipeline Projects

Dawn Pipeline Projects Gulf Market Pipelines

Percentages include physical sales

Volumes 2018E CY 2018 (000 MMBtu) Gas Sold (%) Basis DOM South 45,074 9% ($0.67) ETNG/Cascade Creek TZ5 9,097 2% $0.34 TCO Pool 46,899 10% ($0.26) TETCO ELA & WLA 6,112 1% ($0.09) TETCO M3 29,235 6% $0.23 TETCO M2 209,567 43% ($0.67) Michcon 28,315 6% ($0.21) Physical basis sales 112,945 23% $0.02 Total (000 MMBtu) 487,244 100% ($0.36) Total (MMcf) 463,000 NYMEX $2.78 Weighted Average Basis (Not considering hedging) ($0.36) 2018E Average Realized Price (per MMBtu) $2.42 Conversion Factor (MMBtu/Mcf) 1.054 2018E Average Realized Price (per Mcf) $2.55 BTU Uplift $0.13 Market 79

Financial Guidance: 2018E NGL Barrel Composition and Pricing

Approximately $200 million in revenue 2018E

▪ 2018E liquids sold:

• NGLs: 7,600 MBbls
• Condensate: 603 MBbls
• Oil: 18 MBbls

▪ 2018E: 9-10% total production expected to be liquids ▪ Total expected price for NGLs in 2018E of $23-$24/Bbl ▪ Total weighted average price of liquids in 2017 was $25.53/Bbl ▪ Contractual obligations to recover ethane (INEOS)

• Those contracts currently yield better pricing for the ethane

than selling it as a natural gas equivalent

Ethane 48% Propane 30% I-Butane 5% N-Butane 9% Natural gasoline 8%

Low High Midpoint

NGL $23.00 $24.00 $23.50 Condensate (% of WTI) 70% Oil (% of WTI) 100%

Weighted Average NGL ($/Bbl) “NGL Barrel” Composition

80

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

81

▪ In addition to NYMEX and basis financial hedges, CNX has physical fixed basis sales and physical fixed price sales with customers ▪ CY 2018 physical fixed basis sales: 89.6 Bcf ▪ CY 2018 physical fixed price sales: 17.3 Bcf ▪ Physical sales provide additional basis hedge

• Flows through gas sales in financials

Financial Guidance: 2018E E&P EBITDAX Buildup

82

E&P EBITDAX + Attributable CNXM EBITDA $825-$850 million

Financial Guidance: 2018E CNXM EBITDA Attributable to CNX

83

$0 $50 $100 $150 $200 $250 Total Revenue (100% of CNXM) Operating Expense General & Administrative EBITDA EBITDA Attributable to CNX $ in millions

Non-Controlling Interest

$60-$65 million

84

CAPITAL ALLOCATION

OPTIONALITY DRIVING VALUE

Capital Allocation Optionality Drives NAV/Share

85

▪ 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

January 2016

Capital Allocation Driven

Balance sheet strength and financial flexibility allow CNX to choose its path forward via strategic capital allocation

86

Drill bit Share count reduction Bolt-on acquisitions Balance sheet

Target Leverage Ratio Provides Capital Allocation Optionality

IRR ANALYSIS

Capital Allocation Optionality: Drill Bit IRR Opportunities

87

Summary Assumptions ▪ Gas pricing: $2.50/MMBtu ▪ NGL pricing: $25/Bbl ▪ CND pricing: $45/Bbl Full Cycle Assumptions(1) ▪ Capital Expenditures(2):

• Includes D&C, midstream, water

infrastructure and land ▪ Operating Expenses:

• Includes lifting, gathering(3), utilized FT,

general & administrative and production taxes Half Cycle Assumptions(1) ▪ Capital Expenditures(2):

• Includes only D&C and midstream

▪ Operating Expenses:

• Includes only lifting, gathering(3) and

production taxes

Transaction Volume

Portfolio IRR Summary: Five Year Plan Five-Year Plan Capital Allocation by Region

SWPA 82% CPA 10% OH 2% WV 6%

• 50

100 150 200 250 2017 2018E 2019E 2020E 2021E 2022E $- $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 Shares Outstanding (millions) Market Cap ($ in millions) Market Cap Shares Outstanding - Including Drop Proceeds Shares Outstanding - No Additional Sales/Drops

