EARNINGS RESULTS

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

E&P: Q4 2016 Operations Summary

3

Production Update:

• OPEX Efficiencies: Reduced Q4 2016 OPEX cash costs by $2.1 million while increasing production by 4.9 Bcfe in the same period, improving units costs by $0.09/Mcfe

• WV Ops: Operated additional 28 wells following the dissolution of the Marcellus JV representing an incremental 70 MMcf/d of production, while lowering LOE by $30,000/month

• PA Ops: Accelerated TIL of two RHL23 wells by 14 days, adding 17.3 MMcf/d in production. Production optimization efforts yielded an additional 2 MMcf/d resulting in a net uplift of 19.3 MMcf/d from the pad compared to legacy non-operated production levels

Marcellus Shale Quarterly Summary

Utica Shale Quarterly Summary

Asset Region SWPA

Horizontal Rigs -

Drilled -

Completed 3

Turned In Line (TIL) 8

Avg. TIL Lateral Length (ft) 7,833

Asset RegionOH - Dry Utica

(Monroe County)

Horizontal Rigs 2

Drilled 7

Completed -

Turned In Line (TIL) -

Avg. TIL Lateral Length (ft) -Cycle Time

Improvement

(Y/Y)

Cost

Reduction

(Y/Y)

Drilling 62% 53%

Completions 41% 34%

Q4 2016 Drilling and Completions Update:

E&P: Q4 2016 Results

4

E&P Results Summary

(3) Adjusted earnings before income tax for the E&P Division of $14.3 million for the three months ended December 31, 2016 is calculated as GAAP loss before income tax of $222.5 million plus total pre-tax adjustments of $236.8 million. The $236.8 million adjustment is the pre-tax loss related to the unrealized loss on commodity derivative instruments.

• Adjusted earnings before income tax for E&P segment of $14.3 million(3)

• Production increased by 6% in fourth quarter 2016, compared to year-earlier quarter

• Marcellus Shale total production costs were $2.20 per Mcfe in the fourth quarter, a decrease of $0.18 from $2.38 per Mcfe in the year-earlier quarter, or an 8% improvement

- The improvement in Marcellus Shale operating costs was largely driven by reduced Transportation, Gathering and Compression costs post-JV dissolution

• Utica Shale total production costs were $1.86 per Mcfe in the fourth quarter, a decrease of $0.02 from $1.88 per Mcfe in the year-earlier quarter, or a 1% improvement

• CBM total production costs were $2.72 per Mcfe in the fourth quarter, an increase of $0.09 from $2.63 per Mcfe in the year-earlier quarter, or a 3% impairment

(1) Average Sales Prices for 4Q2016, 4Q2015, and 3Q2016 include gains on commodity derivative instruments (cash settlements) of $0.46, $0.95, and $0.47, respectively. (2) Average Costs for 4Q2016, 4Q2016, and 3Q2016 include DD&A of $1.05 in each period.

E&P Results 4Q 2016(1)4Q 2015

Y/Y

Change 4Q 2016(1)3Q 2016

Q/Q

Change

Average Sales Price(1) ($/Mcfe) $2.77 $2.78 ($0.01) $2.77 $2.54 $0.23

Total Production Costs(2)

($/Mcfe) $2.27 $2.37 ($0.10) $2.27 $2.36 ($0.09)

Sales Volumes (Bcfe) 101.3 95.5 5.8 101.3 96.4 4.9

Sales Volumes (Bcfe) by Category

Marcellus 56.5 49.7 6.8 56.5 51.8 4.7

Utica 22.2 20.7 1.5 22.2 22.5 (0.3)

CBM 17.4 18.7 (1.3) 17.4 17.0 0.4

Other 5.2 6.3 (1.1) 5.2 5.1 0.1

E&P Marketing: Highlights

5

Q4 2016 E&P Realization and Marketing Highlights

• During the quarter, CONSOL successfully completed the majority of its planned firm transportation and processing capacity reallocations in connection with the separation of the joint venture with Noble Energy

• Directly-marketed ethane volumes were 466,000 barrels in Q4 and, on an equivalent basis, yielded a premium price over the Texas Eastern M2 gas market

- An additional ethane contract with favorable terms commenced October 1, 2016

- Directly-marketed ethane gross realization is up 41% from Q3 2016

• $0.09/Mcfe uplift from liquids, including the impact of hedging

Natural Gas Price Reconciliation

2016 2015

Q4 Q3 Q2 Q1 Q4

NYMEX Natural Gas ($/MMBtu) $2.98 $2.81 $1.95 $2.09 $2.27

Average Differential (0.88) (0.86) (0.46) (0.36) (0.54)

BTU Conversion (MMBtu/Mcf)* 0.12 0.11 0.09 0.10 0.10

Gain on Commodity Derivative

Instruments-Cash Settlement 0.46 0.47 0.91 0.98 0.95

Realized Gas Price per Mcf $2.68 $2.53 $2.49 $2.81 $2.78

* Conversion Factor 1.06 1.06 1.06 1.06 1.06

E&P Marketing: Gas Hedges

6

(1) Hedge positions as of 1/17/2017. FY 2017 includes actual settlements of 25.0 Bcf. (2) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (3) Based on total production guidance of 415 Bcfe in 2017E.

