INVESTOR DAY December 13, 2016 Cautionary Language This - - PowerPoint PPT Presentation

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INVESTOR DAY December 13, 2016 Cautionary Language This - - PowerPoint PPT Presentation

ANALYST AND INVESTOR DAY December 13, 2016 Cautionary Language This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended).


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SLIDE 1

ANALYST AND INVESTOR DAY

December 13, 2016

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SLIDE 2

Cautionary Language

This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we expect to receive for our natural gas, natural gas liquids, and coal, including due to

  • versupply relative to the demand available for our products; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate the volume
  • f hydrocarbons that are recoverable from our oil and natural gas assets; we may encounter unexpected operational issues or disruptions when we drill and mine, including equipment

failures, geological conditions, and higher than expected costs for equipment, supplies, services and labor, including with respect to third-party contractors; we may not achieve the efficiencies we expect to realize in our drilling and completion operations, and as a result, our projected cost savings may not be fully realized; our joint venture partner, who operate assets in which we have a significant interest, may not perform as we expect and these and other circumstances could cause us not to realize the benefits we anticipate from our joint venture; we may not be able to sell non-core assets on acceptable terms; divestitures that we anticipate making or have made may not occur or produce anticipated benefits, or may cause disruptions to our business operations; we may be subject to environmental and other government regulations that adversely impact our operating costs and the market for our natural gas and coal; failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect

  • ur results of operations, financial position, and cash flows; we may be unable to incur indebtedness on reasonable terms; provisions in our multi-year sales contracts may provide limited

protection and may result in economic penalties to us or permit the customer to terminate the contract; our common units in CNX Coal Resources LP are subordinated, and we may not receive related distributions; and other factors, many of which are beyond our control. Additional factors are described in detail under the captions "Forward Looking Statements" and "Risk Factors" in CONSOL Energy Inc.’s annual report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly. Currently, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to the commencement of natural gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the gas rights we control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP.

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SLIDE 3

3

Agenda

Company Overview

Nick DeIuliis, President and CEO

Exploration & Production

Tim Dugan, COO Andrea Passman, VP-E&P Development Don Rush, VP-E&P Marketing

Diversified Business Units

Steve Johnson, EVP-DBU Rodney Wilson, Director-Business Development Marshall Roberts, Director-CONVEY Water Systems Katharine Fredriksen, SVP-DBU & Environmental Affairs

Financial Overview

Dave Khani, CFO Chuck Hardoby, VP-Finance

Regulatory Update

Tommy Johnson, VP-Government & Public Relations

Closing Remarks

Nick DeIuliis

Q&A Lunch / CNX Coal Resources LP Breakout Session CONE Midstream Partners LP Breakout Session

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SLIDE 4

Acquisition of Dominion Resources E&P assets tripling Marcellus Shale acreage position 4

CONSOL Energy’s Evolution

2014-2015

CONE Midstream Partners LP (NYSE: CNNX) formed with Noble Energy to provide gathering services in the Marcellus Shale and CNX Coal Resources LP (NYSE: CNXC) formed to house and manage CONSOL’s PA coal assets

2010 2013 2016 2016

Announces sale of five thermal coal mines in West Virginia to Murray Energy With the sale of the Buchanan mine and

  • ther remaining legacy

coal assets, CONSOL’s transformation into a premier natural gas Company is completed

2017+

CONSOL and Noble Energy announce separation of Marcellus JV, providing CONSOL with additional

  • perational flexibility

and the ability to reach leverage targets more rapidly Looking to the future – working towards complete separation from coal; monetizing assets where possible; continuous operational improvement

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SLIDE 5

+179% YTD

CONSOL Energy Has Continued to Transform Itself in 2016

RBL Reaffirmation Restarted Drilling (Accelerated Schedule) NBL JV Resolution Buchanan Sale

Jan 2016 Today

P2AA Asset Optimization (Phase 2) Zero-Based Budgeting P2AA Asset Optimization (Phase 1) Integrated Model Miller Creek & Fola Sale Re-org (Streamlined Operations & Planning) Turned DUC Inventory Online Restructured Agreement with Penguins

CNX Share Price YTD 2016(1)

Capital Allocation Driven

Cash Stabilization CNXC/ CNNX Drops

5

(1) As of 12/7/2016

$0 $5 $10 $15 $20 $25 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16

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SLIDE 6

Who We Are: Differentiating Ourselves Through Three Pillars

Values:

  • Never compromised regardless of circumstance
  • Operate daily free of injuries and environmental incidents
  • Pursuit of perfection driving towards best-in-class performance
  • Mitigates business risk profile and supports license to operate in an industry

that is subject to intense public scrutiny

Business philosophy:

  • NAV/share focused
  • Production growth is a byproduct
  • Capital allocation process drives decision-making
  • Delivering responsible, long-term value

Asset base:

  • Substantial drilling inventory equates to scalable advantages
  • Considerable percentage of held by production (HBP) acreage provides

unique flexibility in development plans

  • Largest stacked pay opportunity set in the lowest cost basin in the U.S.
  • Marcellus JV separation unlocks significant stacked pay opportunities

6

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SLIDE 7

Business Philosophy: Zero-Based Budgeting in Action

Transformed balance sheet:

  • Reduced legacy liabilities by $3 billion

Reduced expenses:

  • Cash servicing costs reduced by more than

$250 million since 2012

Transformed culture:

  • Executive compensation less than half

2012 levels

  • Compensation widely aligned with

shareholders’ interests

  • Executive perks and benefits eliminated;

exited arena naming rights agreement, providing significant cost savings

  • 61%

(1) Includes corporate jets/hangar, membership fees, and arena naming fees (2) Annual legacy liability cash servicing costs

Overhead(1) Executive Pay Legacy Liabilities(2) Selling G&A 2012 2016E

7

Reductions in Expenses 2012-2016E

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SLIDE 8

The Path Forward: Realization of Value

How we plan to close the value gap: Realization

  • f Value...

Today $22.05

Closing price 12/7/2016 1

GROW EBITDA – PRUDENT GROWTH OF E&P PRODUCTION EFFICIENT CAPITAL ALLOCATION TO HIGH IRR, NAV ACCRETIVE AOIs PAY DOWN DEBT – ORGANIC FREE CASH FLOW AND ASSET MONETIZATIONS DRIVE LEVERAGE RATIO IMPROVEMENT BELOW TARGET OF 2.5x REDUCE SHARE COUNT – OPPORTUNISTICALLY BUY BACK SHARES AS MARKET ALLOWS

2 3

8

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SLIDE 9

$- $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 2015 YTD 2016 $ in millions

Weathered Downturn Without Issuing Equity

9

Since the beginning of 2014, total follow-on equity issued by Appalachian peers totaled $10.6 billion:

  • All seven Appalachian peers have issued follow-
  • n equity since the beginning of 2014
  • CONSOL was able to de-lever the balance sheet

and improve liquidity through organically growing free cash flow (FCF) and monetizing assets

  • Avoiding issuing equity has resulted in not

diluting shareholders and providing further upside potential

Source: Scotia Howard Weil Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN

Follow-On Equity Issued Across Energy Industry FY2015-YTD 2016

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SLIDE 10

CONSOL Energy Represents a Unique Value Story

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Focus on NAV/Share Growth Driving NAV/share growth:

  • Significant increases to estimated ultimate recoveries (EURs)
  • Reducing drilling and completion (D&C) costs and capital intensity
  • Proving up and de-risking reserves
  • Accelerating activity
  • Continued focus on de-levering the balance sheet

E&P Assets Asset base is unique:

  • Prolific stacked pay positions create significant competitive advantage
  • Early efforts to delineate the Utica Shale are driving up net present value

(NPV) estimates

  • Large inventory of acreage for potential monetization opportunities

Supplementary Value Drivers Supplemental value drivers growing over time:

  • Diversified Business Units (DBU), which includes:
  • CONVEY Water Systems and the Baltimore Marine Terminal
  • CNX Coal Resources LP
  • CONE Midstream Partners LP
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SLIDE 11

EXPLORATION & PRODUCTION

11

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SLIDE 12

E&P Operations: NAV/Share Drivers

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CONVERTING NON-CORE ACREAGE TO CORE MAJOR OPERATIONAL IMPROVEMENTS SINCE 2014 STACKED PAY OPPORTUNITIES

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SLIDE 13

Continuous Improvement

0% 20% 40% 60% 80% 100% 120% 140% 160% 0.46 0.60 0.78 0.83 0.97 1.04 1.27 1.43 1.64 1.95 2.04 2.20 1.03 1.09 1.24 1.47 1.63 1.85 1.98 1.99 2.03 2.16 2.19 2.41 2.49 2.55 1.27 1.52 1.88 2.22 2.43 2.45 2.56 2.64 2.71 2.96 3.01 3.11 3.60 3.74 3.88 4.34 2014 2015 2016 BTAX IRR (%) EUR/Capex (Mcfe/$)

Capital Efficiency

1.24 Mcfe/$ 1.83 Mcfe/$ 2.78 Mcfe/$

13

Note: Bars represent well-level economics, which includes total capital employed

NAV growth being driven by improved capital efficiency

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SLIDE 14

E&P Industry: F&D Costs

Source: Scotia Howard Weil: 2015 F&D Cost Study Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN (1) (Land Acquisition Costs + Exploration + Development)/Drilling Reserve Additions