Capital Allocation Optionality: Share Buybacks

88

Share Reduction 230.1 million 223.8 million

Additional 90+ million share reduction(2)

Q3 2017 End Year-End 2017 2018E-2022E Buyback Potential As of:

S/O:

219.8 million

As of 3/6/2018

Potential share count reduction of ~60% by year-end 2022 including additional drop proceeds

▪ Prior to spin:

• 6.4 million shares repurchased at average price
• f $16.08(3)
• Accounting for value of associated CEIX shares,

repurchased shares have appreciated 36% compared to recent market prices(3) ▪ Since spin:

• 4.0 million shares repurchased at an average

price of $13.95 appreciated 28% compared to recent market prices(3) ▪ Approximately $300 million remaining on share repurchase authorization for 2018 ▪ CNX refused to issue equity during the downturn when most of its peers did

• As a result, longer term shareholders are seeing

the benefit of the discipline compounded by the share repurchases happening now

~$110/share with drop proceeds(1)

$0 $100 $200 $300 $400 $500 $0 $1,000 $2,000 $3,000 $4,000 $5,000 2012 2013 2014 2015 2016 2017 2018E

Annual Cash Servicing Costs ($ in millions) Long-Term Liabilities ($ in millions)

Long-Term Liabilities Total Annual Cash Servicing Cost

Rehabilitated Balance Sheet Sets New Beginning

89

Long-term liabilities now <$60 million with annual cash servicing costs of <$5 million

Long-Term Liabilities Reduced by More than $4 Billion Over last Six Years

2018E hedge book and production ramp sets clear path to

<2.5x net debt / EBITDAX

Capital Allocation: Balance Sheet

90

Total Debt YE 2017 YE 2018E Balance Sheet Highlights(1) Cash Net Debt Leverage Ratio(2)(4) – LQA Leverage Ratio(3) - TTM

$2,232 $1,980 $509 $25 $1,723 $1,960 2.5x

• 3.6x

2.4x

CNX EBITDAX Less Sensitive to Commodity Swings

Each $0.25 decline in HH price yields only a $35 million decline in 2018E EBITDAX

Total Liquidity

$1,770 $1,700

$ in millions

Leverage Ratio(2)(3) – NTM

2.1x 2.1x

Tax Reform and NOLs Create Tailwind

91

▪ Tax reform law states that Alternative Minimum Tax (AMT) amounts can be refunded at 50% in first year

• Expect to receive first proceeds in 2019: ~$95 million
• Remainder of $188 million AMT refund expected over

subsequent years

• Total figure is an estimate and could increase

▪ Following the spin transaction, CNX retained the corporate tax attributes

• Approximately $475 million in federal net operating losses

(NOLs) with a cash value of about $95 million

• NOLs prior to 2018 can be used to offset 100% of future

taxable income

• As a result, expect to pay no cash taxes for roughly 4-5

years ▪ Additional NOLs projected with sale of SOG that are likely to further delay cash tax obligation ▪ Intangible drilling costs (IDCs) will be 100% deductible in year one or can be amortized over five years

• In conjunction with NOLs, IDCs create flexibility to

minimize cash tax burden for many years

December 31, 2017 2016 Deferred Tax Assets: Alternative minimum tax $ 188,080 $ 219,872 Net operating loss - State 107,756 74,310 Net operating loss - Federal 99,524 144,450 Foreign tax credit 44,402 39,850 Gas well closing 16,648 20,512 Salary retirement 9,404 16,928 Capital lease 2,020 3,210 Gas derivatives — 72,105 Other 33,697 48,961 Total Deferred Tax Assets 501,531 640,198 Valuation Allowance (136,576) (282,778) Net Deferred Tax Assets 364,955 357,420 Deferred Tax Liabilities: Property, plant and equipment (385,366) (450,695) Gas derivatives (15,248) — Advance gas royalties (3,648) (5,824) Equity Partnerships (1,251) (2,237) Other (3,815) (3,760) Total Deferred Tax Liabilities (409,328) (462,516) Net Deferred Tax Liability $ (44,373) $ (105,096)

Finance Summary: 2014-2018+

92

Company Transformation and Balance Sheet Repair

Share Repurchases Begin Drilling Program Expanded

2017 2014- 2017

Growing EBITDAX Balance Sheet Optionality

Continued Share Repurchases Bolt-On Acquisitions Drill Bit

2018+

Growing NAV/Share

Ongoing Hedge Program Locking in Revenue and Returns IRR Analysis

CNX is Designed and Managed Differently

93

Strategy is reinforced by management philosophy, company values, incentive plans, and ownership

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%

94

Q&A

Appendix

Stacked Pay: Pad Level Benefits

96

▪ 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

Stacked Pay: What are the Main Advantages?

