BARCLAYS CEO ENERGY-POWER

CONFERENCE SEPTEMBER 5, 2017

Cautionary Language

2

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 (including the timing and success of the potential separation); 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: uncertainties as to the timing and manner of the separation (whether by sale or spin-off) and whether it will be completed (including any dropdowns of the coal business); the possibility that various closing conditions for the separation may not be satisfied; the impact of the separation on our business; the expected tax treatment of the separation; the risk that the coal and natural gas exploration and production businesses will not be separated successfully or such separation may be more difficult, time-consuming or costly than expected, which could result in additional demands on our resources, systems, procedures and controls, disruption of our ongoing business and diversion of management's attention from other business concerns; competitive responses to the separation; we may not receive the prices we expect to receive for our natural gas, natural gas liquids, and coal, including due to oversupply 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 of 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 participation in joint ventures may restrict our operational and corporate flexibility, and actions taken by a joint venture partner may impact our financial position and operational results; we may not be able to sell non-core assets on acceptable terms; acquisitions and 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 our results of operations, financial position, and cash flows; we may be unable to incur indebtedness on reasonable terms; provisions in our multi-year coal sales contracts may provide limited protection and may result in economic penalties to us or permit the customer to terminate the contract; the majority of 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, 2016 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs as well as the factors described under the caption “Risk Factors” in the Form 10 filed with the SEC by the CONSOL Mining Corporation, on July 11, 2017, as amended from time to time. 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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Agenda

Executive Summary

Company Update • Overview • FY2017 Activity Summary • Marcellus Operations • Utica Operations • Marketing Overview • Guidance Updates

Strategic Initiatives • Asset Sale Update • Coal Separation Overview

Q&A

Executive Summary

4

Current Q2 2017 Δ DRIVERS

GUIDANCE

Production – 2017E (Bcfe)

405-415 420-440 -20

Completion design optimization in Monroe County resulting in longer cycle times, greater water flowback, and increased equipment maintenance

Surface and downhole issues that required intervention

Tightening in the availability of field services

Total Company EBITDA – 2017E ($ millions)

$815 $870 -$55 Decline in production relative to prior expectation Weaker than expected coal realizations

Leverage Ratio – YE2017 (Net Debt / TTM Adj. EBITDA)

2.8x 2.6x +0.2x Reduction in YE2017E TTM adjusted EBITDA

Asset Sales ($ millions)

$410 $345 +$65 Additional asset sales closed in Q3 2017 and one

expected to close in Q4 2017

Note: The terms “EBITDA,” “net debt,” and “TTM adjusted EBITDA" are non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measure below, under the caption “Non-GAAP Reconciliation.”

• Reducing 2017 E&P Division production guidance to approximately 405-415 Bcfe, compared to the previously stated guidance of 420-440 Bcfe

- Reaffirming capital guidance for FY2017 of $620-$645 million - Reaffirming FY2018 production guidance of 520-550 Bcfe

• Q3 2017 production expected to be approximately 100 Bcfe with Q/Q spike in Q4 2017 as TIL schedule ramps

• Total asset sales, including signed agreements, have reached approximately $410 million - Forward leverage ratio estimate assumes low-end of $400-$600 million asset sale guidance

• Coal segment spin targeted in Q4 2017

• One-year $200 million share repurchase program authorized by Board of Directors

COMPANY UPDATE

5

6

CONSOL Energy’s Evolution

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

2014-2015 CONE Midstream Partners LP formed with Noble Energy to provide gathering services in the Marcellus Shale and CNX Coal Resources LP 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 other 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 operational 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

Jan 2016 Today

Restarted Drilling

NBL JV

Resolution

Buchanan

Sale

Miller Creek &

Fola Sale

Turned DUC Inventory

Online

Cash

Stabilization

CNXC/

CNNX Drops CONSOL Mining

Form 10 Awaiting Final Reviews and

Approval from BOD, IRS, and SEC

Planned Spin Execution in Q4 2017

Acreage Position

7

Note: Acreage numbers as of 2016 10-K ; PDPs as of 6/30/2017 (1) Approx. Net Locations calculated with corresponding lateral lengths and spacing for each respective asset region and formation found on modeling input slides; based on total

undeveloped acreage, including both type curve guidance area and surrounding acreage.

