EARNINGS RESULTS

THIRD QUARTER 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; 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 of the separation and whether it will be completed; 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. 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.

Post-Spin Company Names and Stock Trading Symbols

3

Effective November 28, 2017, the company known as CONSOL Energy Inc. (NYSE: CNX) expects to separate its gas business (GasCo or RemainCo) and its coal business (CoalCo or SpinCo) into two independent, publicly traded companies by means of a separation of CoalCo from RemainCo.

• The gas business will be named CNX Resources Corporation (RemainCo, GasCo or CNX) and will continue to be listed on the New York Stock Exchange (NYSE), retaining the ticker symbol “CNX”. After the spin-off occurs, information regarding CNX and its natural gas business will be available at www.cnx.com.

• The coal business will be named CONSOL Energy Inc. (SpinCo, CoalCo or CONSOL) and will be listed on the NYSE under a new ticker symbol: “CEIX”. CoalCo will own, operate and develop all of the company’s coal assets, including the Pennsylvania Mining Complex, the Baltimore Marine Terminal, and approximately 1.6 billion tons of greenfield coal reserves. After the spin-off occurs, information regarding the new CONSOL Energy and its coal business will be available at www.consolenergy.com.

• The master limited partnership that is currently named CNX Coal Resources LP (NYSE: CNXC) will change its name to CONSOL Coal Resources LP and will trade on the NYSE under a new ticker symbol: “CCR”. CoalCo will own 100 percent of the general partner of CONSOL Coal Resources LP (representing a 1.7 percent general partner interest), as well as all of the incentive distribution rights and the subordinated partnership units in CNX Coal Resources LP, which are currently owned by CONSOL Energy Inc. After the spin-off occurs, information regarding CONSOL Coal Resources will be available at www.ccrlp.com

Executive Summary

4

Q3 2017 EXPECTATION

STRATEGIC INITIATIVE

Operational Execution Successful operational quarter deploying next

generation completion designs and positive early production results

Implementing stacked pay design and operational learnings across additional fields heading into FY2018

Non-Core Asset Sales FY 2017 guided range: $400M-$600M Closed sales YTD: $427M

Pursuing sale of additional non-core assets including Virginia coalbed methane project area and scattered Marcellus and Utica acres

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

YE2017 guided range as of Sept. 2017: 2.8x Q3 2017 end consolidated: 2.8x

Intends to continue paying down debt upon completion of the spin transaction

Production Guidance Q3 2017 production of 101 Bcfe implies Q4 2017

production of ~120 Bcfe

Q4 2017 TIL schedule weighted to November On track to meet FY2017 guidance range Reaffirming FY2018 guided production range of

520-550 Bcfe

Share Repurchase Since the end of Q3 2017, have bought back

~$81 million worth of shares through market close on October 30, 2017

Authorization increased to one-year $450 million and will be executed opportunistically as market conditions allow

Spin Transaction SpinCo Record date set for November 15 as

announced on Tuesday, October 31

Distribution date set for November 28 and Regular Way trading expected to commence November 29

Note: The terms “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."

Spin Transaction: Process Overview

5

SpinCo (to be renamed “CONSOL Energy Inc.” following completion of the spin)

Rebranding Ticker CEIX

Exchange NYSE

Distribution Ratio 1 share of CEIX for every 8 shares of CNX outstanding as of the record date

Number of Outstanding SpinCo Shares ~28.75 million(1)

“When Issued” Trading Commences November 14, 2017

Record Date November 15, 2017

Distribution Date November 28, 2017

“Regular Way” Trading Begins November 29, 2017

Note: Anticipated dates; all dates remain subject to change. (1) Based on CNX shares outstanding as of 3Q17 end of about 230 million.

Spin Transaction: Expected Capital Structure

6

SpinCo Capital Raise Expected Sources and Uses

Amount($ in thousands)

New Term Loan A Facility $100,000

New Term Loan B Facility 400,000

New Second Lien Secured Notes 300,000

Total Sources $800,000

Amount($ in thousands)

Refinancing of CNXC Revolver $190,000

Cash transfer to ParentCo, net of fees 425,000

Cash to balance sheet 146,000

Transaction fees and expenses 39,000

Total Uses $800,000

Sources

Uses

RemainCo Pro Forma Net Debt

(1) Estimated pro forma values are approximate as of 3Q 2017 end.