Hedged Open

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

2017

2018

020406080

100120140160180200220240260280300320

FY 2017 FY 2018 FY 2019 FY 2020 FY 2021

Gas

Vo

lum

es

He

dge

d (

Bcf

)

NYMEX Only Hedges Exposed to Basis

NYMEX + Basis (2)(2)

Hedge Volumes and Pricing 2017 2018 2019 2020 2021

NYMEX Only Hedges

Volumes (Bcf) 278.9 218.9 153.2 81.6 6.8

Average Prices ($/Mcf) $3.18 $3.15 $3.07 $3.17 $3.08

Index Hedges and Contracts 

Volumes (Bcf) 32.4 1.7 8.5 3.4 -

Average Prices ($/Mcf) $3.19 $2.42 $2.52 $2.35 -

Total Volumes Hedged (Bcf) (1)311.3 220.6 161.7 85.0 6.8

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

Volumes (Bcf) 287.1 182.4 108.6 57.0 -

Average Prices ($/Mcf) $2.57 $2.67 $2.60 $2.79 -

NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) 24.2 38.2 53.1 28.0 6.8

Average Prices ($/Mcf) $3.18 $3.15 $3.07 $3.17 $3.08

Total Volumes Hedged (Bcf)(1)

311.3 220.6 161.7 85.0 6.8

• Approximately 75% of total 2017E production volumes hedged(3)

• NYMEX hedges added during Q4: 215 Bcf (2017-2021)

• Basis hedges added during Q4: 149 Bcf (2017-2020)

2017 2018 2019 2020 2020

E&P Marketing: Liquids Realizations

7

Natural Gas Liquids, Oil, and Condensate

• Q4 2016 liquids sold: 10.0 Bcfe

• Total weighted average price of all liquids increased 38% to $21.34 per Bbl in Q4 2016, from $15.48 per Bbl in Q3 2016(1)

• Liquids comprised approximately 10% of Q4 2016 production volumes, 13% of E&P revenue, and 8% of total company revenue(1)

• 17.5 million gallons of propane hedged from April 2016 through March 2017 at an average price of $0.48 per gallon

Average Price Realization ($ per Bbl)(1)

Gas $ High

Gas $ Low

NGL $ Low NGL $ High

Avoid Processing

Optimize Send to Processing

Optimize

22 Bcf

Wet Gas Flexibility

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

2017

Eth

ane

$/g

al

Mt. Belvieu Ethane CNX Netback Appalachian Gas Alternative

2016 2015

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

NGLs $20.40 $13.15 $12.86 $12.29 $14.18 $4.78 $12.46 $20.39

Oil 41.57 42.05 33.74 30.84 39.08 54.19 46.16 47.79

Condensate 30.84 37.27 31.68 14.66 25.37 27.82 31.27 20.83

2017 Direct Ethane Sales Netback Estimate

(1) Excludes propane hedging impact

Finance: Q4 2016 Review

8

Fourth Quarter 2016 Results

• Adjusted net income from continuing operations in the 2016 fourth quarter of $0.5 million, or $0.00 per diluted share(1); on a GAAP basis, net loss from continuing operations of $321 million or ($1.42) per diluted share

- Adjusted net income excludes the following pre-tax items: $236.8 million unrealized loss on commodity derivative instruments $166.8 million valuation allowance related to alternative minimum tax credits $4.8 million loss related to pension settlement $3.8 million of Marcellus JV Dissolution fees $0.4 million of severance expense

• Adjusted net loss from continuing operations for the full year 2016 of $100 million, or ($0.44) per diluted share;(2) on a GAAP basis, net loss from continuing operations of $536 million or ($2.38) per diluted share

• Total company adjusted EBITDA attributable to continuing operations in the fourth quarter of $205 million

(1) Income tax effect of Total Pre-tax Adjustments was $90,956 the three months ended December 31, 2016. Adjusted net income for the three months ended December 31, 2016 is calculated as GAAP net loss from continuing operations of $321,198 plus total pre-tax adjustments from the EBITDA reconciliation table of $245,826, less the associated tax expense of $90,956, plus a valuation allowance charge of $166,798 for alternative minimum tax credits equals the adjusted net income from continuing operations of $470.

(2) Income tax effect of Total Pre-tax Adjustments was $155,212 for the year ended December 31, 2016. Adjusted net income for year ended is calculated as GAAP net loss from continuing operations $535,965 plus pre-tax adjustments from the EBITDA reconciliation table of $424,274, less the associated tax expense of $155,212 plus a valuation allowance charge of $166,798 equals adjusted net loss of $100,105.