SWPA WV CPA OH Total

Upper Devonian Net Acres 111,500 157,000 35,500 - 304,000

Net Acres 103,000 62,000 234,500 13,500 413,000

Fee Acres 41,000 2,000 19,000 3,000 65,000

Approx. Net Locations (1)

572 411 1,472 85 2,540

Net Producing Wells (PDPs) 197 39 60 1 297

Net Acres 151,500 181,000 229,000 121,500 683,000

Fee Acres 48,000 13,000 16,000 38,000 115,000

Approx. Net Locations (1) 855 1,104 1,294 483 3,736

Gross Producing Wells (PDPs) 1 - 1 98 100

Utica

Marcellus

FY2017 Activity Focus

8

OH – Dry Utica Switz

• Eight pads • Drilling began Q3 2016 • TILs began July 2017

WV – Marcellus Shirley/Pennsboro

• Four pads • Remaining DUC inventory • TILs began May 2017

SWPA – Marcellus Morris/Green Hill/Richhill • Three pads • Drilling began Q1 2017 • TILs began Q3 2017

CPA – Deep Dry Utica Aikens/Marchand

• Two Aikens wells offsetting Gaut 4IH - Drilling began Q1 2017 - TILs scheduled Q4 2017

• Marchand well to start drilling in late Q3 2017

0

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70

80

0

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40

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80

100

120

140

160

180

200

2014 2015 2016 2017E

Incr

emen

tal W

ells

On

line

Net

Op

erat

ed P

rod

uct

ion

(B

cfe)

TIL Year

Marcellus Utica Net Production New wells

Operational Evolution

9

Key Performance Metrics(1) 2014 2017E

Average EUR (Bcfe/1,000’) 1.4 2.8

Lease operating expense (LOE) ($/Mcfe) 0.49 0.19

Average Marcellus drilling days on well 27 14

Completion efficiency (ft/day) 575 1,040

Completion stage spacing (ft) 300 200-225

Completion proppant volume (lbs/ft) 1,300 2,500-3,500

Improved operational performance:

• Lean manufacturing

• Supply chain management

• Zero-based budgeting

Sustained growth at lower $/EUR

(1) Combined Marcellus and Utica key performance metrics unless otherwise noted

Cumulative Net Operated Production vs. Incremental Wells TIL by Year

Operational Evolution: Richhill Type Curve and EUR Increase

10

Richhill, SWPA – Marcellus

• EUR increasing 20%, from 1.9 BCF/1000’, to 2.2 BCF/1000’

• RHL-23D and 23E compared to proposed type curve

• Actual production exceeding expectations with lower than forecasted decline

• Production facility capacity optimized to production protocol methodology

• Wells drilled up-dip yielding improved performance, RHL field re-design complete with up-dip approach

1

10

100

1,000

10,000

100,000

0 200 400 600 800 1,000 1,200 1,400

Gas

Rat

e (M

CFD

)

Days

ACTUAL PRODUCTION Proposed Curve Current Plan TC

Richhill-23D and 23E: Actual Production vs. Decline Curve

Operational Evolution: Additional Revised Type Curves

11

Monroe County, OH – Dry Utica

• Better-than-expected reservoir performance, but EUR unchanged

• Accelerated production driven by: - Optimized inter-lateral

spacing - Optimized stage length and

proppant type, size, and loading

Morris Field, SWPA – Marcellus

• Shape of type curve changed due to accelerated production, but EUR remains the same

• Production protocol used to enhance flowback and early time production

• Accelerated production driven by: - Optimized stage length,

diversion techniques, and proppant loading

Revised Type Curve Shape vs. Prior Plan

Revised Type Curve Shape vs. Prior Plan

CPA Deep Dry Utica: Aikens Drilling Update

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0

5000

10000

15000

20000

25000

0 20 40 60 80 100 120

Dep

th (

fee

t)

Days

Aikens wells offsetting Gaut 4IH show 173% improvement in feet drilled/day

• Aikens 5J drilled in 43 days and 5M drilled in 34 days with an average 7,500 foot lateral compared to 99 days for the Gaut 4IH with a 7,000 foot lateral

- Operational efficiency through intermediate section of well bore drove majority of the improvement

• Drilling costs for the Aikens 5J and 5M were $5.5 million and $4.6 million, respectively

- Represents a 71% decline for the Aikens 5M vs. the Gaut 4IH

• Total D&C capital for each Aikens well is expected to be about $15 million compared to approximately $27 million for the Gaut 4IH

