Earnings Conference Call Q2 2016

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 included in our

earnings release, and 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 and coal; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately

estimate our economically recoverable natural gas, oil and condensate; we may encounter unexpected operational issues when we drill and mine, including

equipment failures, geological conditions and higher than expected costs for equipment, supplies, services and labor; 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 partners,

who operate assets in which we have a significant interest, may not perform as we expect; we may not be able to sell non-core assets on acceptable terms;

we may be unable to incur indebtedness on reasonable terms; 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; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - disruption to our business, including

customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results; 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.

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 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 oil and 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.

3

Adjusted net loss attributable to continuing operations(1) in the 2016 second quarter of $49 million, or ($0.21) per

diluted share

- Excludes the following pre-tax items:

$279.7 million unrealized loss on commodity derivative instruments

$13.7 million loss related to pension settlement

$6.3 million gain related to a customer’s partial buyout of a coal contract

$1.5 million in severance expense

Q2 2016 production of 99.3 Bcfe, up approximately 23.8 Bcfe from Q2 2015, a 32% increase

Production volumes expected to grow to approximately 380-385 Bcfe in 2016

2016 E&P capital budget guidance reduced 25% to $190 – $205 million, based on the midpoint of the

guidance range, while adding back two rigs in second half of 2016, which will result in drilling 10 wells

throughout rest of year

(1) Q2 2016 net loss includes ($236) million from discontinued operations, net of tax.

Note: The terms "adjusted net loss attributable to continuing operations," "adjusted EBITDA," “adjusted EBITDA attributable to continuing operations,” "free cash flow," and "organic

free cash from continuing operations" are non-GAAP financial measures, which are defined and reconciled to GAAP net (loss)/income and net cash provided by continuing operations

below, under the caption “Non-GAAP Reconciliation."

CONSOL Energy: Second Quarter 2016 Results

Q2 2016 Review

Q2 2016 Summary Y/Y Q-to-Q Seq. Q-to-Q

($ in millions, except per share data) 2Q2016 2Q2015 Change 2Q2016 1Q2016 Change

Net (Loss) Income Attributable to CNX Shareholders ($470) ($603) $133 ($470) ($98) ($372)

Loss per Diluted Share ($2.05) ($2.64) $0.59 ($2.05) ($0.43) ($1.62)

Revenue and Other Income $286 $546 ($260) $286 $533 ($247)

Net Cash Provided by Continuing Operations $84 $42 $42 $84 $123 ($39)

Adjusted EBITDA Attributable to Continuing

Operations $136 $138 ($2) $136 $176 ($40)

(1) (1)

4

Generated positive free cash flow

- Increased organic free cash flow from continuing operations in Q2 2016 to $46 million; first half 2016 organic FCF of

$85 million

- Total free cash flow in Q2 2016 of $66 million; first half 2016 total free cash flow of $516 million

- Q2 2016 cash flow includes $84 million of interest payments

Reduce outstanding borrowings on the revolving credit facility, which increased liquidity and de-levered

the balance sheet

- Used $66.3 million of free cash flow generated during the quarter and the $426.7 million of the cash on hand from

March 31, 2016 to reduce outstanding borrowings on the revolving credit facility, which increased liquidity and de-

levered the balance sheet

Total capital expenditures in Q2 2016 of $38 million: First half 2016 total capital expenditures of $122 million

Source: Company filings. Sum of numbers may differ slightly from totals and financial statements due to rounding.