Amount

($ in thousands)

Q3 2017 consolidated LTD plus current portion $2,543,283

Less: Baltimore Terminal bonds 102,865

Less: CNXC Revolver 188,000

Less: SpinCo related other debt obligations 15,352

Less: Cash transfer from SpinCo (net of fees) 425,000

Less: Q3 2017 end cash and cash equivalents 282,096

RemainCo Pro Forma Net Debt $1,529,970

RemainCo Pro Forma Estimates(1)

Q3 2017 Results

7

• On a GAAP basis, Net Loss Attributable to CONSOL Energy Shareholders of $26 million in the 2017 third quarter or ($0.11) per diluted share; Adjusted Net Loss Attributable to CONSOL Energy Shareholders of $36 million, or ($0.15) per diluted share(1); Adjusted Net Loss excludes the following pre-tax items:

- $30 million gain on sale of assets - $2 million unrealized gain on commodity derivative instruments - $17 million in various other items

• Total company Adjusted EBITDA Attributable to Continuing Operations in the third quarter of $168 million

Note: The terms “Adjusted Net Income Attributable to CONSOL Energy Shareholders," and “Adjusted EBITDA Attributable to Continuing Operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation." (1) Income tax effect of Total Pre-tax Adjustments was $5,530 for the three months ended September 30, 2017. Adjusted net loss attributable to CONSOL Energy Shareholders for

the three months ended September 30, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $26,441 less total pre-tax adjustments of $14,943, plus the associated tax expense of $5,530 equals the adjusted net loss attributable to CONSOL Energy Shareholders of $35,854.

Q3 2017 Summary

($ in millions, except per share data) 3Q 2017 3Q 2016

Y/Y

Change 3Q 2017 2Q 2017

Q/Q

Change

Net (Loss) / Income Attributable to CNX Shareholders ($26) $25 ($51) ($26) $170 ($196)

(Loss) / Earnings per Diluted Share ($0.11) $0.11 ($0.22) ($0.11) $0.73 ($0.84)

Revenue and Other Income from Continuing Operations $671 $746 ($75) $671 $866 ($195)

Net Cash Provided by Continuing Operating Activities $179 $168 $11 $179 $89 $90Adjusted EBITDA Attributable to Continuing Operations $168 $158 $10 $168 $177 ($9)

Q3 2017 Results (Cont’d)

8

Source: Company filings. Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding. The term “free cash flow" is a non-GAAP financial measure, which is defined and reconciled to the GAAP Net Cash Provided by Operating Activities below, under the caption “Non-GAAP Reconciliation."

Net (Decrease) / Increase in Cash

• Generated positive free cash flow

- Total free cash flow in Q3 2017 of $94 million compared to $92 million in Q3 2016

- Redeemed total outstanding balance of 2020 and 2021 bonds worth $95 million Used free cash flow generated in Q2 2017 plus cash on hand

• Total capital expenditures in Q3 2017 of $177 million compared to $64 million in Q3 2016

• Share repurchase program increased to one-year $450 million by Board of Directors

- Following the end of Q3 2017, have bought back about $81 million worth of shares through market close on October 30, 2017

Q3 2017 Cash Flow Summary

($ in millions) 3Q 2017 3Q 2016

Y/Y

Change 3Q 2017 2Q 2017

Q/Q

Change

Net Cash Provided by Operating Activities $178 $163 ($6) $178 $89 $89

Capital Expenditures ($177) ($64) ($122) ($177) ($160) ($17)

Proceeds from Asset Sales $82 $21 $61 $82 $326 ($244)

Other Investing $11 (27) $38 $11 $19 ($8)

(Payments on) / Proceeds from Short-Term Debt & Misc. Borrowings ($5) ($104) $99 ($5) ($3) ($2)

(Payments on) / Proceeds from Long-Term Notes ($97) - ($97) ($97) ($19) ($78)

Other Financing ($5) ($6) $1 ($5) ($14) $9

Net (Decrease) / Increase in Cash ($13) ($18) $5 ($13) $238 ($251)

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 Q2 2017 Q3 2017

Tota

l Liq

uid

ity

($ m

illio

ns)