• Both Aikens wells are scheduled to be completed and turned-in-line in 4Q17

Aikens 5J and 5M vs. Gaut 4IH: Days vs. Depth Drilled

Gaut 4IH Aikens 5J Aikens 5M

Marketing: Natural Gas Sales Market Mix

13

MIDWEST TETCO M3

TETCO M2

EAST TENNESEE

TETCO ELA

TETCO WLA

TCO POOL

DOMINION SOUTH

Natural Gas Sales Market Mix 2017E 2018E

Columbia (TCO) 10% 10%

TETCO (M2) 50% 52%

TETCO (M3) 10% 6%

Dominion (DTI) 8% 9%

East Tennessee 13% 10%

TETCO ELA & WLA 6% 5%

Midwest (Michcon) 3% 8%

100% 100%

Marketing: Gas Hedges

14

(1) Hedge positions as of 7/12/2017. 2017 includes actual settlements of 177.3 Bcf. 2021 excludes 11.9 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total production guidance of 405-415 Bcfe in 2017E.

• Approximately 77% of total 2017E production volumes hedged(3)

• NYMEX hedges added during Q2: 88 Bcf (2018-2020)

• Basis hedges added during Q2: 101 Bcf (2018-2021)

Gas Hedges 2017-2021

309.8 308.0

200.0

120.2

25.3

5.4 21.1

30.6

21.7

- 0

50

100

150

200

250

300

350

2017 2018 2019 2020 2021

Gas

Vo

lum

es H

edge

d (

Bcf

)

NYMEX Only Hedges Exposed to Basis NYMEX + Basis (2)

Hedge Volumes and Pricing Q3 2017 2017 2018 2019 2020 2021

NYMEX Only Hedges

Volumes (Bcf) 73.5 282.4 311.9 217.6 134.1 17.4

Average Prices ($/Mcf) $3.15 $3.14 $3.14 $3.02 $3.05 $2.99

Index Hedges and Contracts

Volumes (Bcf) 8.2 32.8

17.2 13.0 7.8 7.9

Average Prices ($/Mcf) $3.17 $3.15 $2.62 $2.47 $2.41 $2.39

Total Volumes Hedged (Bcf)(1) 81.7 315.2 329.1 230.6 141.9 25.3

NYMEX + Basis (fully-covered volumes)(2)

Volumes (Bcf) 77.7 309.8 308.0 200.0 120.2 25.3

Average Prices ($/Mcf) $2.54 $2.59 $2.81 $2.73 $2.78 $2.67

NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) 4.0 5.4 21.1 30.6 21.7 -

Average Prices ($/Mcf) $3.15 $3.14 $3.14 $3.02 $3.05 -

Total Volumes Hedged (Bcf)(1) 81.7 315.2 329.1 230.6 141.9 25.3

Updated 2017E EBITDA Guidance

15

Note: Base plan assumes NYMEX as of 6/30/2017 of $3.17 per MMBtu + weighted average basis of ($0.51) per MMBtu on open volumes. CONSOL Energy is unable to provide a reconciliation of projected EBITDA and Adjusted 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. (1) Includes forecasted Earnings of Equity Affiliates of $40 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream Partners. This income is

reflected within Miscellaneous Other Income in the CNX Income Statement.

($ in millions) E&P(1) PA Mining

Operations Other

Current Total

(as of 9/5/17)

Prior Total

(as of 8/1/17)

Earnings Before Interest, Taxes and DD&A (EBITDA)

$675 $380 ($20) $1,035 $1,055

Adjustments:

Unrealized (Gain) on Commodity Derivative Instruments

(205) - - (205) (165)

Stock-Based Compensation 20 10 - 30 30

Adjusted EBITDA $490 $390 ($20) $860 $920

Noncontrolling Interest - (45) - (45) (50)

Adjusted EBITDA Attributable to CNX $490 $345 ($20) $815 $870

2017 TD TIL

Marcellus 10 31

Utica 24 26

Upper Devonian - 3

CBM 63 63

TOTAL ex. CBM 34 60

FY2017 Development Plan Unchanged

Segment Guidance

16

Note: Guidance as of 9/5/2017, based on strip pricing as of 6/30/2017 of $3.17 per MMBtu + weighted average basis of ($0.51) per MMBtu on open volumes. (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. (3) As of end of 2Q17.