CONSOL has had some of the lowest F&D costs in the industry over the last five years Drilling Finding and Development Cost 5-yr. Average 2011-2015(1)

14 $0.80 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1 2 CNX 3 4 5 6 7 $/Mcfe

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SLIDE 15

Technological Evolution Driving Growth

15

Tools and Procedures 2014 2016E Earth model

Fracture simulation

Reservoir simulation

Rate transient analysis (RTA)

Risk analysis

Portfolio NAV optimization

NAV/Share Growth Drivers Since 2014:

  • 100% increase in EUR/1,000'
  • 38% improvement in capital deployment
  • 54% reduction in lease operating expense (LOE) ($/Mcfe)
  • 40% of dry Utica acreage converted from non-core to core
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SLIDE 16

Operational Evolution

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Key Performance Metrics(1) 2014 2016E Average EUR (Bcfe/1,000’) 1.4 2.8 Total Marcellus capital ($/ft) 1,345 835 Lease operating expense (LOE) ($/Mcfe) 0.41 0.19 Average drilling days on well 27 18 Average completion days on well 32 15 Completion stage spacing (ft) 300 150-225 Completion proppant volume (lbs/ft) 1,300 2,500-3,000

Improved operational performance:

  • Lean manufacturing
  • Supply chain management
  • Zero-based budgeting

Sustained growth at lower $/EUR

(1) Combined Marcellus and Utica key performance indicators (KPIs)

Cumulative Production vs. Incremental Wells TIL by Year

10 20 30 40 50 60 70 80 100 200 300 400 500 2014 2015 2016 Incremental Wells Online Cumulative Gas Production, BCF Marcellus-Utica Cumulative Production New Wells Online

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SLIDE 17

100 200 300 400 500 600 700 10 20 30 40 50 Cum prod (MMcfe/1,000') Normalized months CNX 1/2014 - 5/2015 CNX 6/2015+ 500 1,000 1,500 2,000 CNX 1 2 3 4 5 CNX 2014 - 5/2015 Mcfe/d 3 Mo (20:1) 6 Mo (20:1) Avg 3 Mo (20:1) Avg 6 Mo (20:1)

Well Performance Over Time

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Horizontal well production per 1,000’ since June 2015 – CNX vs. Peers

142% Increase Source: IHS Enerdeq via Credit Suisse Note: Peers include CVX, EQT, RICE, RRC, Vantage

CNX Well Performance Improved well performance:

  • Enhanced completions design
  • Optimized landing points
  • Managed pressure drawdown
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SLIDE 18

Large Acreage Position

CNX vs. Appalachian Peers – Acreage Position and Production

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Only 4% of total Marcellus and Utica Shale inventory developed to date:

  • 8% of the Marcellus acreage

developed

  • Marcellus 90% HBP
  • 1% of the Utica acreage

developed

  • Utica 91% HBP
  • 60+ years(1) of production

runway in inventory

  • 89% net revenue interest (NRI)
  • 22 years of inventory in

stacked pay in core areas(2)

(1) Inventory calculated assuming 100 wells drilled per year (2) Stacked pay core areas include Marcellus and Utica

720,000 615,000 406,000 640,000 480,000 175,000 200,000 490,000 400,000 608,000 370,000 375,000 160,000 210,000 500 1,000 1,500 2,000 2,500 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1 2 CNX 3 4 5 6 7 Daily Production (MMcfe/d) Net Acres Marcellus Utica Q3 Daily Production

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SLIDE 19

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New World View: Assets Before and After JV Separation

SWPA WV CPA OH Total Total Change Upper Devonian Net Acres 102,000 112,000 21,000

  • 235,000

280,000 (45,000) Net Acres 98,000 61,000 232,000 15,000 406,000 436,000 (30,000) Fee Acres 32,000 1,000 20,000 3,000 56,000 41,000 15,000

  • Approx. Net Locations (1)

533 370 1,465 116 2,484 Net Producing Wells (PDPs) 188 34 60 1 283 258 25 Net Acres 119,000 162,000 208,000 119,000 608,000 623,000 (15,000) Fee Acres 42,000 8,000 12,500 36,000 98,500 100,000 (1,500)

  • Approx. Net Locations(1)

673 987 1,177 517 3,354 Gross Producing Wells (PDPs) 1

  • 1

94 96 97 (1) Marcellus Utica

Post-JV Dissolution Pre-JV Dissolution

(1) Total net locations calculated from modeling inputs expected lateral lengths and spacing for each respective asset region and formation

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SLIDE 20

64% increase in Marcellus core acreage:

  • Full control of stacked pay opportunity set
  • Incremental 85 MMcfe/d of production
  • Further strengthens balance sheet
  • Higher weighted average EUR, compared

to pre-dissolution

Post-Exchange Marcellus Acreage Map

20

Dissolution of the Marcellus Shale Joint Venture

Marcellus Impact Pre- JV Dissolution Post- JV Dissolution Change Flowing PDP (MMcfe/d) 535 620 +16% DUCs 37.5 53 +41% Net acres (1) 336,000 306,000 (30,000) Core(2) 99,000 162,000 +64% Non-core(3) 237,000 144,000 (39%)

(1) Net acres include undeveloped only (2) Core: Prospective reservoir at current gas price forecast, de-risked by drilling, midstream, and market availability, with capacity for development and non-op potential (3) Non-Core: Non-prospective reservoir at current gas price forecast, acreage not a main driver, minor to no delineation, and minor to no non-op potential

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SLIDE 21

Development Optimization Production Modeling

Engineering Workflow Drives Decisions

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Earth Modeling

NPV/Well

Portfolio Risk Analysis Rate Transient Analysis Forecasting

ITERATIVE CYCLE

3D Frac Modeling

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SLIDE 22

Asset Region 1: Southwest Pennsylvania Overview

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Marcellus Shale average EUR/1,000’ of lateral increased 29% to 2.7 Bcfe(1)

  • Total net acres: 98,000
  • Total NRI: 89%
  • Sizable capital expenditure in the

next 2 years

  • 2 rigs in 2017 and 3 rigs in 2018

Utica Shale

  • Average EUR/1,000’ of 3.1 Bcf(1)
  • Total net acres: 119,000
  • Total NRI: 89%
  • Continue to delineate through

participation and drilling

Upper Devonian Shale

  • Total net acres: 102,000
  • 3 wells expected to be turned in

line (TIL) in 2017

(1) Average EUR represents the type curve guidance area depicted on the map Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

64% Utica/Marcellus core over core acreage overlap

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SLIDE 23

100,000 200,000 300,000 400,000 500,000 600,000 700,000 12 24 36 48

Gas Production (Mcf/month) Months After TIL

7000' LL

100,000 200,000 300,000 400,000 500,000 600,000 12 24 36 48

Gas Production (Mcf/month) Months After TIL

8500' LL

Southwest Pennsylvania Modeling Inputs and Economics

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SWPA Marcellus Type Curve (2.7 Bcfe/1000') SWPA Utica Type Curve (3.1 Bcf/1000')

BTAX ROR % (3)

Realized Price 8,500' $2.00 39% $2.50 71% $3.00 109%

BTAX ROR % (3)

Realized Price 7,000' $2.00 19% $2.50 34% $3.00 52%

(1) Assuming 8,500 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

Assumptions IP (MMcfe/d) 19.0 Decline 69% B-factor 1.65 EUR/1000’ (Bcfe) 2.7 Lateral Length 8,500’ Wells Per Pad 6 Capital ($ millions) $7.1 Fixed Cost ($/mo./well) $730 LOE ($/Mcfe) $0.12 Gathering ($/Mcfe) $0.48 Reserves Detail Gross EUR (Bcfe) 22.6 BTU 1,130 Assumptions IP (MMcf/d) 23.1 Decline 67% B-factor 1.20 EUR/1000’ (Bcf) 3.1 Lateral Length 7,000’ Wells Per Pad 5 Capital ($ millions) $13.2 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Gathering ($/Mcf) $0.23 Interest / Net Locations WI / NRI (%) 100% / 89% Net Locations(1) ~533 Wells Online (9/30/16) 188 Reserves Detail Gross EUR (Bcf) 21.4 BTU 1,010 Interest / Net Locations WI / NRI (%) 100% / 89% Net Locations(2) ~673 Wells Online (9/30/16) 1

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SLIDE 24

Asset Region 2: West Virginia Overview

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Marcellus Shale average EUR/1,000’ of lateral increased 61% to 2.9 Bcfe(1)

  • Total net acres: 61,000
  • Total NRI: 86%
  • Focus on completing DUC

inventory: sunk capital results in improved IRR

Utica Shale

  • Average EUR/1,000’ of 2.8 Bcf
  • Total net acres: 162,000
  • Total NRI: 88%
  • Delineation through

participation

(1) Average EUR represents the type curve guidance area depicted on the map Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 220,000 acres of Utica resource potential in WV not included in company totals Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