CONSOL Energy: Net (Decrease)/Increase in Cash

Q2 2016 Review

Q2 2016 Cash Flow Summary (including Discontinued Operations) Y/Y Q-to-Q Seq. Q-to-Q

($ in millions) 2Q2016 2Q2015 Change 2Q2016 1Q2016 Change

Net Cash Provided by Operating Activities $95 $66 $29 $95 $128 ($33)

Capital Expenditures ($38) ($342) $304 ($38) ($84) $46

Proceeds From Asset Sales $10 $5 $5 $10 $411 ($401)

Other Investing ($1) ($16) $15 ($1) ($6) $5

Proceeds From /(Payments on) Short-Term Debt & Misc. Borrowings ($388) $302 ($690) ($388) ($103) ($285)

Proceeds From /(Payments on) Long-Term Debt - ($3) $3 - - -

Dividends Paid - ($14) $14 - ($2) 2

Other Financing (7) $7 ($14) ($7) $10 ($17)

Net (Decrease) / Increase in Cash ($329) $5 ($334) ($329) $354 ($683)

5

E&P Division: Q2 2016 Results Summary

Q2 2016 Review

(1) Average Sales Prices for 2Q2016, 2Q2015 and 1Q2016 include gains on commodity derivative instruments (cash settlements) of $0.91, $0.64 and $0.98, respectively.

(2) Average Costs for 2Q2016, 2Q2015 and 1Q2016 include DD&A of $1.04, $1.18 and $1.08, respectively.

Adjusted loss before income tax for E&P Division of $14.3 million(1)

Production increased by 32% in second quarter 2016, compared to year-earlier quarter

Marcellus Shale all-in unit costs were $2.25 per Mcfe in the second quarter, a decrease of $0.28 from $2.53 per

Mcfe in the year-earlier quarter, or a 11% improvement

Utica Shale all-in unit costs were $1.76 per Mcfe in the second quarter, a decrease of $0.53 from $2.29 per Mcfe in

the year-earlier quarter, or a 23% improvement

CBM all-in unit costs were $2.62 per Mcfe in the second quarter, a decrease of $0.13 from $2.75 per Mcfe in the

year-earlier quarter, or a 5% improvement

Conventional all-in unit costs were $3.50 per Mcfe in the second quarter, a decrease of $1.65 from $5.15 per Mcfe

in the year-earlier quarter, or a 32% improvement

Y/Y Q-to-Q Seq. Q-to-Q

E&P Division 2Q2016 2Q2015 Change 2Q2016 1Q2016 Change

Average Sales Price(1)

($ / Mcfe) $2.50 $2.68 ($0.18) $2.50 $2.73 ($0.23)

Average Costs(2)

($ / Mcfe) $2.27 $2.76 ($0.49) $2.27 $2.41 ($0.14)

Sales Volumes (Bcfe) 99.3 75.5 23.8 99.3 97.5 1.8

Sales Volumes (Bcfe) by Category

Marcellus 53.1 39.9 13.2 53.1 51.2 1.9

CBM 17.1 18.8 (1.7) 17.1 17.6 (0.5)

Utica 23.3 10.7 12.6 23.3 22.9 0.4

Other 5.8 6.1 (0.3) 5.8 5.8 0.0

(1) Adjusted loss before income tax for the E&P Division of $14.3 million for the three months ended June 30, 2016 is calculated as GAAP loss before income tax of $294.5 million

plus total pre-tax adjustments of $280.2 million. The $280.2 million adjustment is the pre-tax loss related to the unrealized loss on commodity derivative instruments and a pre-tax loss

of $0.5 million related to severance expense.

6

(1) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements.

(2) At the midpoint of production guidance.

(3) Hedge positions as of 7/13/2016.

Gas Hedges

Gas Marketing: Hedges

E&P Hedge Program:

Program and actively

monitored hedges

─ Program Hedge - protect

margins on up to 90% of our

Proved Developed

Production

─ Active Hedge Process -

supplements program

hedges up to 80% of our

total production including

proved undeveloped

production

Since 3/31/16, added

approximately 120 Bcf of

NYMEX gas hedges and 170

Bcf of basis hedges through

2020, further protecting

downside

Approximately 70% of total

FY 2016E production

volumes hedged(2)

Q3 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020

NYMEX + Basis(1)

Volumes (Bcf) 72.1 263.6 187.1 108.5 20.6 6.9

Average Prices ($/Mcf) $2.79 $3.04 $2.61 $2.69 2.46 2.63

NYMEX Only Hedges Exposed to Basis (Bcf)