97

Marcellus Utica Unstacked Stacked Unstacked Stacked LOE ($/Mcf) 0.10 0.05 0.04 0.04

• Gath. Rate ($/Mcf)

0.96 0.38 0.37 0.24 CapEx ($ in millions) 8.4 8.3 14.6 14.3

Stacked Pay Pad Economics Example

▪ Reduces capital

• Pre-spud capital nearly eliminated for second formation
• Use existing fuel gas to power D&C operations

▪ Reduces cycle times

• Pad & facilities already constructed
• Midstream and water infrastructure already in place

▪ Reduces LOE

• Driven by higher well count & concentrated volume
• Maintenance efficiency on infrastructure

▪ Reduces gathering fees

• Dry and wet gas can be blended to avoid processing fees
• Combining formations reduces gathering rate on Utica
• Processing flexibility to capture NGL upside in market

▪ 3D seismic de-risks & optimizes D&C across all pay zones

$2.00 $2.50 $3.00

Stacked Pay: Gas Blending Driving NAV/Share

98

▪ Midstream pipeline tariffs require Marcellus gas above 1110 BTU be processed ▪ Processing damp gas between 1100-1150 BTU range is NPV destructive ▪ Solution: Develop dry Utica concurrent to damp Marcellus and blend to avoid processing

• Avoids processing & increases gathering

efficiency

• Allows capture of BTU value of damp gas
• Blending solutions drive long term synergies

with CNXM

Unstacked Stacked Delta Well Count 240 240

• CapEx ($ in millions)

$2,761 $2,700 ($61) NPV ($ in millions) $1,306 $1,616 +$310 BTAX IRR 48.4% 59.4% +11.0%

Lateral Feet to Blend by BTU to Equal 1100

Stacked Pay: Marcellus/Utica vs. Marcellus/Upper Devonian

99

▪ Stacked Pay with Marcellus and Utica yields a higher NPV than stacking Marcellus with Upper Devonian wells ▪ Stacking wet gas Marcellus wells with dry gas Utica wells gives the optionality to blend or process the gas depending on NGL market conditions ▪ An Upper Devonian well yields ~60% of the production of a Marcellus well for similar capital 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

• 0.50

Normalized NPV (NPV/Foot)

Detailed IDR Model: Assuming 15% Distribution Growth

100

Guidance: Natural Gas Hedging – Gain/Loss Projections

101

Asset Portfolio Overview

102

Marcellus Utica

SWPA WV CPA OH Total SWPA WV CPA OH Total

Virginia CBM ▪ ~270,000 contiguous acres, 100% WI ▪ 88% HBP, 87.5% NRI ▪ ~4,000 PDPs at 165 MMcf/d

Shirley-Pennsboro Wells

Shirley-Pennsboro: Asset and Development Overview

103

▪ CNX’s future development represents a 47% increase in capital efficiency (Mcfe/$) compared to legacy wells

• 28% increase in EUR/1000’ driven by enhanced stimulated reservoir design and
• ptimization of inter-lateral spacing
• EUR/1,000’: Shirley 3.0 Bcfe; Pennsboro 2.6 Bcfe
• BTAX IRR at $2.50 realized price: Shirley 38%; Pennsboro 35%
• 18% decrease in fully-loaded D&C capital per lateral foot compared to the

legacy JV wells ▪ Reduced capital driven by operational excellence:

• Achieved record completion speed of 2,250 ft/day or 10+ stages in a 24 hour

period

• Achieved record drill-out speed of 8,400 ft/day

▪ The Shirley-Pennsboro field contains 50+ future wells that will be part of the core development plan ▪ Expected to add $22-$24 million of pro forma 2018 EBITDA for CNXM growing to $40-$50 million in 2020E