14% Utica/Marcellus acreage overlap

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SLIDE 25

10,000 20,000 30,000 40,000 50,000 100,000 200,000 300,000 400,000 12 24 36 48

NGL/CND Production (BBL/month) Gross Gas Production (Mcf/month) Months After TIL

Gas NGL CND 100,000 200,000 300,000 400,000 500,000 600,000 12 24 36 48

Gas Production (Mcf/month) Months After TIL

6500' LL

BTAX ROR % (4)

Realized Price 6,500' $2.00 10% $2.50 20% $3.00 31% 25

West Virginia Modeling Inputs and Economics

WV Marcellus Type Curve (2.9 Bcfe/1000')

BTAX ROR % (4)

Realized Price 8,000' $2.00 37% $2.50 56% $3.00 76%

(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 6,500 ft lateral @ 1,100 ft inter-lateral spacing (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

WV Utica Type Curve (2.8 Bcf/1000')

Assumptions IP (MMcf/d) 14.0 Decline 69% B-factor 1.65 EUR/1000’ (Bcfe) 2.9 Lateral Length 8,000' Wells Per Pad 6 NGL Yield (Bbl/MMcf)(3) 74.1 CND Yield (Bbl/MMcf)(3) 12.8 Capital ($ millions) $6.6 Fixed Cost ($/mo./well) $730 LOE ($/Mcf) $0.12 Gathering/Processing ($/Mcf) $0.93 NGL OpEx ($/Bbl) $5.00 CND OpEx ($/Bbl) $5.00 Reserves Detail Gross EUR (Bcfe) 22.8 BTU 1,260 Interest / Net Locations WI / NRI (%) 100% / 86% Net Locations(1) ~123 Wells Online (9/30/16) 34 Assumptions IP (MMcf/d) 15.3 Decline 58% B-factor 1.10 EUR/1000’ (Bcf) 2.8 Lateral Length 6,500' Wells Per Pad 3 Capital ($ millions) $12.7 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Gathering ($/Mcf) $0.23 Reserves Detail Gross EUR (Bcf) 17.9 BTU 1,015 Interest / Net Locations WI / NRI (%) 100% / 88% Net Locations(2) ~987 Wells Online (9/30/16)

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SLIDE 26

Asset Region 3: Central Pennsylvania Overview

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Marcellus Shale

  • Average EUR/1,000’ of 1.8 Bcf(1)
  • Total net acres: 232,000
  • Total NRI: 88%
  • Weighted average EUR/1000’ for

the entire region is 1.5 Bcf

  • Evaluate Marcellus development

in conjunction with Utica

Utica Shale average EUR/1,000’

  • f lateral up 17% to 3.5 Bcf
  • Total net acres: 208,000
  • Total NRI: 89%
  • Continued drilling expected in

2017 and 2018

  • 2 wells planned in 2017 and 1

well in 2018

  • Non-operated participation
  • pportunities

(1) Average EUR represents the type curve guidance area depicted on the map, which is approximately 111,000 acres in CPA Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 22,000 Utica resource potential in CPA not included in company totals Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

96% Utica/Marcellus acreage overlap

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SLIDE 27

100,000 200,000 300,000 400,000 12 24 36 48

Gas Production (Mcf/month) Months After TIL

9000' LL

100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 12 24 36 48

Gas Production (Mcf/month) Months After TIL

7000' LL

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Central Pennsylvania Modeling Inputs and Economics

CPA Marcellus Type Curve (1.8 Bcf/1000')

BTAX ROR % (3)

Realized Price 9,000' $2.00 23% $2.50 39% $3.00 62%

CPA Utica Type Curve (3.5 Bcf/1000')

(1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and opex (4) IP held flat for 14 months at 21.6 MMcf/d Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

BTAX ROR % (3)

Realized Price 7,000' $2.00 63% $2.50 107% $3.00 152% Assumptions IP (MMcf/d) 13.3 Decline 69% B-factor 1.65 EUR/1000’ (Bcf) 1.8 Lateral Length 9,000' Wells Per Pad 6 Capital ($ millions) $6.2 Fixed Cost ($/mo./well) $730 LOE ($/Mcf) $0.12 Gathering ($/Mcf) $0.32 Reserves Detail Gross EUR (Bcf) 15.8 BTU 1,000 Interest / Net Locations WI / NRI (%) 100% / 88% Net Locations(1) ~1,465 Wells Online (9/30/16) 60 Assumptions IP (MMcf/d)(4) 21.6 Decline 74% B-factor 1.20 EUR/1000’ (Bcf) 3.5 Lateral Length 7,000' Wells Per Pad 6 Capital ($ millions) $12.6 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Gathering ($/Mcf) $0.23 Reserves Detail Gross EUR (Bcf) 24.8 BTU 1,010 Interest / Net Locations WI / NRI (%) 100% / 89% Net Locations(2) ~1,177 Wells Online (9/30/16) 1

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SLIDE 28

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Asset Region 4: Ohio Overview

Total Ohio Utica:

  • Total net acres: 119,000
  • Total NRI: 89%

Utica Dry:

  • Average EUR/1,000’ of 2.8 Bcfe(1)
  • 23,000 net undeveloped acres
  • Continued development of

Monroe County

  • 101 net locations

Utica Wet:

  • Average EUR/1,000’ of 2.1 Bcfe(2)
  • 42,000 net undeveloped acres
  • Continue to monitor pricing for

continued development

  • 305 net locations

(1) Average EUR represents the type curve guidance area depicted on the map by a solid blue line (Utica Dry) (2) Average EUR represents the type curve guidance area depicted on the map by a dotted blue line (Utica Wet) Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

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SLIDE 29

5,000 10,000 15,000 20,000 25,000 30,000 100,000 200,000 300,000 400,000 500,000 12 24 36 48

NGL/CND Production (BBL/month) Gross Gas Production (Mcf/month) Months After TIL

Gas NGL CND 100,000 200,000 300,000 400,000 500,000 600,000 12 24 36 48

Gas Production (Mcf/month) Months After TIL

9000' LL

29

Ohio Modeling Inputs and Economics

OH Wet Utica Type Curve (2.1 Bcfe/1000') OH Dry Utica Type Curve (2.8 Bcf/1000')

BTAX ROR % (4)

Realized Price 8,000' $2.00 13% $2.50 27% $3.00 47%

BTAX ROR % (4)

Realized Price 9,000' $2.00 55% $2.50 90% $3.00 127% Assumptions IP (MMcf/d) 16.3 Decline 71% B-factor 1.40 EUR/1000’ (Bcfe) 2.1 Lateral Length 8,000’ Wells Per Pad 5 NGL Yield (Bbl/MMcf)(3) 32.6 CND Yield (Bbl/MMcf)(3) 4.0 Capital ($ millions) $7.6 Fixed Cost ($/mo./well) $1,371 LOE ($/Mcf) $0.29 Gathering/Processing ($/Mcf) $0.78 NGL OpEx ($/Bbl) $6.78 CND OpEx ($/Bbl) $6.25 Assumptions IP (MMcf/d) 20.4 Decline 56% B-factor 1.10 EUR/1000’ (Bcf) 2.8 Lateral Length 9,000’ Wells Per Pad 4 Capital ($ millions) $9.4 Fixed Cost ($/mo./well) $500 LOE ($/Mcf) $0.05 Gathering ($/Mcf) $0.21 Ohio Wet - Reserves Detail Gross EUR (Bcfe) 16.9 BTU 1,150 Ohio Wet - Interest / Net Locations WI / NRI (%) 50% / 45% Net Locations(2) ~305 Ohio Dry - Reserves Detail Gross EUR (Bcf) 25.0 BTU 1,060 Ohio Dry - Interest / Net Locations WI / NRI (%) 100% / 89% Net Locations(2) ~101 OH Utica Total Net Locations(1) ~517 Wells Online (9/30/16) 94

(1) Assuming average 8,500 ft lateral @1,100’ spacing (2) Assuming 8,000 ft and 9,000 ft lateral @ 1,100’ spacing for Ohio Wet and Ohio Dry, respectively (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

slide-30
SLIDE 30

Virginia Coalbed Methane

Virginia coalbed methane (CBM):

  • 267,000 net acres
  • 88,000+ undeveloped acres
  • WI / NRI: 100% / 87.5%
  • 4,000+ wells online
  • 3,690 future locations
  • 0.5 Bcf/well average EUR
  • 2,000+ refrac opportunities
  • Net production: 182 MMcf/d
  • Annual decline rate of approximately 5-7%
  • Access to multiple markets: TCO, ETNG Mainline,

Transco Zone 5

30

Capex(1) Opex(2) D&C Cycle Time(3) 2015 $300,000 $1.63 93 2016E $223,000 $1.42 29 2017E $215,000 $1.20 19

(1) Average combined capital per well (2) Cash costs ($/Mcf) (3) Days spud to TIL Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx 0% 10% 20% 30% 40% 50% 60% $2.50 $2.75 $3.00 $3.25 $3.50 Future Locations Refracs

38% 28%

CBM IRR

slide-31
SLIDE 31

Development Methodology

31

CONSOL utilizes a portfolio

  • ptimization development

methodology to:

  • Assess the value of the assets

within the portfolio to drive decision making targeted towards maximizing NAV/share