Net

Deb

t /

TTM

Ad

j. EB

ITD

A

Leverage Ratio Total Liquidity

Deleveraging Progress

9

Source: Company filings. Note: The terms “net debt,” “TTM adjusted EBITDA,“ and “free cash flow” are non-GAAP financial measures, which are defined and reconciled to the relevant GAAP measures under the caption “Non-GAAP Reconciliation.“

Leverage ratio down more than 40% since 2015 peak

• Focused on disciplined capital spending and generating free cash flow to drive deleveraging effort

• Redeemed total outstanding balance of 2020 and 2021 bonds worth $95 million in Q3 2017

• Divestiture of non-core assets key to accelerating reduction in net debt

- Guided $400-$600 million in asset sales for FY2017, have closed on $427 million year-to-date

- Continuing to pursue sale of various non-core assets, including Virginia coalbed methane project area and scattered Marcellus and Utica acres

Marketing: Gas Hedges

10

(1) Hedge positions as of 10/17/2017 includes actual settlements of 258.2 Bcf. 2018 excludes 9.1 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 Q3: 127 Bcf (2018-2021)

• Basis hedges added during Q3: 169 Bcf (2017-2021)

Gas Hedges 2017-2021

311.3 333.3

239.1

166.2

94.8

5.3

0.3

7.3

31.7

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)

0.0

Hedge Volumes and Pricing Q4 2017 2017 2018 2019 2020 2021

NYMEX Only Hedges

Volumes (Bcf) 73.5 282.4 316.1 226.3 161.6 113.8

Average Prices ($/Mcf) $3.16 $3.14 $3.14 $2.99 $2.89 $2.59

Index Hedges and Contracts

Volumes (Bcf) 9.6 34.2 17.2 13.1 11.9 12.7

Average Prices ($/Mcf) $3.01 $3.11 $2.62 $2.44 $2.27 $2.09

Total Volumes Hedged (Bcf)(1) 83.1 316.6 333.3 239.4 173.5 126.5

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

Volumes (Bcf) 81.7 311.3 333.3 239.1 166.2 94.8

Average Prices ($/Mcf) $2.62 $2.59 $2.78 $2.69 $2.59 $2.25

NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) 1.4 5.3 - 0.3 7.3 31.7

Average Prices ($/Mcf) $3.16 $3.14 - $2.99 $2.89 $2.59

Total Volumes Hedged (Bcf)(1) 83.1 316.6 333.3 239.4 173.5 126.5

Segment Guidance

11

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) ($0.40)-($0.50) NGL Realized Price ($/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

Note: Guidance as of 10/31/2017, based on NYMEX as of 9/29/2017 of $3.14 per MMBtu + weighted average basis of ($0.61) 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.

Updated 2017E EBITDA Guidance

12

Note: Base plan assumes NYMEX as of 9/29/2017 of $3.14 per MMBtu + weighted average basis of ($0.61) per MMBtu on open volumes. CONSOL Energy is unable to provide a reconciliation of projected 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

(10/31/17)

Prior Total

(9/5/17)

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

$615 $365 ($20) $960 $1,035

Adjustments:

Unrealized (Gain) on Commodity Derivative Instruments

(140) - - (140) (205)

Stock-Based Compensation 20 15 - 35 30

Adjusted EBITDA $495 $380 ($20) $855 $860

Noncontrolling Interest - (40) - (40) (45)

Adjusted EBITDA Attributable to CONSOL Energy Shareholders

$495 $340 ($20) $815 $815

Operations: E&P Activity Summary

13

Development Plan

SWPA SWPA WV OH Q3 2017 YTD 2017

Marcellus Upper Devonian Marcellus Dry Utica TOTAL TOTAL

Horizontal Rigs 1 - - 1 2 2

Drilled 6 - - 4 10 26

Completed - - 13 7 20 46

Turned In Line (TIL) 5 1 11 12 29 41

Avg. TIL Lateral Length (ft) 9,713 10,671 7,671 9,140 8,734 8,704

Q3 2017 Summary

2017 TD TIL TD TIL TD TIL

Marcellus 14 31 10 31 4 0

Utica 21 23 24 26 (3) (3)

Upper Devonian 0 2 0 3 - (1)

CBM 63 63 63 63 - -

TOTAL ex. CBM 35 56 34 60 1 (4)

ΔNew Guide Prior Guide

• Adjustments to the development schedule for the end of the year shifted certain TILs into 2018

- No impact to FY2017 or FY2018 production guidance, which have both been reaffirmed

Operations: E&P Results Summary

14

(3) Adjusted earnings before income tax for the E&P Division of $12.3 million for the three months ended September 30, 2017 is calculated as GAAP earnings before income tax of $20.2 million less total pre-tax adjustments of $7.9 million. The $7.9 million of adjustments are $1.5 million of pre-tax gain related to the unrealized gain on commodity derivative instruments, $11.6 million of pre-tax gains on asset sales, a pre-tax charge of $4.8 million related to stock-based compensation and a pre-tax charge of $0.4 million related to severance expense.