Shirley-Pennsboro – Capital Efficiency

System Operating Area

Shirley Pennsboro

Leading Capital Efficiency in SWPA Marcellus

104

• 0.500

SWPA Capital Efficiency

Company EUR (Bcf/1000’) Well Capital Lateral Length Total EUR Capital Efficiency (Mcfe/$) CNX 2.8 $8,300,000 9,500 26.79 3.23 Peer 1 2.4 $9,050,000 9,500 22.80 2.52

WV Region Overview: Shirley-Pennsboro and East

105

▪ Strong well results from enhanced completion techniques ▪ High BTU area that supplies liquids to portfolio

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

• WV East

Marcellus Utica

Undeveloped Net Locations 105 434 EUR (Bcfe/1000’) 2.4 2.8 Total NRI 90% 88% Total PDPs

• Net Current Production (Bcfe/d)
• ▪

Utica delineation can unlock tremendous value based

• n acreage held

Asset Region 4: Ohio Overview

106

▪ Joint Venture with Hess

OH Wet Marcellus Utica

Undeveloped Net Locations

• 135

EUR (Bcfe/1000’)

• 2.1

Total NRI

• 42%

Total PDPs

• 59 (Hess)

31 (CNX) Net Current Production (Bcfe/d)

• 0.086

OH Dry Marcellus Utica

Undeveloped Net Locations 100 26 EUR (Bcf/1000’)

• 3.2

Total NRI 85% 85% Total PDPs 1 24 Net Current Production (Bcfe/d)

• 0.313

▪ Fueling current growth with four pads remaining ▪ Increased type curves and returns driven by wider spacing ▪ OH Dry Utica Locations decreased due to Jefferson County sale in Q1 2017, increased spacing assumptions, and increased activity in 2017

Peer Benchmarking: Ohio Region - Dry

107 Company EUR (Bcf/1000’) Well Capital Lateral Length Total EUR (BCF) Capital Efficiency (Mcfe/$)

CNX 3.2 $10,500,000 9,000 28.71 2.73 Peer 1 2.2 $9,056,250 9,000 19.80 2.19 Peer 2 2.6 $9,990,000 9,000 23.40 2.34 Peer 3 2.1 $10,832,000 9,000 18.90 1.75

• 0.500

Ohio Dry Utica Capital Efficiency

SWPA Central Modeling Inputs and Economics

108

Reserves Detail Interest / Net Locations

• CND Yield (Bbl/MMcf)
• Well Capital ($MM)

• CND OpEx ($/Bbl)
• Assumptions

Reserves Detail Interest / Net Locations

Assumptions Price 9,500' $2.00 45% $2.50 75% $3.00 113% BTAX IRR% Price 8,500' $2.00 37% $2.50 64% $3.00 95% BTAX IRR%

SWPA Central Marcellus Type Curve (2.8 Bcf/1000')

SWPA Central Utica Type Curve (3.2 Bcf/1000')

SWPA Central Marcellus Type Curve (2.8 Bcf/1000’) SWPA Central Utica Type Curve (3.2 Bcf/1000’)

SWPA Greater Modeling Inputs and Economics

109

Reserves Detail Interest / Net Locations

• Well Capital ($MM)

• Assumptions

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions Price 9,500' $2.00 26% $2.50 47% $3.00 72% BTAX IRR% Price 8,500' $2.00 33% $2.50 59% $3.00 91% BTAX IRR%

SWPA Greater Marcellus Type Curve (2.7 Bcfe/1000')

SWPA Greater Utica Type Curve (3.0 Bcf/1000')

SWPA Greater Marcellus Type Curve (2.7 Bcfe/1000’) SWPA Greater Utica Type Curve (3.0 Bcf/1000’)

WV SHR/PENS Modeling Inputs and Economics

110

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions Price 8,000' $2.00 29% $2.50 46% $3.00 65% BTAX IRR% Price 7,000' $2.00 14% $2.50 30% $3.00 50% BTAX IRR%

WV SHR/PENS Marcellus Type Curve (2.8 Bcfe/1000')

WV SHR/PENS Utica Type Curve (2.8 Bcf/1000')

WV SHR/PENS Marcellus Type Curve (2.8 Bcfe/1000’) WV SHR/PENS Utica Type Curve (2.8 Bcf/1000’)

WV East Modeling Inputs and Economics

111

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions Price 8,000' $2.00 18% $2.50 30% $3.00 46% BTAX IRR% Price 7,000' $2.00 15% $2.50 31% $3.00 52% BTAX IRR%