Volumes (Bcf) - - 37.1 41.6 62.6 20.7

Average Prices ($/Mcf) - - $3.01 $3.10 $3.03 $3.19

Physical Sales With Fixed Basis Exposed to NYMEX

Volumes (Bcf) 3.5 4.9 - - - -

Average Hedged Basis Value ($/Mcf) ($0.29) (0.09)$ - - - -

Total Volumes Hedged (Bcf)(3) 75.6 268.5 224.2 150.1 83.2 27.6

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

3Q 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020

Gas V

olu

mes H

ed

ged

(B

cf)

Physical Sales With Fixed Basis Exposed to NYMEX

NYMEX Only Hedges Exposed to Basis

NYMEX + Basis(1)

$4,345

$1,902 $1,694 $1,542 $1,492 $1,374

$370

$148 $153 $137

$106

$0

$50

$100

$150

$200

$250

$300

$350

$400

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

FY 2012 FY 2013 FY 2014 FY 2015 Q2 2016 FY 2016E

An

nu

al C

ash

Se

rvic

ing

Co

st (

$ in

Mill

ion

s)

Lega

cy L

iab

iliti

es

($ in

Mill

ion

s)

Total Legacy Liabilities (left axis) Annual Legacy Liabilities Cash Servicing Cost (right axis)

As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 6/30/2016 12/31/2016E

Legacy Liabilities ($ in Millions)

LTD $39 $20 $22 $20 $19 $18

WC 180 85 90 83 82 81

CWP 184 121 126 123 127 126

OPEB 3,018 1,022 761 672 661 662

Salary Retirement/Pension 225 53 119 94 90 84

Asset Retirement Obligations 699 601 576 550 513 403

Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,492 $1,374

FY 2012 FY 2013 FY 2014 FY 2015 Q2 2016 FY 2016E

Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $137 $106

Legacy liabilities reduced and cash servicing costs reduced by more than 60%

since 2012, with further reductions expected going forward

7

Significant Legacy Liability Reductions Over Past 3 Years

Financial: Legacy Liabilities

Projected $106MM Annual Cash

Servicing Cost for FY 2016, a

$31MM reduction from the year-

end 2015 run-rate of $137MM

Flows through P&L in operating costs

(impact reflected in operating cost

guidance)

Flows through P&L in Coal Division’s “Other Costs”

Flows through P&L within DD&A

Flows through Other Segment in

“Miscellaneous Operating Expense”

$0.23 $0.38 $0.24 $0.16

$1.10$1.02

$1.04$0.93

$0.17 $0.17$0.09

$0.09

$0.84 $0.59

$0.37

$0.26

$1.17

$1.11

$0.82

$0.48

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

2013 2014 2015 2016E

SG&A Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE

8

Full-cycle Breakeven Operating Metrics Declined from $3.51 to $1.92 Per Mcfe, a 45% Projected Decline

E&P Operations - Benchmarking vs Peers

Exceeded cost reduction target of 15% in 2015 with a 22% reduction from 2014

and projecting an additional 25% reduction from 2015

Cash OpEx

(plus G&A) of

$1.28/Mcfe,

plus PUD-to-

PDP CapEx of

$0.48/Mcfe,

equals total full

cycle cash

costs of

$1.92/Mcfe

Hired Tim Dugan to run E&P operations

As of YE 2015 A B C D E F G Wtd. Avg. CNX

E&P Per Unit Future PUD F&D ($/Mcfe) $0.60 $0.75 $0.91 $0.41 $0.48 $0.69 $1.33 $0.79 $0.48

Note: 2016E reflects midpoint of guidance range. Numbers may differ slightly due to rounding.

Source: Company filings and presentations. Peers include AR, COG, EQT, GPOR, RICE, RRC and SWN.