(1) Average Sales Prices for 3Q2017, 3Q2016, and 2Q2017 include gains/(loss) on commodity derivative instruments (cash settlements) of $0.20, $0.47, and ($0.39), respectively. (2) Average Costs for 3Q2017, 3Q2016, and 2Q2017 include DD&A of $1.00, $1.05, and $0.98, respectively.

• Adjusted earnings before income tax for the E&P Division of $12.3 million(3)

• Marcellus Shale total average production costs were $2.20 per Mcfe in the third quarter, a decrease of $0.13 from $2.33 per Mcfe in the year-earlier quarter, or a 6% improvement

- Driven by reductions to production, ad valorem, and other fees, and DD&A

• Utica Shale total average production costs were $1.91 per Mcfe in the third quarter, an increase of $0.10 from $1.81 per Mcfe in the year-earlier quarter, or a 6% impairment

- Driven by lower Utica Shale volumes resulting in increases in lease operating expense as well as higher depreciation associated with higher capital costs in the PA deep dry Utica delineation wells

• E&P Division capital expenditures increased in Q3 2017 to $147.5 million, from $142.3 million spent in Q2 2017 due primarily to an increase in capital associated with additional completions activity

3Q 2017 3Q 2016

Y/Y

Change 3Q 2017 2Q 2017

Q/Q

Change

Average Sales Price(1) ($/Mcfe) $2.50 $2.54 ($0.04) $2.50 $2.47 $0.03

Total Production Costs(2)

($/Mcfe) $2.26 $2.36 ($0.10) $2.26 $2.20 $0.06

Sales Volumes (Bcfe) 101.0 96.4 4.6 101.0 92.2 8.8

Sales Volumes (Bcfe) by Category

Marcellus 60.4 51.8 8.6 60.4 56.9 3.5

Utica 20.1 22.4 (2.3) 20.1 13.8 6.3

CBM 16.2 17.0 (0.8) 16.2 16.5 (0.3)

Other 4.3 5.2 (0.9) 4.3 5.0 (0.7)

15

SWPA Marcellus: Morris Field Development Update

0

100

200

300

400

500

600

700

0 10 20 30 40 50

10

00

0' N

orm

aliz

ed P

rod

uct

ion

(M

Mcf

/M)

Months

Legacy Morris Morris-30 Current Production

Morris Production – Legacy vs. Now

(1) Legacy Morris comprised of 21 wells TIL March 2012-June 2013; Morris 30 comprised of 5 wells TIL mid-2017.

Morris Capital Efficiency – Legacy vs. Now

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

- Morris-30 completed with enhanced stimulated reservoir design

- Increased lateral length, increased proppant loading, min/max stress optimization along with the mechanical diversion testing program is driving increased reservoir performance

• Morris field will be part of core development going forward

• Capital Efficiency (Mcfe/$) has increased over 200% on average from legacy PDPs to Morris-30

• Fully-loaded capital per foot declined 44% - Legacy Morris: $1,896/ft - Morris-30: $1,070/ft

• Full field Utica opportunity remains and the field is being designed for future stacked pay development Legacy Now

0.00

0.50

1.00

1.50

2.00

2.50

3.00

Cap

ital

Eff

icie

ncy

(M

cfe/

$)

Legacy average: 0.78 Mcfe/$

MOR30 average: 2.43 Mcfe/$

16

Ohio Dry Utica: SWITZ Field Development Update

0

50

100

150

200

250

300

350

400

450

500

0

5

10

15

20

25

30

MM

CF/

Day

Wel

l Co

un

t

Online Well Count Daily Production (actuals and forecast)

-

1

2

3

4

5

0 5 10 15 20 25 30

Dri

llin

g D

ays

/ 1

00

0' M

D

Wells Drilled

SWITZ Wells and Production FY2017

SWITZ Drilling Efficiency

• Monroe County online well counts and production expected to continue meaningful growth through the end of 2017