WV East Marcellus Type Curve (2.5 Bcfe/1000')

WV East Utica Type Curve (2.8 Bcf/1000')

WV East Marcellus Type Curve (2.5 Bcfe/1000’) WV East Utica Type Curve (2.8 Bcf/1000’)

CPA South Modeling Inputs and Economics

112

Reserves Detail Interest / Net Locations

• CND Yield (Bbl/MMcf)
• Well Capital ($MM)

• Fixed Cost ($/mo./well)

• CND OpEx ($/Bbl)
• Assumptions

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions Price 9,000' $2.00 18% $2.50 33% $3.00 50% BTAX IRR% Price 7,000' $2.00 58% $2.50 104% $3.00 157% BTAX IRR%

CPA South Marcellus Type Curve (1.8 Bcf/1000')

CPA South Utica Type Curve (3.5 Bcf/1000')

CPA South Marcellus Type Curve (1.8 Bcf/1000’) CPA South Utica Type Curve (3.5 Bcf/1000’)

CPA North Modeling Inputs and Economics

113

Reserves Detail Interest / Net Locations

• CND Yield (Bbl/MMcf)
• Well Capital ($MM)

• Fixed Cost ($/mo./well)

• CND OpEx ($/Bbl)
• Assumptions

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions Price 9,000' $2.00 10% $2.50 19% $3.00 31% BTAX IRR% Price 7,000' $2.00 56% $2.50 100% $3.00 151% BTAX IRR%

CPA North Marcellus Type Curve (1.5 Bcf/1000')

CPA North Utica Type Curve (3.5 Bcf/1000')

CPA North Utica Type Curve (3.5 Bcf/1000’) CPA North Marcellus Type Curve (1.5 Bcf/1000’)

Ohio Modeling Inputs and Economics

114

1098

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions

Reserves Detail Interest / Net Locations

• Fixed Cost ($/mo./well)

Assumptions Price 8,000' $2.00 19% $2.50 33% $3.00 50% BTAX IRR% Price 9,000' $2.00 74% $2.50 126% $3.00 189% BTAX IRR%

OH Wet Type Curve (2.1 Bcfe/1000')

OH Dry Utica Type Curve (3.2 Bcf/1000')

OH Wet Utica Type Curve (2.1 Bcfe/1000’) OH Dry Utica Type Curve (3.2 Bcf/1000’)

Half Cycle and Full Cycle Modeling Assumptions

115

CNX Midstream Partners Governance

116

Public

(Development Co. 1)

(Development Co. 2)

(Development Co. 3)

Post-Spin Company Names and Stock Trading Symbols

117

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

• f CoalCo from RemainCo.

▪ The gas business, CNX Resources Corporation (RemainCo, GasCo or CNX), continues to be listed on the NYSE, retaining the ticker symbol "CNX". Information regarding CNX and its natural gas business is available at www.cnx.com. ▪ Following the closing of CNX’s purchase of Noble Energy’s 50% interest in CNX Gathering LLC, which occurred on January 3, 2018, the master limited partnership that was named CONE Midstream Partners, LP has changed its name to CNX Midstream Partners LP and now trades under a new ticker symbol: “CNXM”. CNX indirectly owns 100% of the general partnership interests of CNX Midstream Partners LP as well as all of its incentive distribution rights. Information regarding CNX Midstream Partners LP is available at www.cnxmidstream.com. ▪ The coal business, CONSOL Energy Inc. (SpinCo, CoalCo or CONSOL), is listed on the NYSE under the ticker symbol: "CEIX". CoalCo owns, operates and develops coal assets, including the Pennsylvania Mining Complex, the Baltimore Marine Terminal, and approximately one billion tons of greenfield coal reserves. Information regarding the new CONSOL Energy and its coal business is available at www.consolenergy.com. ▪ The master limited partnership that was named CNX Coal Resources LP (NYSE: CNXC) has changed its name to CONSOL Coal Resources LP and trades on the NYSE under a new ticker symbol: "CCR". CONSOL owns 100% of the general partner of CONSOL Coal Resources LP (representing a 1.7% general partner interest), as well as all of the incentive distribution rights and the common and subordinated interests in CNX Coal Resources LP that were owned by CNX prior to the spin-off. Information regarding CONSOL Coal Resources LP is available at www.ccrlp.com.