9

$2.0 billion Revolving Credit Facility:

5 year credit facility expires June 2019

Paid down approximately $490 million of revolving debt on the credit facility year-to-date

Gas reserves based lending facility: Lending group reaffirmed CONSOL's $2 billion borrowing base in

April 2016

- Borrowing base is redetermined semi-annually in the Spring and Fall

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

Strong Liquidity Position of ~$1.3 Billion

Financial: Liquidity

Ample liquidity of $1.3 billion with business plans focused on positive free cash flow

generation and deleveraging the balance sheet

(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $98 million as of 6/30/2016, $9 million of which was CNXC’s and consolidated in CNX’s financial statements

per US GAAP accounting

(2) Revolving credit facility as of 6/30/2016

Amount/ Amount Letters Amount

June 30, 2016 ($ in million) Capacity Drawn of Credit Available

Cash and Cash Equivalents(1) $89 - - $89

Revolving Credit Facility(2) $2,000 $466 $309 $1,225

Total $2,089 $466 $309 $1,314

June 30,

Maintenance Covenants Limit 2016

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 4.79 to 1.0

Minimum Current Ratio < 1.0 to 1.0 2.75 to 1.0

10

Debt and Liquidity Profile

Financial: Liquidity (Cont’d)

Note: Some numbers may not match exactly to financial statements due to rounding.

(1) The 2022 and 2023 senior notes includes $5 million and $6 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively.

(2) Total Debt of $3.257 billion includes discontinued operations and excludes total unamortized debt issuance costs of $30 million.

(3) Net Debt equals Total Debt less Cash and Cash Equivalents.

(4) As of 6/30/2016, CNX had approximately $466 million of borrowings and $309 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,225 million of

availability. CNXC had $198 million outstanding on its revolving credit facility leaving approximately $202 million of availability.

Goal to lower leverage ratio and increase liquidity over the next 18 months

(5) Number of MLP units owned by CNX as of 6/30/2016 and unit prices as of market close on 7/19/2016.

(6) CNX Coal Resources liquidity data is as of 6/30/2016 and CONE Midstream data is as of 3/31/2016.

(7) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the

reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $679

million plus gain on sale of assets of $42 million, plus gain related to changes in retiree medical (OPEB)

plan of $211 million, less the $69 million of CNXC EBITDA Attributable to CNX, plus the $39 million of

CNXC cash distributions to CNX, less $18 million of other net adjustments. For a reconciliation of CNXC’s

EBITDA please see the Company’s form 10Q’s and 10K’s. Bank net debt equals debt of $3.059 billion, less

$89 million cash on hand excluding CNXC’s cash, less $3 million of advance mining royalties, plus $241

million of net letters of credit related to firm transportation obligations, mining equipment leases and

insurance policies, less $2 million of debt for discontinued operations.

CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 6/30/2016 6/30/2016 6/30/2016

Capitalization

Cash and Cash Equivalents $98 $9 $89

Revolving Credit Facility Balance 664 198 466

Capital Lease Obligations 38 - 38

Total Secured Debt $702 $198 $504

8.25% Senior Notes due 2020 $74 - $74

6.375% Senior Notes due 2021 21 - 21

5.875% Senior Notes due 2022 (1) 1,855 - 1,855

8.0% Senior Notes due 2023 (1) 494 - 494

Baltimore 5.75% Revenue Bonds due 2025 103 - 103

Miscellaneous Debt 8 - 8

Total Debt (2) $3,257 $198 $3,059

Net Debt (3) $3,159 $189 $2,970

Stockholders’ Equity $4,271 $146 $4,125

Total Capitalization $7,528 $344 $7,184

Liquidity

Cash and Cash Equivalents $98 $9 $89

Revolving Credit Facility Capacity (4) 1,427 202 1,225

Total Liquidity $1,525 $211 $1,314

Equity Value of Ownership in

Affiliated Public MLPs

CNX

Owned LP

Units(5)

Unit

Price(5)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 12.7 $10.90 $138

CONE Midstream Partners LP (CNNX:NYSE) 19.1 $17.00 $325

Total Equity Value of Ownership Interests in Affiliated Public MLPs $463

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity of

Affiliates

CNX Coal Resources LP (6)

$400 $198 $202 $9 $211

CONE Midstream Partners LP (6)