  • Assess the risk associated with

developing the assets within the portfolio

  • Determine investment, acquisition

and divesture opportunities to

  • ptimize E&P portfolio

Asset Assessment

GIS Mapping Geology/ Reservoir Engineering Land, Title, JAD Marketing Water Midstream Drilling, Completion, Production Purchase Additional FT Land Swap Potential Build Pipeline/ infrastructure Water Optimization Opportunities Pick up/ Lay Down Rigs Complete DUCs

17 22

  • 50

100 150 200 250 300 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 Net Mmcf/d Cumulative PV (Secondary)

Performance Studies Portfolio Classification Asset Development and Optimization Monte Carlo Risk Analysis

slide-32
SLIDE 32

New World View: Stacked Pay

Rhinestreet Middlesex Burkett West River

Formation Name

P a y

Cashaqua Tully Hamilton Marcellus Onondaga Utica Point Pleasant Trenton

0 GR 400 LITHOLOGY

32

  • 40+ years of stacked pay inventory(1)
  • The JV separation gives CONSOL complete
  • perational control in stacked pay
  • pportunities
  • The Upper Devonian provides triple stacked

pay potential, on top of Marcellus and Utica

  • Stacked pays allow CONSOL to take

advantage of a dry gathering system

  • $0.10-$0.25/Mcfe Utica gathering
  • Stacked pays take advantage of infrastructure

sunk capital

(1) Stacked pay inventory includes core and non-core undeveloped acreage

slide-33
SLIDE 33

Stacked Pay Value for SWPA: Pad Level Example

33

Stacked Pay Efficiencies Unstacked Stacked Unstacked Stacked LOE ($/Mcf) $0.12 $0.05 $0.15 $0.05 Gathering Rate ($/Mcf) $0.45 $0.39 $0.24 $0.18 Capital ($ in thousands) $5,900 $5,450 $13,200 $12,300 Dry Marcellus Dry Utica

Stacked pay development improves IRR by 10-20 percentage points

  • Marginal horizons may be pulled into the

development plan due to stacked pay economic improvement

  • Stacked pay development concentrates large-scale
  • perations in a small footprint
  • Concurrently developing two horizons enables cost

effective infrastructure build-out for both plays

  • Significant reduction in both lifting and gathering
  • perating costs due to higher volumes

(1) Assumes six Marcellus wells and four Utica wells per pad; 7,000’ laterals

Stacked Pay Pad Economics Example(1)

0% 20% 40% 60% 80% 100% 120% $0 $20,000 $40,000 $60,000 $80,000 $100,000 $120,000 $140,000 $160,000 $2.00 $2.50 $3.00 BTAX IRR (%) BTAX NPV ($ in millions) Gas Price Unstacked NPV Stacked NPV Unstacked IRR % Stacked IRR %

slide-34
SLIDE 34

Stacked Pay Value for SWPA Marcellus: Well Level

34 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 1.32 1.38 1.56 1.65 1.75 2.05 2.39 2.42 2.50 2.64 2.66 2.66 2.69 2.78 2.82 2.87 2.95 2.95 2.96 3.22 3.25 3.27 3.34 3.38 3.45 3.91 3.97 4.06 4.19 4.22 4.33 4.72 5.50 BTAX IRR (%) EUR/Capex (Mcfe/$)

Unstacked Stacked Pay

2016 Capital Efficiency Stacked Pay Potential

Capital Efficiency Mcfe/$ Unstacked (actual) 2.78 Stacked (potential) 3.02 Change +9% BTAX IRR +15 percentage points

slide-35
SLIDE 35

Stacked Pay Optimization: Richhill Field

  • 33% NPV uplift due to stacked pay development
  • 17,000 Marcellus acres with Utica rights
  • Marcellus damp gas on its own requires processing
  • Blending Marcellus with dry Utica gas allows the

avoidance of processing costs

  • Concurrent development of Marcellus and Utica

reduces capex and opex and increases combined NPV

  • 100% WI provides CONSOL ability to maximize

field NPV through stacked pay development flexibility

35

Richhill Optimization Richhill Case Study

Marcellus Utica Stacked % Difference Well Count 125 123 248 N/A BTU 1,130 1,015 1,070 N/A Opex ($/Mcfe) $1.16 $0.32 $0.41

  • 46%

Capex ($ in millions) $829 $2,007 $2,630

  • 7%

NPV ($ in millions) $317 $389 $939 +33%

slide-36
SLIDE 36

Upper Devonian: Rhinestreet and Burkett

Provides triple stacked pay potential,

  • n top of Marcellus and Utica
  • 235,000 net acres
  • 16 operated Upper Devonian wells
  • Combination with Marcellus and Utica

development driven by gas price trigger

0% 10% 20% 30% 40% 50% 60% 70% $2.00 $2.50 $3.00 $3.50 $4.00 BTAX IRR (%) $/MMBtu 36

SWPA 7000’ Burkett

slide-37
SLIDE 37

Delineation Schedule (Gross Wells) 2016 2017 2018 2019 2 3 4 4

37

Moving Utica Non-Core to Core

Delineating the Utica through operated and non-operated wells, data trades, and data purchases:

  • Provides geologic and reservoir data to

evaluate NAV impact and helps assess development risk

  • 170,000 dry Utica core acres
  • Potential to increase core position by

250,000+ acres by expanding the core

Delineation Opportunities

Non-Operated TIL Forecast (Gross Wells) 2016 2017 2018 Utica 13 17 15

X X X

GH-9 Greene Co. PA 3rd Party Harrison Co. OH 3rd Party Guernsey Co. OH 3rd Party Washington Co. PA

X

Aikens-5 Westmoreland Co. PA

X X

3rd Party Indiana Co. PA 3rd Party Monongalia Co. WV

X

MAJ-6 Marshall Co. WV

X

SWPA Prospect Allegheny Co. PA

X

CPA Prospect Westmoreland Co. PA

X

SWPA Prospect Greene Co. PA

X

SWPA Prospect Greene Co. PA

X

WV Prospect Monongalia Co. WV

X

Jan-16 Jan-17 Jan-18 Jan-19 Dec-19

slide-38
SLIDE 38

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 5,000 10,000 15,000 20,000 25,000 30,000

9/23/15 1/1/16 4/10/16 7/19/16 10/27/16 2/4/17 Casing Pressure (psi) Flow Rate (Mcf/d) Flow Rate MCf/Day Casing Pressure

  • Consistent reservoir and geologic conditions indicate additional wells in the Gaut area should have similar

performance Gaut 4IH 61.4 MMcf/d IP Initial SICP = 9,921 psig 5,808’ Lateral Length 7.8 Bcf by 01/2017

38

Why We Love the Utica: Gaut 4IH Westmoreland County, PA

Testing period Mcf/d

slide-39
SLIDE 39

Stacked Pay with the Utica: The Size of the Prize

39

360,000+

Net Acres

20 Tcfe

Recoverable Resource in Place

5,000+

Triple Stacked Core Locations

40+

Years of Drilling

  • 360,000 net acres of double stacked pay opportunity

in the core and non-core areas

  • 180,000 core acres with double stacked pay opportunity
  • Utica stacked pay delineation in the next 2 years drives

stacked pay development

  • 30 Utica non-operated participation wells
  • Concentrates the footprint of stacked pays: Upper Devonian

(Rhinestreet, Burkett), Marcellus and Utica

  • Accelerates locations into the near-term plan by uplifting

lower value formations

  • The Marcellus and Utica stacked pays supports a 4-rig

program for over 40 years

  • Drilled 14 dry Utica wells and participated in 18 other wells
slide-40
SLIDE 40

Two-Year Development Plan

  • Consistently complete DUCs

from December 2016 through 2018

  • Total of 33 DUCs to be

completed in two-year plan

  • High value areas in Monroe

County, OH and SWPA will be developed throughout 2017, 2018, and beyond

  • Delineation prospects will

continue to be drilled and evaluated

40

2017 2018

TD FRAC TIL Capex TD FRAC TIL Capex

Marcellus 12 13 13 $80 54 42 40 $260 Utica $0 3 3 3 $40 Upper Devonian

  • 2

3 $15 -

  • Marcellus
  • 20

18 $95 -

  • 2

$10 3rd Party Marcellus 2 11 11 $5 4 -

  • $5

CPA

Utica 2 2 2 $25 1 1 1 $15 Utica 17 22 22 $210 12 15 13 $140 3rd Party Utica 20 20 20 $15 16 16 16 $25

VA

CBM 61 51 51 $20 28 33 33 $5

TOTAL(1)

31 59 58 $465 70 61 58 $500

SWPA WV OH

($ in millions) (1) Total includes CONSOL-operated Marcellus, Utica, and Upper Devonian TD, Frac, and TIL for 2017E and 2018E

slide-41
SLIDE 41

E&P Capital Expenditure Guidance

($ in millions)

2016E 2017E 2018E Drilling and Completion $175 $465 Midstream $20 $40 Land, Permitting, and Other $10 $50 Total E&P and Midstream Capital $205 $555 $600 Total Production (Bcfe) 395 415 485 Expected Production Growth 20% 5% 17%