E&P Segment Guidance 2017E

Production Volumes: Natural Gas (Bcf) 360-370 NGLs (MBbls) 6,800-7,000 Oil (MBbls) 60-65 Condensate (MBbls) 540-550

Total Production (Bcfe) 405-415 % Liquids 9%-11%

Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35)-($0.43) NGL Realized Price ($/Bbl) $19.00-$20.00 Condensate Realized Price % of WTI 70% Oil Realized Price % of WTI 90%

Capital Expenditures ($ in millions):

Total E&P and Midstream CapEx $620-$645 Average per unit operating expenses ($/Mcfe):

Lease Operating Expense $0.17-$0.21 Production, Ad Valorem, and Other Fees $0.07-$0.08 Transportation, Gathering and Compression $0.90-$0.95

Total Cash Production and Gathering Costs $1.14-$1.24

Other Expenses ($ in millions): Selling, General, and Administrative Costs(1) $70-$75 Other Corporate Expenses(2) $75-$80

PA Mining Operations – Consolidated 100% Basis 2017E

Coal Sales Volumes:

Total Coal Sales Volumes (millions of tons) 25.6-27.6

Total Committed Volumes (contracted and priced) 25.4 % Committed ~95%(3)

Capital Expenditures ($ in millions): Total Coal Capital Expenditures ($ in millions) $112-$120

• Coal capital expenditures expected to be approximately $5 per ton in 2018 and beyond

STRATEGIC INITIATIVES

17

Asset Sale Update

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Analyst Day December 2016

• Announced plan to sell $400-$600 million of assets in 2017

Q4 2016

Q3 2017 Q1 2017

Q1 2017 Earnings Call May 2017

• Closed on $108 million of sales YTD ‐ 6,300 Utica/Point Pleasant acres

in Ohio for $77 million ‐ Two transactions consisting of

non-core oil and gas assets, pipelines and surface properties worth combined $31 million

• Stated expectation to reach ~$300 million in sales by end of Q2 2017

Q2 2017 Earnings Call August 2017

• Announced $245 million of asset sales in the quarter for YTD total of $345 million ‐ $130 million for 12 PDPs, 15 DUCs, and

~11,000 acres in WV ‐ Three other transactions for total of

11,500 undeveloped acres in PA for $85 million

‐ Non-core acreage sale of ~$30 million to close in Q3 2017

• Stated expectation to reach ~$400 million in sales by year end

Q2 2017

Q3 2017 • Closed on $385 million in asset

sales YTD • Reached signed sales agreement on

additional $25 million sale expected to close late September or early October ‐ Total of $410 million closed or

signed sales YTD • Current year-end leverage ratio

forecast based on asset sales already completed YTD

SpinCo Structure: Material Components

19

Pennsylvania Mining Complex

(PAMC)

Premier U.S. thermal coal assets ~90% owned by CNX when combining direct ownership (75%) with ownership in CNXC MLP

Interest in CNXC MLP MLP owns 25% of PAMC; CONSOL Energy owns ~62% of MLP through outstanding LP and GP units

Baltimore Terminal Provides access to seaborne markets and is expected to generate $29-$32 million of EBITDA in FY2017; 15 million ton per year capacity

Legacy Coal Liabilities Legacy liabilities associated with the coal assets including OPEB, asset retirement obligations, and pension costs set to spin off with the segment

Note: For complete details and pro forma financial statements, see Form 10 filed by CONSOL Mining Corp., July 11, 2017, as amended from time to time.

Pennsylvania Mining Complex: Overview

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Mine

Total Recoverable

Reserves (tons)

Avg. AR Gross Heat

Content (Btu/lb)

Average AR Sulfur Content

Annual Production

Capacity (tons)

2016 Production

(tons)

Bailey(1) 259.7 12,920 2.64% 11.5 12.1

Enlow Fork(1) 306.5 13,030 2.25% 11.5 9.6

Harvey(1) 200.5 12,970 2.25% 5.5 3.0

Total 766.7 12,970 2.38% 28.5 24.7

Illinois Basin(2) 11,356 2.94%

Other NAPP(2) 12,293 3.24%

Other Coal MLPs(2,3) 11,881 2.74%

(1) For the period ending December 31, 2016. (2) Source: EIA. Represents average power plant deliveries for the twelve months ending October 31, 2016. (3) Includes Northern Appalachian and Illinois Basin production from ARLP, FELP, RHNO, and WMLP.