$250 $74 $176 $14 $190

Total Liquidity of Affiliated

Public MLPs $650 $272 $378 $23 $401

Leverage Ratio 6/30/2016

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7)

$884

LTM Bank Net Debt / Adj. EBITDA (7)

3.6x

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0

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

Flow Rate MCf/Day Casing Pressure

The Gaut 4IH well has produced 4.4 Bcf through June 30, 2016, while average

flowing casing pressure remains strong at approximately 6,100 psi 11

Utica Shale: Gaut 4IH Westmoreland County, PA

Expected to produce at flat rate for approximately 400 days until hitting line pressure in February 2017

Establishing reaction to reaching line pressure based on extensive JV / NonOp / Partner data set of 28 wells

We are following a managed pressure drawdown where we are currently dropping pressure at 20 psi/day

Note: Production data has been normalized for temporary/short-term draw-downs and shut-ins due to maintenance.

Expected to CUM 8.4 BCF at

the time it hits line pressure

66

62

46

37

30 29 2927

2524

2321

19 19 19 1917 17

15 14

10 10 10 10 97

6 6

0

10

20

30

40

50

60

70

No

rmal

ized

Asq

rt(K

), m

d^1

/2*

ft

Well

12

Utica Success Normalized Well-to-Well Productivity Comparison

CONSOL has 6 out of the top 10 wells on the list

𝐀√k: A measure of the strength of a well that normalizes for:

• Lateral length

• Stage spacing

• Pressure management

This benchmark metric enables comparison between wells

more accurately than traditional IP testing

*

* Non-Operated well.

‘A’ represents the area in square feet of the contributing hydraulic fracture we create

‘k’ is the permeability in milliDarcy (md) or the ability of the reservoir-hydraulic fracture system to flow gas

104 wells in current Earth Model – 28 wells with production data

13

2016 Planned E&P Activity Overview

E&P Activity Summary – 2016 Plan

E&P Operations

Note: Plan as of 6/30/2016. Average net revenue interest for Marcellus/Utica shales is 43.7%. Table includes one 100% CONSOL-owned wells: a dry Utica Shale well in Monroe

County, Ohio.

Implied inventory exiting 2016 anticipated to consist of 91 Marcellus and Utica

Shale Wells, including 10 new wells expected in 2016

Expected New

Wells Drilled in

H2 2016

Drilled

Uncompleted

Inventory

Drilled

Completed

Inventory

2016 TIL's

Remaining

Implied

2017

Inventory

2016

Completions

Remaining

Marcellus

SW PA Operated 2 18 1 7 14 6

SW PA Non-Op - 5 2 - 7 -

WV Operated - 7 - - 7 -

WV Non-Op - 49 - - 49 -

Total Marcellus 2 79 3 7 77 6

Utica

SW PA Operated - - - - - -

OH Operated 8 1 - - 9 -

OH Non-Op - 5 - - 5 -

Total Utica 8 6 - - 14 -

Total Gross Marcellus/Utica

Wells 10 85 3 7 91 6

14

Guidance

Note: Guidance as of 7/26/2016.

(1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).

E&P Segment Guidance 2016E

Production Volumes:

Natural Gas (Bcf) 338 - 342

NGLs (MBbls) 6,150 - 6,300

Oil (MBbls) 62 - 68

Condensate (MBbls) 850 - 900

Total Production (Bcfe) 380 - 385

Natural Gas Basis Differential to NYMEX ($Mcf) ($0.40) - ($0.50)

NGL Realized Prices ($Bbl) $12.00 - $14.00

Condensate Realized Prices % of WTI 55% - 60%

Oil Realized Prices % of WTI 85% - 90%

Capital Expenditures ($ in millions):

Drilling and Completion $140 - $145

Midstream $34 - $39

Land and Other $17 - $22

Total E&P and Midstream CapEx $190 - $205

Average per unit operating expenses ($/Mcfe):

Lifting (including Direct Admin.) $0.24 - $0.28

Impact Fees/Ad Valorem/Production Taxes $0.08 - $0.10

Gathering, Transportation, Compression & Processing $0.91 - $0.95

Depreciation, Depletion and Amortization $1.04 - $1.07

Total Production and Gathering Cost $2.27 - $2.40

Other Expenses ($ in millions):

Selling, General and Administrative Costs $58 - $62

Unutilized Firm Transportation Expense, net:(1) $15 - $16

15

Guidance

Note: Guidance as of 7/26/2016.