41

2017E E&P Capital Plans

  • Capital expenditure projections based
  • n current market conditions and

forecast

  • Flexibility exists to adjust

spending as necessitated by commodity fluctuations

  • Increase in Land, Permitting, and Other

capital driven by return to activity and blocking up acreage

  • Running three rigs by end of 2017
  • To hold 2016E production flat in 2017,

maintenance capital would be approximately $250-$300 million

Drilling & Completions 84% Midstream 6% Land, Permitting, and Other 10%

E&P Capital and Production Plans

slide-42
SLIDE 42

E&P MARKETING

42

slide-43
SLIDE 43

E&P Marketing: NAV/Share Drivers

43

MAXIMIZING CASH FLOW AT THE WELLHEAD FLEXIBLE FT STRATEGY TO MINIMIZE COSTS AND ENSURE PRODUCTION GROWTH SIGNIFICANT HEDGE BOOK PROTECTING DOWNSIDE, WHILE PRESERVING MEANINGFUL UPSIDE

slide-44
SLIDE 44

E&P Marketing

44

Ability to deal with the increasing uncertainty in a volatile marketplace:

  • A consistent, yet flexible strategy is necessary to help mitigate the uncertainty
  • Strategic and tactical expertise

Contributing to NAV/share through a "barbell" strategy:

  • Previously focused primarily on providing operational support
  • Focused now on providing strategic support that drives corporate decisions
  • Planning, revenue management, and hedging are now one fluid process
  • Ensuring near-term financial success while adding future value through additional hedging and new

approaches

Programmatic Hedging

  • Create incremental free

cash flow (FT cost & capacity optimization, ensure gas flow, diverse sales portfolio)

  • Asset management

agreements

  • Dry / Wet optionality
  • Arbitrage pipeline

flexibility, create 3rd party

  • pportunities
  • Utilize flexibility

CURRENT & NEAR TERM LONGER TERM

  • Enhanced risk

management

  • Capital allocation

protection

  • Develop arbitrage
  • pportunities and new

diversified netbacks

  • Maintain efficient

flexibility

  • Additional margin

& balance sheet protection

slide-45
SLIDE 45

Increased Volatility

45

U.S. LNG Export Forecast Current infrastructure and systems are not built to handle new gas market:

  • Storage capacity has remained the same, while

supply has increased significantly

  • 50 Bcf/d in 2005 vs. approximately 75 Bcf/d

in 2017

  • Existing supply quickly falls, over 20% per year,

if drilling slows

  • Demand sensitivity to price and weather is

increasing significantly

  • LNG and Mexican exports
  • Increased power and heating use
  • A supply and demand imbalance of only 2 Bcf/d
  • n average for a year, is the difference between

an alarmingly high inventory level coming out of winter and an alarmingly low inventory level coming out of winter

The system is bigger and more volatile on both the supply and demand sides with the same amount of storage, leading to increased volatility

$0 $1 $2 $3 $4 $5 $6 $7

Henry Hub and Dominion South Pricing

(Historical First of Month and Forward Strip)

Dominion South Henry Hub Source: Morningstar Source: Historical prices-SNL; Strips- Intercontinental Exchange and CME

slide-46
SLIDE 46

Volatility Can Be Good

46

Take-away capacity is coming to the region:

  • Over 18 Bcf/d of projects in process: question of

when, not if

  • Only need half to come online by 2018 to support

the expected production growth

  • It will all eventually come online to allow a visible

growth path for the next 5+ years

A normal or colder-than-normal winter will have a large effect:

  • Inventory levels are not excessively higher than they

have been in the past

  • The demand pull on the system is higher than it has

ever been (power, heating, Mexico, LNG)

Working Gas Inventory (Bcf):

  • Region proven it can handle approximately 7 Bcf/d of

extra supply

  • Supply relative to demand and storage can swing

positive as quickly as they have swung negative, and CONSOL is positioned to succeed under either situation

Projected Basin Takeaway Capacity

Year Year Prior Max Year Min.

  • Avg. NYMEX Price

2014 3,834 824 $4.42 2013 3,928 1,674 $3.65 2016E 4,009 2,468 $2.46 2017E 4,017 ? $3.25

Source: Historical Supply-Spring Rock; Demand + Takeaway and Supply Potential- various public sources, CONSOL interpretation Source: EIA

  • 5,000

10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Average MMcf/d Demand + Takeaway Capable Excess AVG Supply Supply Potential

slide-47
SLIDE 47

The Benefits of Flexible Firm Transportation

47

FT strategy:

  • Sufficient short- and long-term FT at a cost

lower than peers going to markets that maximize netbacks without over-committing

  • Use FT, IT, AMAs, customers’ capacity,

varying terms, releases, etc.

  • NYMEX differentials in-line with peer average,

with 1/8 of the average “take-or-pay” FT

  • bligation of peers
  • Keep basis differentials lower than the cost of

greenfield FT prices

  • Proactively ensure CONSOL can grow

production

Basis plan will utilize:

  • A unique sales focus for each market
  • Strategically selecting FT
  • Diversified sales portfolio
  • Programmatic basis hedges placed years in

advance

  • Opportunistic basis hedges when appropriate

(1) Company filings as of Q3 2016; gas price differentials based on first nine months of 2016 Note: Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC, SWN

$(2.00) $(1.50) $(1.00) $(0.50) $- $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $16.0 $18.0 $20.0 CNX 1 2 3 4 5 6 7 8

  • Diff. to NYMEX ($/MMBtu)

Total Obligations ($ in billions)

Transportation, Gathering, & Processing Commitments and Differentials(1)

FT, Gathering, and Processing Obligations Gas Price Diff. to NYMEX Peer Average Gas Price Diff to NYMEX

slide-48
SLIDE 48

The Benefits of Flexible Firm Transportation (Cont’d)

48

Avoiding long-term, burdensome FT on new projects that go underwater:

  • Many greenfield project demand fees appear to exceed the forecasted price uplift at various basis locations
  • Short-term gains will be minimal compared to long-term deterioration
  • Avoiding significant, long-term exposure to out-of-the-money positions

$- $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80 $0.90 2018 2019 2020 2021 2022 2023 Estimated $/Dth

Future Spreads vs. Estimated Demand Fees(1)

Project A Spread Project B Spread Project A Calculated Fee Project B Calculated Fee

(1) Project costs were obtained from FERC filings; demand fees conservatively estimated using only expected project costs and an assumed 15% rate of return

slide-49
SLIDE 49

Firm Transportation Management

49

Diversified sales and FT portfolios:

  • Result in competitive basis differentials and

balanced basket of prices

  • Strategically aligned with the best AMA partners in
  • ur markets to optimize asset value and realize
  • ther tangible benefits
  • In-basin exposure mitigated through basis hedge

program and diversified sales mix

Positioned significantly ahead of peers as in-basin market stays volatile:

  • Peers’ expensive long-haul FT cost will fluctuate

with netbacks being in and out of the money

  • Will limit their flexibility and tend to worsen with

time as more costs hit their income statements and they face minimum volume commitments in more recent contracts

200 400 600 2016 2017 2018 Bcf

Sales Portfolio Market Mix

In Basin Open In Basin Hedged East Coast Total Far Midwest Total Gulf Total

In-Basin Prices and Basis 2017E-2022E

$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 2017 2018 2019 2020 2021 2022 Annual Price ($/MMBtu) TETCO M2 NYMEX

Source: Intercontinental Exchange and CME

slide-50
SLIDE 50

200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000

MMBtu/d Cumulative NYMEX Hedges Cumulative Basis Hedges

Hedging Strategy

50

Newly instituted programmatic hedge program:

  • Systematically layering in hedges to protect margins on

up to 90% of proved developed production

  • Protecting from in-basin blowout through regional basis

hedges

  • Lock in revenue: Match NYMEX and basis hedge volumes

We are hedging PDP volumes out to 2020:

  • Systematic approach protects from market downturns
  • Increased drilling activity and opportunistic hedge program

capture market upswings, de-risking capital decisions

Hedge Position

(Outer ring = NYMEX; Inner ring = Basis)

Hedge Volumes and Pricing FY 2017 FY 2018 FY 2019 FY 2020

NYMEX Only Hedges Volumes (Bcf) 233.8 187.3 124.3 62.1 Average Prices ($/Mcf) $ 3.08 $ 3.13 $ 3.07 $ 3.19 Index Hedges and Contracts Volumes (Bcf) 32.4

  • 6.8

3.4 Average Prices ($/Mcf) $ 3.19

  • $ 2.54 $ 2.35

NYMEX + Basis (fully-covered volumes) Volumes (Bcf) 263.8 177.3 103.5 53.7 Average Prices ($/Mcf) $ 2.52 $ 2.66 $ 2.61 $ 2.79 NYMEX Only Hedges Exposed to Basis Volumes (Bcf) 2.4 10.0 27.6 11.8 Average Prices ($/Mcf) $3.08 $ 3.13 $ 3.07 $ 3.19 Total Volumes Hedged (Bcf)(1) 266.2 187.3 131.1 65.5 (1) Hedge position as of 12/7/16. Includes financial and physical hedges.