• Pennsylvania Mining Complex (PAMC) consists of three like-new underground mines and related infrastructure with high-Btu bituminous coal - PAMC – 766.7 million tons reserves(1) / 28.5 million tons annual

capacity

• Train loadout facility (up to 9,000 tons per hour) with dual rail access with Norfolk Southern and CSX

• High-Btu bituminous thermal coal is primarily sold to utility companies in the eastern United States: ~13,000 Btus per pound average gross heat content and 2.4% average sulfur content over the life of the reserves

• Five longwalls and 15-17 continuous mining sections

• Access to seaborne markets through CONSOL-owned Baltimore Marine Terminal for exporting thermal and metallurgical coal

• Over $2.0 billion invested in Harvey Mine, new slopes, overland conveyor belts, equipment, and plant upgrades since 2008

2016 PA Mining Complex Domestic Customers

PA Mining Complex

Baltimore Terminal

Pennsylvania Mining Complex: Longwall Productivity

21

24.7

4.4 3.9 1.5

10.5

7.0 6.6 6.3 5.0

6.6

2.0 3.6

7.3

4.9

6.4

2.2

6.4

4.8

6.9

6.0

6.5

7.3

4.4

3.6

–

1.0

2.0

3.0

4.0

5.0

6.0

7.0

0

5

10

15

20

25

30

PA

MC

(5)

Ma

rion

Cou

nty

(1)

Mo

non

galia

Cou

nty

(1)

Fed

era

l (1

)

Ma

rsh

all

Co

unty

(2)

Cu

mbe

rlan

d (

1)

Tun

nel R

idge

(1)

Ohio

Co

unty

(1)

Ce

ntu

ry (

1)

Ha

rris

on C

ounty

(1)

Mo

unta

in V

iew

(1

)

Le

er

(1)

Pro

ductiv

ity (tons / e

mplo

yee h

our)

Pro

duction (

mill

ion t

ons)

2016 production 2016 productivity

Higher sulfur Near end of reserve life

Mine mouth operations

Primarily met coal producer

Serve river markets

Source: EIA 923, MSHA. Note: Number of longwalls indicated in parentheses.

Pennsylvania Mining Complex: Transportation Advantage

22

• PAMC has best-in-U.S. access to export infrastructure

• Logistics infrastructure and proximity to coal-fired power plants allow operational and marketing flexibility

• Norfolk Southern and CSX rail lines enable direct access to domestic customers and Baltimore Terminal - Baltimore Terminal provides valuable

options to access international markets

• Transportation advantage: - NAPP has a $4-8/ton advantage vs. ILB in

the Carolinas, and an even greater advantage in the Mid-Atlantic states

- NAPP has a $3-8/ton advantage vs. ILB to Europe / India(1)

- These values do not account for Btu differences (9%-18% higher than ILB’s), which give NAPP an even greater advantage

Transportation Overview

Source: CONSOL and CNXC Management, ABB Velocity Suite. (1) Includes vessel differential. Assumes NAPP exported through Baltimore and ILB exported through Gulf.

Pennsylvania Mining Complex: Marketing

23

PAMC has capitalized on reliable production, world-class quality, and excellent access to rail and port infrastructure to strategically build a highly diversified portfolio, providing volume stability and multiple paths to upside.

PAMC Marketing Strategy 2016 Coal Sales Portfolio by Market Segment

In 2016, PAMC sold coal to 38 domestic power plants located in 18 states, and to thermal and metallurgical end-users located across four

continents.

Maximize sales to established customer base of rail-served power plants in the Eastern U.S., with a focus on top-performing environmentally-controlled plants

Place approximately 5-10% per annum in the crossover met coal market

2

1

Selectively place remaining tonnage in opportunities (domestic or export) that maximize FOB mine

realizations 3

Capitalize on innovative marketing tactics and strategies to grow opportunities and realizations in all

of the Company’s market areas 4

37%

28%

10%

7%

7%

5% 3% 3%

Domestic - PJM

Domestic - Southeast

Domestic - Miso

Europe Terminal

Asia Terminal

Asia Metallurgical

0

10

20

30

40

50

60

70

2012 2013 2014 2015 2016

Ton

s (M

illio

ns)

12%

31%

37%

11%

9%

PAMC

Other NAPP

CAPP

ILB

PRB

Pennsylvania Mining Complex: Marketing (Cont’d)

24

Top 15 PAMC Customer Plants(1) Share of Tons Delivered Top 15 PAMC Customer Plants Annual Coal Burn

2011

Top 15 PAMC Customer Plants

• Provide steady demand for >50 mm tons of coal per year

• Accounted for 82% of our domestic power plant shipments in 2016

• All have been in the portfolio for 3+ years

• Average size = 1.8 GW

• All are equipped with state-of-the-art emission controls, including scrubbers

• None have announced plans to retire

• Operated at a 15 percentage point higher weighted-average capacity factor than other NAPP rail-served plants in 2016

2016

32%

21% 14%

17%

16%

Top customer plants are top performers. PAMC achieved a 20 percentage point increase in market share at these plants since 2011, largely by displacing other NAPP and CAPP producers, with more room still to grow.