(1) Includes estimated contribution from Miller Creek and Other Coal Operations for fiscal year 2016 and 1Q16 for Buchanan, and excludes Loss on Sale of Buchanan and the

expected Loss on Sale for the Miller Creek and Fola mines.

(2) Includes miscellaneous other income (net of applicable expenses) associated with the company's Terminal Operations, Rental Income, Coal Royalty Income, and other

miscellaneous land income.

(3) Includes Legacy Liability Costs of approximately $80-85 million; Other Coal-Related Corporate Expenses, and other miscellaneous items. Excludes stock-based compensation

and pension settlement charges.

Coal Segment Guidance 2016E

Estimated Total Consolidated Coal Division Sales Volumes (in millions of tons) 24.5 - 27.5

Total Volumes Sold 26.8

% Committed 100%

Total Consolidated Coal Division Capital Expenditures ($ in millions):

Production $85 - $95

Other (Land/Water/Safety/Terminal) $20 - $30

Total Coal Capital Expenditures $105 - $125

Adjusted EBITDA Guidance

CNXC EBITDA $59 - $69

5x

100% PA Coal Complex Operating EBITDA $295 - $345

Less: Noncontrolling Interest ($26) - ($31)

Plus: Other Coal Operating EBITDA(1)

$23 - $28

Plus: Other Coal Misc. EBITDA(2)

$16 - $24

Less: Other Costs and Expenses (including Legacy Liabilities' Cash Costs)(3)

($108) - ($116)

CNX Pro Rata Coal EBITDA $200 - $250

16

Milestones:

Improving E&P performance from high-grading activities, improving completion techniques, reducing cycle times, and

service cost deflation

Adding two rigs while maintaining disciplined on capital expenditures

Benefits from recent long-term contracting activities and operating cost reductions

CONE MLP growth – July 22nd announced 3.7% increase to quarterly distribution to $0.254 per unit, the 5th consecutive

increase since July 2015

Positive initial well results from operated dry Utica (Gaut 4IH, GH9, and Switz 6D)– sets up future stacked pay

opportunities

Improved free cash flow and opportunistic asset sales to de-lever

- Continued focus on zero-based budgeting – expecting significantly reduced costs and improved balance sheet

- Improving price realizations – anticipate excess Appalachian firm transportation capacity above production to drive

narrowing basis differential by year-end 2016. This should help both natural gas and thermal coal prices.

Our management team is motivated and incentivized to generate FCF and NAV/share, which is consistent with the

metrics used in the short and long term incentive programs for 2016

Plans and Goals Aligned to Drive Increased Valuation

We will continue to be focused on increasing shareholder value while staying within

our core values of safety, compliance, and continuous improvement

Key Takeaways

17

Appendix

18

Non-GAAP Reconciliation: EBITDA and Adj. EBITDA

Appendix

Three Months Ended Twelve Months Ended

June 30

2016 2016 2016 2016 2015

($ in thousands)E&P

Division

Coal

DivisionOther

1 Total

Company

Total

Company

Net (Loss)/Income ($294,499) ($212,235) $38,085 ($468,649) ($603,301)

Less: Loss from Discontinued Operations - 235,639 - 235,639 26,078

Add: Interest Expense 755 2,153 44,519 47,427 46,506

Less: Interest Income (320) - (227) (547) (364)

Add: Income Taxes Benefit - - (100,354) (100,354) (301,669)

(Loss)/Earnings Before Interest & Taxes (EBIT) from Continuing Operations (294,064) 25,557 (17,977) (286,484) (832,750)

Add: Depreciation, Depletion & Amortization 105,151 30,069 1 135,221 138,135

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

Continuing Operations ($188,913) $55,626 ($17,976) ($151,263) ($694,615)