Hedged Open Hedged Open

2017 2018 Hedges made across different years and different sales points for basis throughout the year

slide-51
SLIDE 51

NGL Strategy

51

Processing flexibility on a third of wet volumes:

  • Avoid processing fees when NGL pricing is low
  • Capture NGL uplift during peak pricing
  • Leverage dry Utica blend-stock

Plant optionality on nearly half of wet volumes:

  • Optimize on residue gas takeaway
  • Enhance NGL marketability
  • Drive down costs through competition

Direct ethane sales netbacks tracking Mt. Belvieu pricing:

  • Achieved without burdensome FT commitment
  • Equivalent of selling gas with a +$0.68/MMBtu

basis

40% of C3+ in 2017-2018 expected to be sold internationally:

  • Exposure to multiple price points
  • Over half of production will stay domestic to feed

increasingly attractive markets

2017 Direct Ethane Sales Netback Estimate(1)

Gas $ High Gas $ Low NGL $ Low NGL $ High Avoid Processing Optimize Send to Processing Optimize

22 Bcf Wet Gas Flexibility

$0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 2017 Ethane ($/gal)

  • Mt. Belvieu Ethane

CNX Netback Appalachian Gas Alternative

(1) As of 11/28/16 forward strip (2) Avoiding approximately $0.16/gal cost and long-term commitment to obtain Mt. Belvieu pricing

(2)

slide-52
SLIDE 52

Key Marketing Financial Parameters

52

(1) Based on 12/6/2016 strip prices

Expected Market Mix 2017E 2018E Columbia (TCO) 14% 16% TETCO (M2) 38% 41% TETCO (M3) 12% 7% Dominion (DTI) 15% 13% East Tennessee 9% 7% TETCO ELA & WLA 6% 5% Midwest (Michcon) 6% 11% 100% 100% Estimated utilized firm transportation demand expense ($ in millions) $77.2 $108.4 Estimated firm transportation demand expense per unit of production ($/Mcf) $0.21 $0.24 Expected average basis w/o regard to hedging (based on market mix) ($/Mcf) (1) ($0.63) ($0.50) Expected average basis, including hedges currently in place ($/Mcf) (1) ($0.58) ($0.47) Volumes with basis currently hedged (Bcf) 263.8 177.3 Average price of basis hedges currently in place ($/Mcf) ($0.62) ($0.47) % of production 70% 40%

slide-53
SLIDE 53

DIVERSIFIED BUSINESS UNITS

53

slide-54
SLIDE 54

Diversified Business Units: NAV/Share Drivers

54

$400-$600 MILLION IN 2017 ASSET SALES GROWING MISCELLANEOUS OTHER EBITDA SIGNIFICANTLY REDUCING LEGACY LIABILITIES

slide-55
SLIDE 55

CONSOL has a strong track record of successful divestitures:

  • 20 NAV-enhancing divestitures since 2012
  • Over $5 billion of combined value

Team is now focused on divesting E&P assets:

  • Recent Marcellus JV separation provides more control

and flexibility with asset base

  • Continually evaluating NAV-accretive opportunities

CONSOL has a significant asset base:

  • 60+ years of drilling inventory
  • Acres all throughout the Appalachian basin in all

horizons

Flexible approach:

  • Outright sales
  • Swaps and trades
  • AMI / participations
  • Acquisitions

2017 total asset sales target between $400-$600 million

55

Business Development: Strategy

slide-56
SLIDE 56

Other Miscellaneous: Income and Expense Sources

Miscellaneous Other Income 2016E 2017E 2018E Baltimore Terminal Royalty Income Right of Way Sales CONVEY Water Systems Rental Income & Other Miscellaneous Other Costs 2016E 2017E 2018E Baltimore Terminal Lease Rental Expense Coal Reserve Holding Cost CONVEY Water Systems Long-Term Liabilities Bank Fees and Other Net of Income and Cost ($MM)

  • $60 to -$65
  • $15 to -$20
  • $10 to -$15

56

Increasing value from a range of often overlooked sources:

slide-57
SLIDE 57

CONVEY Water Systems

57

Provides water related services for CNX and third party upstream E&P companies:

  • Fresh water delivery for well completion operations
  • Recycle and disposal of produced fluids
  • One of the largest water pipeline network in Appalachia
  • 2017E water life cycle management of approximately 2.8

million gal/day

  • Rapid expansion of 3rd party customer base
  • Leverage expansive pipeline system and surface acreage

position to achieve best in class operating cost

  • Volumetric service fee structure provides revenue and
  • perating cash flow

Organic value creation through spin-off or drop-down opportunity

  • Highly attractive midstream EBITDA valuation multiple

(9.0x – 12.0x)

Projected 2017 EBITDA of approximately $50 million

Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected

  • perating income, the most comparable financial measure calculated in accordance with GAAP,

due to the unknown effect, timing, and potential significance of certain income statement items. 2017 EBITDA projection is based on rates charged to CNX Gas, which are subject to change

CONVEY Water System Assets

Marcellus Utica Other Total Water Pipelines (Miles) 291 18 216 525 Storage Impoundments 8 1 9 Water Sourcing Dams 2 2 UIC Well 1 1 2017 CONVEY Capex ($MM) 15 10 25 2017 Water Pipelines (Miles) 10 15 25 2017 Storage Impoundments

  • Total 2017 Infrastructure

Water Pipelines (Miles) 301 33 216 550 Storage Impoundments 8 1

  • 9

Water Source 2 2 UIC well 1 1

slide-58
SLIDE 58

Baltimore Marine Terminal

58

Overview:

  • Coal export terminal
  • 15 million tons per year capacity throughput; 1.1

million tons coal storage yard capacity

  • Strategically located: able to access the attractive

seaborne markets supplying both Europe and Asia

  • The only coal export terminal on the East Coast

served by two railroads: Norfolk Southern and CSX Corporation

Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

2016 achievements:

  • Baltimore Terminal expected to generate approximately $15 million in EBITDA for a projected 8.5 million ton

throughput, despite challenging coal export market conditions in 2016

  • Opened the terminal up for throughput capacity from third party shippers: Signed 3 million tons in 2017

(with take or pay provisions) from third party shipping contracts in addition to legacy contracts of 12 million tons reserve (not take or pay)

  • Achieved significant service and operating cost efficiencies in 2016

2017 outlook:

  • Strong met and stronger thermal export market indications provide reasonable expectation of 9-10 million

ton throughput providing $19-$22 million of EBITDA

  • Cost savings of at least $1 million from scheduling and supply chain optimization
slide-59
SLIDE 59

Recent Transactions: Legacy Assets

59

Buchanan Mine transaction:

  • Includes potential royalty payment based on rising

met coal prices

  • 20% royalty on export sales of any excess of

the gross FOB mine sales price over certain minimums that increase each year and end after five years

  • Solid met coal pricing in recent quarters has

positioned CNX to receive a royalty in Q4 2016

  • 2017 forecasted EBITDA associated with the

Buchanan royalty is forecasted to be between $10-$20 million

Miller Creek / Fola transaction:

  • Eliminated small non-core coal operation
  • Removed $100 million of long-term liabilities

from CONSOL’s balance sheet

  • Sold approximately 230 million and 185 million

tons of reserves or resources, respectively, in the two complexes

Example Average Buchanan Mine Monthly Export Price(1) $ 150.00 Royalty Threshold Price (Year 2) $ 78.75 Average Export Sales Price Over Threshold $ 71.25 Royalty 20% Royalty Revenue Per Ton at 20% $ 14.25 Example Annual Export Tons(1) 2,500 Example Annual Royalty Revenue ($ millions)(2) $ 35.6

(1) Average monthly export price and export ton quantity for example purposes only (2) Due to uncertainty in metallurgical coal markets, CONSOL uses a risked view for planning purposes Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

Example 2017 Royalty Calculation

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SLIDE 60

Financial: Legacy Liabilities

Significant legacy liability reductions over past three years:

  • Miller Creek/Fola transaction drove

substantial reduction in legacy liabilities in 2016

  • Continue to actively manage the reduction
  • f legacy liabilities

60

Balance Sheet Liability Long-Term Liability Guidance 12/31/2016E FY 2017 FY 2018 LTD $17 WC 82 CWP 125 OPEB 655 Salary Retirement/Pension 89 Asset Retirement Obligations 227 Total Legacy Liabilities $1,194 Total Cash Servicing Cost $95 $74 - $79 $70 - $75 EBITDA Impact

($60 - $65)

($18 - $23) ($21 - $26)

Note: 12/31/16 liability balance includes approximately $33.5 million and $34.1 million in employee-related and environmental liabilities associated with Pennsylvania Mining Operation (PAMC), respectively. Future EBITDA loss and cash servicing costs related to these liabilities will run through the PAMC segment financial detail and therefore the cash servicing costs and EBITDA loss related to these liabilities are excluded from the 2017 & 2018 forecast presented above. For FY 2017, the cash servicing costs associated with PAMC LTL are forecasted to approximate $8.1 million, while the EBITDA loss associated thereto is forecasted to approximate $11.9 million. Excludes gas well closing.