(1) Represent the 15 largest U.S. power plant customers of PAMC in 2016, based on total tons sold

2017ERetained EBITDA LP Units Cash Distributions

CNXC: Value of CNX Passive Ownership in PAMC

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%

Option to drop remaining ownership over time

CNXC Value Representation(1)

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. (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 8/29/2017.

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) 15.25$

Units Held 16.6

LP Unit Value 253.4$

CNXC EBITDA Contribution to CNX

2017E Retained EBITDA 345.0$

Total combined interest in PA Mining Ops: 90%

25

Baltimore Terminal: Overview

26

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:

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

• Strong met and stronger thermal export market indications provide reasonable expectation of 12-14 million ton throughput providing $29-$32 million of EBITDA

• Cost savings of at least $1 million from scheduling and supply chain optimization

$4,187

$1,703 $1,497 $1,362 $1,267 $1,232 $1,226

$975

$365

$144 $139 $133

$92 $77 $77 $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 2016 Q2 2017 2017E 2017E

An

nu

al C

ash

Ser

vici

ng

Co

sts

($

in M

illio

ns)

Lega

cy L

iab

iliti

es (

$ in

mill

ion

s)

Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost

Coal Legacy Liabilities

27

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 of legacy liabilities

• Qualified pension plan almost completely funded

Balance Sheet Liability Long-Term Liability Guidance

6/30/2017 FY 2017E FY 2018E

LTD $18

WC 78 CWP 117

OPEB 695

Unfunded Retirement Obligations 107

Asset Retirement Obligations 217

Total Legacy Liabilities $1,232

Total Quarterly Cash Servicing Cost $21 $74 - $79 $70 - $75

EBITDA Impact ($14) ($57 - $62) ($57 - $62)

Note: 6/30/17 liability balance includes approximately $24 million and $37 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 long-term liabilities are forecasted to approximate $8 million, while the EBITDA loss associated thereto is forecasted to approximate $12 million. Excludes gas well plugging and abandonment (or P&A) expense.

At current ~4% discount rate

Assuming 6.3% discount rate

3.0x 2.8x

$-

$500

$1,000

$1,500

$2,000

$2,500

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

YE2015 YE2016 Q1 2017 Q2 2017 2017E Tota

l Liq

uid

ity

($ m

illio

ns)

Net

Deb

t /

TTM

Ad

j. EB

ITD

A

Leverage Ratio Total Liquidity

Spin Process: Leverage Ratio and Restricted Payments Bucket

28

Source: Company filings. Note: The terms “net debt” and “TTM adjusted EBITDA“ non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measures below, under the caption “Non-GAAP Reconciliation.“ (1) Assumes $400 million completed of the $400-$600 million asset sale guidance range for FY2017. (2) See Indentures in Form 8K, Sept. 30, 2015.

Leverage ratio down nearly 40% since end of 2015

(1)

• Rolling aggregated sum equal to 50% of Consolidated Net Income beginning in FY2010 plus net cash proceeds of any equity issuances since that time(2)

• Value as of 6/30/2017: ~$2.7 billion

• Not subject to leverage ratio covenants

• CoalCo value deducted from RP basket

• Intended to be tax-free

Indentures identify two different mechanisms that can be used to execute the CoalCo spin:

Qualified Spin Restricted Payments Basket OR

• Requires gross leverage ratio of <2.75x for pro forma E&P company

• Intended to be tax-free

Summary

29

NAV/SHARE DRIVEN

Free cash flow

Optimized completion design

Disciplined spending rather than chasing production

UNIQUE ASSET BASE

Multiple decades of high NRI inventory

Capacity to monetize or high-grade non-core acres

Large stacked pay opportunity

Premier thermal coal assets

COAL SEPARATION

Management teams and internal processes in place now

Focus on creating two strong separate entities

Plan to execute spin-off in Q4 2017

TWO

PR

EMIE

R S

TAN

DA

LON

E C

OM

PAN

IES

E&P RemainCo

CoalCo

Q&A

30

APPENDIX

31

Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA

32

Source: Company filings. (1) CONSOL Energy's Other Division includes expenses from various other corporate and diversified business unit activities including legacy liabilities costs and income tax

expense that are not allocated to E&P or PA Mining Operations Divisions. (2) Adjusted EBITDA Attributable to Noncontrolling Interest for the three months ended June 30,2017 is Net Income Attributable to Noncontrolling interest of $4,313 plus

Depreciation, Depletion and Amortization of $4,606, plus Interest Expense of $1,074, plus Stock-based compensation of $309. Adjusted EBITDA Attributable to Noncontrolling Interest for the three months ended June 30,2016 is Net Income Attributable to Noncontrolling interest of $1,179 plus Depreciation, Depletion and Amortization of $4,646, plus Interest Expense of $925 plus Stock-based compensation of $192.