• SWITZ pads will make up a greater proportion of total production, total operating costs are forecasted to fall due to favorable gathering rates and LOE efficiencies:

- SWITZ wells set to have an outsized impact on EBITDA growth through 2018

- 2H2017 average monthly production rates will increase 800% over 1H2017

- Forecasted December 2017 exit rate of 394 MMcf/d compared to January 2017 exit rate of 20 MMcf/d

• Drilling efficiencies have improved significantly as the field has moved to full development

- Most recent 25 SWITZ wells all executed between 0.80-1.42 days/1000’

- These efficiencies directly correlate to cost savings for each additional well in a field

17

Ohio Dry Utica: SWITZ Field Development Update (Cont’d)

-

0.50

1.00

1.50

2.00

2.50

3.00

Cap

ital

Eff

icie

ncy

(M

CF/

$)

- 50

100 150 200 250 300 350 400 450 500

0 10 20 30 40 5075

00

' No

rmal

ized

Pro

du

ctio

n

(MM

CF/

M)

Months

SWITZ 6 (2015) SWITZ 5 (2017) Current Production

SWITZ Productivity Improvements 2015-2017 • The SWITZ 5 pad, which was completed with a new technique was TIL’ed in mid-2017 and is showing a 38% increase in EUR compared to the SWITZ 6, completed in 2015 - Driven by:

Increased sand loading between 43-100% over legacy designs with model driven ceramic optimization

Optimized inter-lateral well spacing to drive accretive NAV for the asset

Revised pad layouts and engineered well specific drilling and completion designs

SWITZ Capital Efficiency 2015-2017

• As a result of the overhauled pad layout and completion designs, capital efficiency (Mcfe/$) on the SWITZ 5 pad increased more than 160%

• Fully-loaded capital per foot declined 49% - SWITZ 6 (2015): $2,157/ft - SWTIZ 5 (2017): $1,096/ft

• Completion speed (ft/day) has remained constant while achieving a 43% increase in sand loading

SWITZ 6 average: 0.90 Mcfe/$

SWITZ 5 average: 2.37 Mcfe/$

2015 2017

APPENDIX

18

Appendix: Liquids Realizations

19

Natural Gas Liquids, Oil, and Condensate

• Q3 2017 liquids sold: 11.0 Bcfe

• Total weighted average price of all liquids increased 34% to $20.77 per Bbl in Q3 2017 from $15.48 per Bbl in Q3 2016(1) and increased 17% from $17.81 per Bbl in Q2

• In Q3, liquids comprised approximately 11% of 2017 production volumes, 16% of E&P sales,

and about 6% of total company revenue and income

Average Price Realization ($ per Bbl)(1)

(1) Excludes propane hedging impact. (2) Price at Mont Belvieu hub in Texas.

2017

2016

Q3 Q2 Q1

Q3 Q2 Q1

NGLs $19.32 $15.96 $29.16 $13.14 $12.84 $12.30

Oil $41.94 $48.18 $44.40 $42.06 $33.72 $30.84

Condensate $41.34 $34.14 $33.84 $37.26 $31.68 $14.64

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

Eth

ane

$/g

al

Mt. Belvieu Ethane (2) CNX Price Appalachian Gas Alternative

Q3 2017 Direct Ethane Sales Comparison

Appendix: Q3 2017 E&P Marketing Highlights

20

• Directly-marketed ethane volumes were

637,000 barrels in Q3 and, on an equivalent basis, yielded a $1.52 per MMBtu premium over CONSOL’s residue natural gas alternative

• $0.12/Mcfe uplift(1) from liquids for total average realization of $2.50 per Mcfe in Q3 2017

Natural Gas Price Reconciliation

2017 2016

Q3 Q3

NYMEX Natural Gas ($/MMBtu) $3.00 $2.81

Average Differential (0.94) (0.86)

BTU Conversion (MMBtu/Mcf)* 0.12 0.11

Gain on Commodity DerivativeInstruments-Cash Settlement 0.20 0.47

Realized Gas Price per Mcf $2.38 $2.53

* Conversion Factor 1.06 1.06

(1) Calculation includes the impact of gas hedging cash settlements.

Appendix: Gas Hedges (Cont’d)

21

(1) Hedge positions as of 10/17/2017.