$4,187 $1,703 $1,497 $1,362 $1,194 $365 $144 $139 $133 $95 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 2012 2013 2014 2015 2016E Annual Cash Servicing Costs ($ in millions) Legacy Liabilities ($ in millions) Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost

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SLIDE 61

FINANCE

61

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SLIDE 62

Finance: NAV/Share Drivers

62

REDUCING COST OF CAPITAL CAPITAL ALLOCATION IMPROVING FORECASTING CAPABILITY AND TRANSPARENCY

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SLIDE 63

Financial Accomplishments Since 2014

Reduced Debt By attacking all parts of our business, we have reduced the nominal and per unit spend by 45% and 55%, respectively. Paid down approximately $1 billion in debt Managed Legacy Liabilities Reduced legacy liabilities by approximately $300 million and annual cash service costs by approximately $50 million Launched Two MLP IPOs Created CNXC and CONE Midstream MLPs to provide clarity for investors and followed each IPO with an additional drop Drove Down Operating Costs Dramatically reduced operating costs to be competitive with top-tier Appalachian E&Ps Lowered SG&A Incorporated zero-based budgeting and substantially reduced SG&A with a range of initiatives

63

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SLIDE 64

Tools to Grow NAV/Share

64

Safety Compliance Operating Efficiencies Liability Management Capital Allocation Revenue Management

NAV/Share Growth

Prudent capital allocation is one of the most important tools to grow NAV/share; a clear and consistent methodology to assess capital allocation options and make decisions is essential.

Zero-Based Budgeting

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SLIDE 65

Capital Allocation Decision Making

Production

KEY PERFORMANCE METRICS

Proved Reserves Borrowing Base PV9 Discount Rate Free Cash Flow Liquidity

NAV/Share

Managing Risk Appropriately Throughout the Commodity Cycle

Leverage Ratio

CAPITAL SOURCES CAPITAL USES

  • Pulling back capital

spend/activity level

  • Selling assets/drop downs
  • Issuing debt
  • Issuing equity
  • Reducing

dividends/distributions

  • Developing high rate
  • f return Marcellus and

Utica opportunities

  • Paying down/buying

back debt

  • Buying back equity to reduce

share count

  • Paying dividends/distributions
  • Acquiring assets (M&A)

65

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SLIDE 66

2017E-2018E E&P Capital Allocation

66

Note: Based on D&C capital

Ranking projects and capital allocation priorities 2017E-2018E

Full Well IRR Sunk Cost IRR DUCs CPA Utica OH Dry Utica SWPA Marcellus VA CBM SWPA Utica 0% 10% 20% 30% 40% 50% 60% 70%

IRR

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SLIDE 67

Benchmarking: Capital Yield Has Been Improving

67

Note: Methodology and 2014-2016E peer estimates from KLR Group. CNX 2016E-2018E based on internal plan. Capital Yield = E&P Operating Cash Margin / (CapEx/Change in Production) * Initial Recovery Percentage. Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN.

  • Focused on improving capital yield through reducing capital intensity

and operating costs

  • Disciplined capital spending through the downturn positioned the

company to dramatically improve its 2016 and 2017 capital yield

  • Driving down operational expenses have improved cash margins in

a depressed pricing environment

  • As operational initiatives continue to take root, CONSOL is expected

to maintain capital efficiency levels well above historical averages

  • 20%

30% 80% 130% 180%

1 2 3 4 5 6 7 CNX

  • 20%

30% 80% 130% 180%

1 2 3 4 5 6 7 CNX

  • 20%

30% 80% 130% 180%

CNX 1 2 3 4 5 6 7

2014: Capital Yield 2015: Capital Yield 2016E: Capital Yield CONSOL Capital Yield 2014-2018E

  • 20%

30% 80% 130% 180% 2014 2015 2016E 2017E 2018E

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SLIDE 68
  • 50

100 150 200 250 300 2012 2013 2014 2015 2016E 2017E 2018E $ in millions Cash SG&A Expense Stock Compensation

SG&A Nominal and Unit Reductions

$0.55 $0.31 $0.20 $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 2014 2015 YTD 2016 SG&A Spend ($/Mcfe(2)) CNX E&P E&P Peers Average

Total Company SG&A(1) 2012-2018E

(1) Historical years recast to align with current reporting. Total includes stock compensation and short-term incentive compensation in all periods. (2) Cost per Mcfe excludes stock-based compensation. Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN.

  • Initial declines tied to asset divestitures
  • Implemented zero-based budgeting in 2015
  • Reduction of top five executive pay by combined approximately 50%
  • Termination of various corporate perks and arena naming rights
  • Reorganized to be able to fully separate E&P and coal in 2017

Since 2014, CONSOL Energy has reduced its SG&A $/Mcfe faster than its peers

68

SG&A $/Mcfe 2014-YTD 2016

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SLIDE 69

Improving Transparency: E&P Guidance

Note: Forecast based on strip pricing as of 11/3/2016 close (1) Excludes stock-based compensation (2) Includes Idle Rig Charges, Unutilized Firm Transportation Expense (Net Of 3rd Party Revenue), Land Rentals, Lease Expiration Costs, Misc. Gas, and Exploration Expense

69

E&P Segment Guidance 2016E 2017E 2018E Production Volumes: Natural Gas (Bcf) 348 375 445 NGLs (MBbls) 6,740 5,800 5,950 Oil (MBbls) 70 45 40 Condensate (MBbls) 860 740 730 Total Production (Bcfe) 395 415 485 % Liquids 12% 10% 8% Open Natural Gas Basis Differential to NYMEX ($/Mcf), as of 11/03/16 ($0.60) ($0.63) ($0.50) NGL Realized Price ($/Bbl) 14.00 16.00 16.50 Condensate Realized Price % of WTI 70% 70% 70% Oil Realized Price % of WTI 90% 90% 90% Capital Expenditures ($ in millions): Drilling and Completions $175 $465 Midstream $20 $40 Land, Permitting and Other $10 $50 Total E&P and Midstream CapEx $205 $555 $600 Average per unit operating expenses ($/Mcfe): Lease Operating Expense 0.26 0.23 Production, Ad Valorem, and Other Fees 0.08 0.07 Transportation, Gathering and Compression 0.93 0.77 Total Cash Production and Gathering Costs 1.27 1.06 1.05 Other Expenses ($ in millions): Selling, General, and Administrative Costs(1) $70 $70 $70 Other Corporate Expenses(2) $70 $80 $60

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SLIDE 70

PA Mining Operations Guidance

70

  • Due to mines being well capitalized, CNXC was able to reduce capital spending on discretionary projects to
  • ffset the challenging coal market conditions, heading into 2016
  • Capital expenditures expected to revert to the approximately $5 per ton starting in 2017 and beyond

PA Mining Operations 2016E 2017E 2018E Estimated Total Coal Sales Volumes (in millions of tons) 24.0 26.5 26.5 Total Committed Volumes (Contracted & Priced) 23.3 23.1 % Committed 97% 87% Capital Expenditures ($ in millions): Production $70 $120 Other (Land/Water/Safety) $20 $15 Total Coal Capital Expenditures ($ in millions) $90 $135 $140

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SLIDE 71

EBITDA Guidance

(1) Includes forecasted Earnings of Equity Affiliates of $36 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream. This income is reflected within Miscellaneous Other Income in the CNX Income Statement. (2) Base plan assumes NYMEX as of 11/3/2016 $2.99 + basis of ($0.70). Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

EBITDA Guidance by Segment – 2017E EBTIDA Sensitivity to E&P Price Fluctuations vs. Plan

71

($ in millions)

E&P(1) Coal Other Total EBITDA $465 $390 ($15) $840 Adjustments: Unrealized Gain Loss on Hedging ($5)

  • ($5)

Stock-Based Compensation $20 $10 $0 $30 Adjusted EBITDA $480 $400 ($15) $865 Less: Noncontrolling Interest

  • ($45)
  • ($45)
  • Adj. EBITDA Attributable to CNX

$480 $355 ($15) $820 2017E E&P Base Plan(2) (strip pricing as of 11/3/16) Open Price (NYMEX + Basis) $1.30 $1.80 $2.30 $2.80 $3.30 EBITDA ($ in millions 690 760 820 890 960 Leverage Ratio 3.0x 2.7x 2.4x 2.1x 1.9x

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SLIDE 72

E&P Reserves Guidance

72 Note: Reserve estimates follow the same approach used for calculating year-end SEC Proved Reserves. Pricing based on forward curve as of 11/03/16.

Reserves Growth Estimates 2014-2018E (Net)

2014 2015 2016E 2017E 2018E Assumed 12 mo. average price $/MMBtu $4.35 $2.59 $2.48 $2.99 $2.94 Marcellus/Utica PUD well count (net) 458 126 201 373 485

6,200

8,000 11,000

6,827 5,643 5,800 6,500 9,000

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 2,000 4,000 6,000 8,000 10,000 12,000 2014 2015 2016E 2017E 2018E

Assumed 12 Mo. Average Price $/MMBtu Bcfe

Reserves Estimated Range Assumed 12 Mo, Average Price $/MMBTU Assumed 12 Mo. Average Price ($/MMBtu)

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SLIDE 73

0.7x 1.8x 1.7x 1.3x 2.4x 2.8x 3.5x 3.4x 0.6x 1.3x 1.4x 1.5x 1.7x 2.3x 2.4x 2.7x

  • 1.0x

2.0x 3.0x 4.0x 1 2 3 4 CNX 5 6 7 2017 Net Debt/EBITDA 2018 Net Debt/EBITDA

  • Enables the company to weather volatility in

commodity prices and limits the risk that leverage ratio moves into the commercial banks perceived danger zone of 3.5x or higher

  • Protects liquidity; can avoid selling assets, tapping

capital markets, or hedging at the bottom of cycle

  • Provides additional protection in the event of a split;

as E&P loses the coal cash flow and diversification benefits, the company will be smaller and have more concentration risk (as will CNXC)

  • Low leveraged names in a weak market avoid a

discount to share price.