Three Months Ended

June 30,

2017 2017 2017 2017 2016

($ in thousands)

E&P Division

PA Mining

Operations

DivisionOther(1) Total Company Total Company

Net Income (Loss) $227,413 $51,876 ($105,466) $173,823 ($468,649)

Less: Loss from Discontinued Operations - - - - 234,605

Add: Interest Expense 598 2,233 40,601 43,432 47,428

Less: Interest Income - - (6,533) (6,533) (547)

Add: Income Taxes - - 66,993 66,993 (100,856)

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 228,011 54,109 (4,405) 277,715 (288,019)

Add: Depreciation, Depletion & Amortization 91,287 41,402 (15,620) 117,069 135,220

Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $319,298 $95,511 ($20,025) $394,784 ($152,799)

Adjustments:

Unrealized (Gain)/Loss on Commodity Derivative Instruments (116,073) - - (116,073) 279,715

Gain on Asset Sales (126,707) - - (126,707) -

Severance Expense 10 - 103 113 1,451

Other Transaction Fees - - 8,411 8,411 -

Loss on Debt Extinguishment - - 36 36 -

Stock-Based Compensation 4,148 5,332 495 9,975 10,430

Pension Settlement - - - - 13,696

Lease Expirations 16,861 - - 16,861 -

Coal Contract Buyout - - - - (6,288)

Total Pre-tax Adjustments ($221,761) $5,332 $9,045 ($207,384) $299,004

Adjusted EBITDA from Continuing Operations $97,537 $100,843 ($10,980) $187,400 $146,205

Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2) - 10,302 - 10,302 6,942

Adjusted EBITDA Attributable to Continuing Operations $97,537 $90,541 ($10,980) $177,098 $139,263

Non-GAAP Reconciliation: TTM EBIT, EBITDA, and Adj. EBITDA

33

Source: Company filings.

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

Three Months

Ended

Twelve Months

Ended

June 30, September 30, December 31, March 31, March 31, June 30, June 30,

($ in thousands) 2016 2016 2016 2017 2017 2017 2017

Net (Loss)/Income ($468,649) $27,598 ($301,634) ($33,502) ($776,187) $173,823 ($133,715)

Less: Loss/(Income) from Discontinued Operations 234,605 34,975 (19,564) - 250,016 - 15,411

Add: Interest Expense 47,428 47,316 46,867 44,433 186,044 43,432 182,048

Less: Interest Income (547) (214) (532) (1,543) (2,836) (6,533) (8,822)

Add: Tax Valuation Allowance - - 166,798 - 166,798 - 166,798

Add: Income Taxes (100,856) 52,858 (84,990) (53,789) (186,777) 66,993 (18,928)

(Loss)/Earnings Before Interest & Taxes (EBIT)

from Continuing Operations (288,019) 162,533 (193,055) (44,401) (362,942) 277,715 202,792

Add: Depreciation, Depletion & Amortization 135,220 151,712 156,583 148,770 592,285 117,069 574,134

Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA)

from Continuing Operations ($152,799) $314,245 ($36,472) $104,369 $229,343 $394,784 $776,926

Adjustments:

Unrealized Loss/(Gain) on Commodity Derivative Instruments 279,715 (159,555) 236,802 (24,640) 332,322 (116,073) (63,466)

Gain on Asset Sales - - - - - (126,707) (126,707)

Impairment on E&P Properties - - - 137,865 137,865 - 137,865

Severance Expense 1,451 952 424 230 3,057 113 1,719

Pension Settlement 13,696 3,652 4,848 - 22,196 - 8,500

Noble Transaction Fees - - 3,752 - 3,752 - 3,752

Other Transaction Fees - - - 5,316 5,316 8,411 13,727

Stock-Based Compensation 10,430 7,771 7,658 6,702 32,561 9,975 32,106

Lease Expirations - - - - - 16,861 16,861

Coal Contract Buyout (6,288) - - - (6,288) - -

(Gain)/Loss on Debt Extinguishment - - - (822) (822) 36 (786)