Physical Fixed Basis and Fixed Price Sales(1) Q4 2017 2017 2018 2019 2020 2021

Physical Fixed Basis Sales

Volumes (Bcf) 16.8 59.1 89.4 90.8 53.1 30.4

Average Basis Prices ($/Mcf) $0.12 $0.01 $0.14 ($0.04) ($0.07) $(0.37)

Physical Fixed Price Sales

Volumes (Bcf) 2.3 4.9

17.2

13.1

11.9

12.7

Average Prices ($/Mcf):

NYMEX portion $3.33 $3.50 $3.18 $3.01 $2.83 $2.61

Basis portion $(1.05) $(1.09) $(0.56) $(0.57) $(0.56) $(0.52)

$2.28 $2.41 $2.62 $2.44 $2.27 $2.09

Hedge Position (Outer ring = NYMEX; Inner ring = Basis)

• Physical fixed basis sales provide opportunities to lock in revenue in illiquid markets

• Systematic hedging of both NYMEX and basis fully covers the majority of 2017 and 2018 expected production

2018 2017

Appendix: Natural Gas Sales Market Mix

22

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%

Appendix: Strong Liquidity Position of ~$2 Billion

23

$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

(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $286 million as of 9/30/2017, $4 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting.

(2) Revolving credit facility as of 9/30/2017.

September 30, 2017 ($ in millions)

Amount/

Capacity

Amount

Drawn

Letters

of Credit

Amount

Available

Cash and Cash Equivalents (1) $282 - - $282

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

Total $2,282 $0 $314 $1,968

Maintenance Covenants Limit

September 30,

2017

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 5.5 to 1.0

Minimum Current Ratio < 1.0 to 1.0 3.1 to 1.0

Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA

24

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) Income tax effect of Total Pre-tax Adjustments was $5,530 and $48,784 for the three months ended September 30, 2017 and September 30, 2016, respectively. Adjusted net

income attributable to CONSOL Energy Shareholders for the three months ended September 30, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $26,441 less total pre-tax adjustments from the above table of $14,943, plus the associated tax expense of $5,530 equals the adjusted net loss attributable to CONSOL Energy Shareholders of $35,854.

Three Months Ended

September 30,

2017 2017 2017 2017 2016

($ in thousands)

E&P Division

PA Mining

Operations

DivisionOther(1) Total Company Total Company

Net Income (Loss) $20,226 $21,011 ($66,888) ($25,651) $27,593

Less: Loss from Discontinued Operations - - - - 34,975

Add: Interest Expense 575 2,164 38,763 41,502 47,317

Less: Interest Income (3) - (1,303) (1,306) (214)

Add: Income Taxes - - 26,758 26,758 52,858

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 20,798 23,175 (2,670) 41,303 162,529

Add: Depreciation, Depletion & Amortization 101,585 41,638 5,545 148,768 151,712

Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $122,383 $64,813 $2,875 $190,071 $314,241

Adjustments:

Unrealized (Gain)/Loss on Commodity Derivative Instruments (1,512) - - (1,512) (159,555)

Gain on Asset Sales (11,557) - (18,758) (30,315) -

Severance Expense 348 4,563 509 5,420 229

Other Transaction Fees - - 6,387 6,387 -

Gain on Debt Extinguishment - - 2,019 2,019 -

Stock-Based Compensation 4,788 5,882 798 11,468 7,771

Pension Settlement - - - - 3,651

Lease Expirations - - - - -

Coal Contract Buyout - (8,410) - (8,410) -

Total Pre-tax Adjustments ($7,933) $2,035 ($9,045) ($14,943) ($147,904)

Adjusted EBITDA from Continuing Operations $114,450 $66,848 ($6,170) $175,128 $166,337

Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2) - 7,065 - 7,065 8,812

Adjusted EBITDA Attributable to Continuing Operations $114,450 $59,783 ($6,170) $168,063 $157,525

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

25

Source: Company filings.