2017 peer average: 2.2x(1) 2018 peer average: 1.7x

Cost of Capital: Leverage Ratio Target Between 2.0x to 2.5x

  • Provides the financial flexibility to grow NAV per

share through several means: drilling pace, buybacks, delineation drilling of our non-core assets, and M&A

  • Maintains optimal cost of capital, enabling access to

the capital markets throughout the cycle if the

  • pportunities arise
  • Increases ability to sell assets from a position of

strength and maximize NAV per share

  • Low leveraged names in a normal market receive a

premium attached to share price

(1) Peer leverage ratios based on consensus EBITDA and consensus net debt (Capital IQ). (2) Forecasts based on strip pricing for open volumes as of 11/3/2016; assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018. Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

CNX AR EQT RICE RRC CHK ECR COG SWN DVN WPX NBL GPOR XEC CRK XCO APA QEP BBG SD

R² = 0.8945

  • 1.0

2.0 3.0 4.0 5.0 6.0 7.0 8.0 (80%) (60%) (40%) (20%)

  • 20%

2015 YE Net Debt/EBITDA Estimate

Stock Performance, 12/1/14 to 7/7/15

73

Leverage vs. Stock Performance Industry Leverage Ratios 2017E-2018E Importance of the Target: Offense Importance of the Target: Defense

(2)

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SLIDE 74

Leverage Ratio and Liquidity Projection

(1) Leverage ratio equals expected year-end net debt divided by expected EBITDA. CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. Note: Assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018 Forecasts based on strip pricing for open volumes as of 11/3/2016

  • Path to reaching and maintaining a sub-2.5x leverage ratio
  • Liquidity rises by estimated $1 billion in free cash flow by 2018
  • Bank revolver reaffirmed at $2 billion for fall 2016
  • Plan Upside:
  • Increased efficiencies
  • Rising commodity prices
  • Accelerated drops
  • Additional asset sales

74

Leverage Ratio 2016E-2018E(1) Liquidity 2016E-2018E

Asset Sales Organic

FCF Sources 2017E-2018E

4.7 2.4 1.7 0.0 1.0 2.0 3.0 4.0 5.0 2016E 2017E 2018E 1.7 2.3 2.7 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2016E 2017E 2018E $ in billions

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SLIDE 75

E&P WACC History

(1) Risk free rate is 30 year TTM risk free rate (2) Peer beta is average 2 year beta. Peers include APC, RICE, COG, PDCE, GPOR, CHK, AR, SWN, EQT Note: Forecasts based on strip pricing for open volumes as of 11/3/2016

8% 9% 10% 11% Jan 2016 Feb 2016 Mar 2016 Apr 2016 May 2016 Jun 2016 Jul 2016 Aug 2016 Sep 2016 Oct 2016 Nov 2016

CNX E&P WACC Over Time Measures taken to manage WACC:

  • Created strong modeling predictability
  • Reduced SG&A
  • Reduced leverage ratio
  • Improved liquidity
  • Increased production
  • Reduced unit costs
  • Reduced interest expense
  • Continued NYMEX and basis hedging

Goals:

  • Further reduce debt
  • Repurchase high cost equity
  • Improve outlook and E&P

team coverage from ratings agencies

Sample WACC Calculation CNX E&P Cost of Capital Nov-16 Equity Risk Free Rate(1) 2.6% Beta (Peer Beta)(2) 1.4 Equity Market Risk Premium 6.5% Cost of Equity 11.7% Debt Risk Free Rate (TTM) 2.6% Spread To Treasury 5.5% Pre-Tax Cost of Debt 8.1% Marginal Tax Rate 38.0% After Tax Cost of Debt 5.0% Enterprise ($ in millions) Market Capitalization 4,045 Market Value Net Debt 3,042 Enterprise Value 7,087 WACC 8.8%

75 Annual E&P WACC 2014 2015 2016 11.2% 10.1% 8.8%

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SLIDE 76

CONE Midstream Drives Value to CONSOL Energy

CONE Midstream Partners LP value to CNX is comprised of four main drivers: How CNX views the total value of CONE Midstream Partners LP:

Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR

76

CONE Value Streams to CNX

($ in millions, except per share data) 2016E 2018E IDRs Cash Flow 1.87 $ Multiple 30.0x Ownership 50.0% Value 28 $ LP Units Unit Price 21.00 $ Current Yield 4.9% Units Held 21.69 Distributions through 2018

  • Value

456 $ CONE Gathering Pro Rata EBITDA Contribution to CNX Adjusted EBITDA 29.6 Market Multiple 9.0x Value 267 $ Total Potential Value 750 $ 1,100 $ Value per CNX Share 3.27 $ 4.80 $

Note: 2018 valuation is based on preliminary estimates

$267 $456 $28 $750 2016E

Retained EBITDA LP Units IDRs

CONE Value to CNX 2016E

slide-77
SLIDE 77

CONE Distributions Expected to Grow Meaningfully

(1) CAGR based on potential LP distribution growth cases

77

Net to CNX GP & IDR Distribution Cases Net to CNX LP Distribution Cases

$0 $10 $20 $30 $40 $50 2015 2016 2017 2018 2019 2020 2021 $ in millions 10% CAGR 15% CAGR 20% CAGR $0 $10 $20 $30 $40 $50 $60 2015 2016 2017 2018 2019 2020 2021 $ in millions 10% CAGR 15% CAGR 20% CAGR

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SLIDE 78

2017E Retained EBITDA LP Units Cash Distributions

CNXC: Value of CNX Passive Ownership in PA Operations

75% ownership of PA Mining Complex 16.6 million total LP units held by CNX(2)

CNX % LP Units' share 60.1% CNX % GP Units' share 1.7% CNX Total % Interest in CNXC 61.8%

Base plan to drop remaining

  • wnership over multiple years

CNXC Value Representation(1)

(1) Graph not indicative of actual CNXC valuation to CNX (2) LP units of various classes, on an as-converted basis (3) Unit price as of market close 12/1/2016

78

CNX Coal Resources LP value to CNX is comprised of four main drivers:

Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR

CNXC Value Streams to CNX

(units and $ in millions, except per share data) 2017E Cash Distributions (LP&GP) Common Units 9.7 $ Subordinated Units 23.8 $ GP Units 1.2 $ Total 2017E Cash Distributions 34.7 $ LP Units Unit Price(3) 18.40 $ Units Held 16.6 LP Unit Value 305.8 $ CNXC EBITDA Contribution to CNX 2017E Retained EBITDA 400.0 $

Total combined interest in PA Mining Ops: 90%

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SLIDE 79

Conditions Improving for Complete Separation from CNXC

79

Path to Completing Separation from CNXC

Financial Conditions Improving CNXC Performance Capital Market Strength

Reduction in financing costs Growing revenue and margins

Growing CNX Free Cash Flow

Greater sponsor flexibility

Base plan: Multi-Year Drops

  • Forecast assumes 20% drop in 2018
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SLIDE 80

Financial Outlook: NAV/Share Value Drivers Accelerating

We expect growth while generating free cash flow:

  • Stringent focus on capital allocation to drive the highest NAV per share decisions
  • Become a leader in capital allocation, when compared to the best global companies
  • Invest when rates of return are meaningfully higher than the cost of capital
  • Reduce capital intensity across the whole enterprise

We have improved transparency and predictability:

  • Extending out public forecasts across all business units
  • Providing the tools to build out the NAV of the company
  • Asset development provides 22 years of core development with large upside – JV dissolution reset
  • Fast delineation of our acreage position to capture large NAV optionality

Our plan forecasts strengthening financial metrics:

  • Maintain strong liquidity above $1.5 billion
  • Improving credit metrics and leverage ratio below 2.5x
  • Provide flexibility to finish separating the E&P and coal businesses
  • Use the approximately $1 billion of free cash flow through 2018 to reduce debt and equity
  • Drive down E&P cost of capital to 8% by year-end 2018

80

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SLIDE 81

REGULATORY UPDATE

81

slide-82
SLIDE 82

Core Themes Driving the CONSOL Value Story

82

OPERATIONAL IMPROVEMENT

Increasing EURs Decreasing Costs Disciplined Capital Spending

UNIQUE ASSET BASE

Robust Stacked Pay Opportunities Turning Non-Core Acreage to Core Supplemental Value Streams

CAPITAL ALLOCATION

Growing Free Cash Flow Improving Balance Sheet Path to Share Repurchases

GROWING NAV/Share

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SLIDE 83

Q&A

83