Total Pre-tax Adjustments $299,004 ($147,180) $253,484 $124,651 $529,959 ($207,384) $23,571

Adjusted Earnings Before Interest, Taxes and DD&A

(Adjusted EBITDA) $146,205 $167,065 $217,012 $229,020 $759,302 $187,400 $800,497

Less: Adjusted EBITDA Attributable to Noncontrolling Interest $6,942 $8,173 $10,465 $11,578 $37,158 $10,302 $40,518

Adjusted EBITDA Attributable to Continuing Operations $139,263 $158,892 $206,547 $217,442 $722,144 $177,098 $759,979

Non-GAAP Reconciliation: Noncontrolling Interest and Net Debt

34

Source: Company filings.

Three Months Ended Three Months Ended

June 30, March 31,

($ in millions) 2017 2017

CNX Total Long-Term Debt including Current Portion $2,641 $2,669

Less: Noncontrolling Interest (38.4%) in CNXC Revolver 72 75

Less: CNX Cash and Cash Equivalents 299 61

Add: CNXC Cash and Cash Equivalents 6 7

CNX Net Debt $2,276 $2,540

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

Three Months

Ended

Twelve Months

Ended

June 30, September 30, December 31, March 31, March 31, June 30, June 30,

($ in thousands) 2016 2016 2016 2017 2017 2017 2017

Net Income Attributable to Noncontrolling Interest $1,179 $2,248 $4,413 $5,464 $13,304 $4,313 $16,438

Add: Interest Expense 925 991 1,089 1,099 4,104 1,074 4,253

Earnings Before Interest & Taxes (EBIT) Attributable to

Noncontrolling Interest 2,104 3,239 5,502 6,563 17,408 5,387 20,691

Add: Depreciation, Depletion & Amortization 4,646 4,723 4,753 4,706 18,828 4,606 18,788

Earnings Before Interest, Taxes and DD&A (EBITDA)

Attributable to Noncontrolling Interest $6,750 $7,962 $10,255 $11,269 $36,236 $9,993 $39,479

Adjustments:

Stock Based Compensation 192 211 210 309 922 309 1,039

Total Pre-tax Adjustments $192 $211 $210 $309 $922 $309 $1,039

Adjusted EBITDA Attibutable to Noncontrolling Interest $6,942 $8,173 $10,465 $11,578 $37,158 $10,302 $40,518

Non-GAAP Reconciliation: Free Cash Flow

35

Source: Company filings.

Three Months Ended Three Months Ended Six Months Ended Six Months Ended

June 30, June 30, June 30, June 30,

($ in thousands) 2017 2016 2017 2016

Net Cash provided by Continuing Operations $88,977 $82,901 $294,171 $206,345

Capital Expenditures (160,348) (37,601) (273,326) (115,257)

Net Distributions from/(Investments in) Equity Affiliates 18,791 - 24,700 (5,578)

Organic Free Cash Flow From Continuing Operations ($52,580) $45,300 $45,545 $85,510

Net Cash Provided By Operating Activities $88,777 $95,446 $293,896 $225,398

Capital Expenditures (160,348) (37,601) (273,326) (115,257)

Capital Expenditures of Discontinued Operations - (1,246) - 394,511

Net Distributions from/(Investments in) Equity Affiliates 18,791 - 24,700 (5,578)

Proceeds from Sales of Assets 325,724 9,831 345,151 18,284

Free Cash Flow $272,944 $66,430 $390,421 $517,358

Appendix: Strong Liquidity Position of ~$2 Billion

36

$2.0 billion Revolving Credit Facility

• 5 year credit facility expires June 2019

• Gas reserves based lending facility borrowing base reaffirmed at $2 billion in Q2 2017

- Includes the right to separate the coal and gas business subject to a leverage test

(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $299 million as of 6/30/2017, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting.

(2) Revolving credit facility as of 6/30/2017.

June 30, 2017 ($ in millions)

Amount/

Capacity

Amount

Drawn

Letters

of Credit

Amount

Available

Cash and Cash Equivalents (1) $293 - - $293

Revolving Credit Facility(2) $2,000 $0 $314 $1,686

Total $2,293 $0 $314 $1,979

Maintenance Covenants Limit

June 30,

2017

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 5.0 to 1.0

Minimum Current Ratio < 1.0 to 1.0 3.3 to 1.0