Adjustments:

Unrealized Loss on Commodity Derivative Instruments 279,715 - - 279,715 24,936

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

Severance Expense 525 26 900 1,451 -

Pension Settlement - - 13,696 13,696 -

Impairment of E&P Properties - - - - 828,905

Backstop Loan Fees - - - - 7,334

Other Transaction Fees - - - - 4,968

OPEB Plan Changes - - - - (33,649)

Loss on Debt Extinguishment - - - - 17

Total Pre-tax Adjustments $280,240 ($6,262) $14,596 $288,574 $832,511

Adjusted EBITDA $91,327 $49,364 ($3,380) $137,311 $137,896

Less: Noncontrolling Interest - (1,179) (1,179) -

Adjusted EBITDA Attributable to Continuing Operations $91,327 $48,185 ($3,380) $136,132 $137,896

Source: Company filings.

Note: Income tax effect of Total Pre-tax Adjustments was $104,855 and $313,327 for the three months ended June 30, 2016 and June 30, 2015, respectively. Adjusted net income

attributable to CONSOL Energy shareholders for the three months ended June 30, 2016 is calculated as GAAP net loss from continuing operations of $233,010 plus total pre-tax

adjustments of $288,574, less the tax benefit of $104,855, equals the adjusted net loss from continuing operations of $49,291.

(1) CONSOL Energy's Other Division includes expenses from various other corporate activities including income tax expense that are not allocated to E&P or Coal Divisions.

19

Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA

Appendix

Source: Company filings.

Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended

September 30 December 31 March 31 June 30 June 30

($ in thousands) 2015 2015 2016 2016 2016

Net Income / (Loss) $125,470 $34,325 ($96,463) ($468,649) ($405,317)

Less: Loss from Discontinued Operations 4,566 11,733 53,752 235,639 305,690

Add: Interest Expense 48,558 49,081 49,865 47,427 194,931

Less: Interest Income (361) (431) (214) (547) (1,553)

Add: Income Taxes 66,524 126,472 (23,217) (100,354) 69,425

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 244,757 221,180 (16,277) (286,484) 163,176

Add: Depreciation, Depletion & Amortization 146,845 139,986 154,988 135,221 577,040

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

Continuing Operations $391,602 $361,166 $138,711 ($151,263) $740,216

Adjustments:

OPEB Plan Changes (100,947) (109,879) - - (210,826)

Unrealized Gain/(Loss) on Commodity Derivative Instruments (99,138) (62,388) 29,271 279,715 147,460

Pension Settlement 3,132 15,921 - 13,696 32,749

Industrial Supplies Working Capital Settlement - 6,258 - - 6,258

Gain/(Loss) on Sale of Non-core Assets (48,468) (7,551) 13,735 - (42,284)

Severance Expense 7,683 - 2,918 1,451 12,052

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

Total Pre-tax Adjustments (237,738) ($157,639) $45,924 $288,574 ($60,879)

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $153,864 $203,527 $184,635 $137,311 $679,337

Less: Noncontrolling Interest ($6,490) ($3,920) ($1,114) ($1,179) ($12,703)

Adjusted EBITDA Attributable to Continuing Operations $147,374 $199,607 $183,521 $136,132 $666,634

20

Free Cash Flow Reconciliation

Appendix

Source: Company filings.

Three Months Ended Six Months Ended

June 30 June 30

($ in thousands) 2016 2016

Net Cash provided by Continuing Operations 83,571$ 206,307$

Capital Expenditures (37,593) (115,257)

Net Investment in Equity Affiliates - (5,578)$

Organic Free Cash Flow From Continuing Operations 45,978$ 85,472$

Net Cash Provided By Operating Activities 95,299$ 223,740$

Capital Expenditures (37,593) (115,257)

Capital Expenditures of Discontinued Operations (1,254) (8,295)

Net Investment in Equity Affiliates - (5,578)

Proceeds From Sales of Assets 9,831 421,090

Total Free Cash Flow 66,283$ 515,700$