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

Three Months

Ended

Twelve Months

Ended

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

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

Net Income / (Loss) $27,593 ($301,634) ($33,502) $173,823 ($133,720) ($25,651) ($186,964)

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

Add: Interest Expense 47,317 46,867 44,433 43,432 182,049 41,502 176,234

Less: Interest Income (214) (532) (1,543) (6,533) (8,822) (1,306) (9,914)

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

Add: Income Taxes 52,858 (84,990) (53,789) 66,993 (18,928) 26,758 (45,028)

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 162,529 (193,055) (44,401) 277,715 202,788 41,303 81,562

Add: Depreciation, Depletion & Amortization 151,712 156,583 148,770 117,069 574,134 148,768 571,190

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

Continuing Operations $314,241 ($36,472) $104,369 $394,784 $776,922 $190,071 $652,752

Adjustments:

Unrealized (Gain)/Loss on Commodity Derivative Instruments (159,555) 236,802 (24,640) (116,073) (63,466) (1,512) 94,577

(Gain) on Asset Sales - - - (126,707) (126,707) (30,315) (157,022)

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

Severance Expense 229 424 230 113 996 5,420 6,187

Pension Settlement 3,651 4,848 - - 8,499 - 4,848

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

Other Transaction Fees - - 5,316 8,411 13,727 6,387 20,114

Stock Based Compensation 7,771 7,658 6,702 9,975 32,106 11,468 35,803

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

Coal Contract Buyout - (8,410) (8,410)

(Gain)/Loss on Debt Extinguishment - - (822) 36 (786) 2,019 1,233

Total Pre-tax Adjustments ($147,904) $253,484 $124,651 ($207,384) $22,847 ($14,943) $155,808

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $166,337 $217,012 $229,020 $187,400 $799,769 $175,128 $808,560

Less: Adjusted EBITDA Attribuatable to Noncontrolling Interest $8,812 $10,465 $11,578 $10,302 $41,157 $7,065 $39,410

Adjusted EBITDA Attributable to Continuing Operations $157,525 $206,547 $217,442 $177,098 $758,612 $168,063 $769,150

Non-GAAP Reconciliation: Noncontrolling Interest and Net Debt

26

Source: Company filings.

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

Three Months

Ended

Twelve Months

Ended

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

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

Net Income Attributable to Noncontrolling Interest $2,248 $4,413 $5,464 $4,313 $16,438 $790 $14,980

Add: Interest Expense 1,098 1,089 1,099 1,074 4,360 1,077 4,339

Earnings Before Interest & Taxes (EBIT) Attributable to Noncontrolling Interest 3,346 5,502 6,563 5,387 20,798 1,867 19,319

Add: Depreciation, Depletion & Amortization 5,233 4,753 4,706 4,606 19,298 4,640 18,705

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

Noncontrolling Interest $8,579 $10,255 $11,269 $9,993 $40,096 $6,507 $38,024

Adjustments:

Stock Based Compensation 233 210 309 309 1,061 558 1,386

Total Pre-tax Adjustments $233 $210 $309 $309 $1,061 $558 $1,386

Adjusted EBITDA Attibutable to Noncontrolling Interest $8,812 $10,465 $11,578 $10,302 $41,157 $7,065 $39,410

Three Months Ended Three Months Ended

September 30, June 30,

($ in millions) 2017 2017

CNX Total Long-Term Debt including Current Portion $2,543 $2,641

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

Less: CNX Cash and Cash Equivalents 286 299

Add: CNXC Cash and Cash Equivalents 4 6

CNX Net Debt $2,189 $2,276

Non-GAAP Reconciliation: Free Cash Flow

27

Source: Company filings.

Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended

September 30, September 30, September 30, September 30,

($ in thousands) 2017 2016 2017 2016

Net Cash provided by Continuing Operations $178,667 $167,535 $472,838 $373,880

Capital Expenditures (177,294) (64,132) (450,620) (179,389)

Net Distributions from/(Investments in) Equity Affiliates 10,920 1,023 35,620 (4,555)

Organic Free Cash Flow From Continuing Operations $12,293 $104,426 $57,838 $189,936

Net Cash Provided By Operating Activities $178,328 $162,909 $472,224 $388,307

Capital Expenditures (177,294) (64,132) (450,620) (179,389)

Capital Expenditures of Discontinued Operations - 11 - (8,295)

Net Distributions from/(Investments in) Equity Affiliates 10,920 1,023 35,620 (4,555)

Proceeds from Sales of Assets 81,727 20,693 426,878 441,794

Payment on Sale of Miller Creek and Fola Complexes - (28,271) - (28,271)

Free Cash Flow $93,681 $92,233 $484,102 $609,591