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 flow 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."

Q4 2016 Summary

($ in millions, except per share data) 4Q 2016 4Q 2015

Y/Y

Change 4Q 2016 3Q 2016

Q/Q

Change

Net (Loss) Income Attributable to CNX Shareholders ($306) $30 ($336) ($306) $25 ($331)

(Loss) Earnings per Diluted Share ($1.33) $0.13 ($1.46) ($1.33) $0.11 ($1.44)

Revenue and Other Income $462 $666 ($204) $462 $746 ($284)

Net Cash Provided by Continuing Operations $87 $106 ($19) $87 $166 ($79)Adjusted EBITDA Attributable to Continuing Operations $205 $198 $7 $205 $156 $49

Finance: Q4 2016 Review

9

Source: Company filings. Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding. The terms "adjusted net loss attributable to continuing operations," "adjusted EBITDA," “adjusted EBITDA attributable to continuing operations,” "free cash flow," and "organic free cash flow 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."

Q4 2016 Cash Flow Summary (including Discontinued Operations)

($ in millions) 4Q 2016 4Q 2015

Y/Y

Change 4Q 2016 3Q 2016

Q/Q

Change

Net Cash Provided by Operating Activities $83 $102 ($19) $83 $163 ($80)

Capital Expenditures ($47) ($119) $72 ($47) ($64) $17

Proceeds from Asset Sales $21 $28 ($7) $21 $21 -

Proceeds from Noble Exchange Settlement $213 - $213 $213 - $213

Other Investing $79 ($23) $102 $79 ($27) $106

(Payments on) / Proceeds from Short-Term Debt & Misc. Borrowings ($356) $4 ($360) ($356) ($114) ($242)

Dividends Paid - ($2) $2 - - - Other Financing ($13) - ($13) ($13) $4 ($17)

Net (Decrease) / Increase in Cash ($20) ($10) ($10) ($20) ($17) ($3)

Net (Decrease) / Increase in Cash

• Generated positive free cash flow

- Organic free cash flow from continuing operations in Q4 2016 of $118 million; full-year 2016 total organic free cash flow of $306 million

- Total free cash flow in Q4 2016 of $349 million; full-year 2016 total free cash flow of $957 million

- Reduced outstanding borrowings on the revolving credit facility by $354 million, which increased liquidity and de-levered the balance sheet

- Used free cash flow generated during the quarter, plus cash on hand

• Total capital expenditures in Q4 2016 of $47 million; full-year 2016 total capital expenditures of $227 million

Finance: Liquidity

10

Strong Liquidity Position of ~$1.7 Billion

$2.0 billion Revolving Credit Facility

• 5 year credit facility expires June 2019

• Paid down nearly $1 billion of revolving debt on the credit facility in 2016

• Gas reserves based lending facility borrowing base reaffirmed at $2 billion in Q4 2016

- 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 $60 million as of 12/31/2016, $9 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting.

(2) Revolving credit facility as of 12/31/2016.

December 31, 2016 ($ in millions)

Amount/

Capacity

Amount

Drawn

Letters

of Credit

Amount

Available

Cash and Cash Equivalents (1) $51 - - $51

Revolving Credit Facility(2) $2,000 $0 $326 $1,674

Total $2,051 $0 $326 $1,725

Maintenance Covenants Limit

Dec. 31,

2016

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 3.5 to 1.0

Minimum Current Ratio < 1.0 to 1.0 2.6 to 1.0

Finance: Liquidity

11

Debt and Liquidity Profile CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 12/31/2016 12/31/2016 12/31/2016

Capitalization

Cash and Cash Equiva lents $61 $10 $51

Revolving Credit Faci l i ty Balance 201 201 -

Capita l Lease Obl igations 49 - 49

Total Secured Debt $250 $201 $49

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

Miscel laneous Debt 5 - 5

Total Debt (2) $2,802 $201 $2,601

Net Debt (3) $2,741 $191 $2,550

Stockholders ’ Equity $3,941 $143 $3,798

Total Capitalization $6,743 $344 $6,399

Liquidity

Cash and Cash Equiva lents $61 $10 $51

Revolving Credit Faci l i ty Capacity (4)

1,873 199 1,674

Total Liquidity $1,934 $209 $1,725

CNX

Owned

LP Units(5)

Unit

Price(5)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 16.6 $17.90 $297

CONE Midstream Partners LP (CNNX:NYSE) 21.7 $24.55 $533

Total Equity Value of Ownership Interests in Affiliated Public MLPs $830

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity

CNX Coal Resources LP (6)

$400 $201 $199 $10 $209

CONE Midstream Partners LP (6) $250 $181 $69 $4 $73

Leverage Ratio 12/31/2016

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7) $628

LTM Bank Net Debt / Adj. EBITDA (7) 4.4x

Equity Value of Ownership in Affiliated Public MLPs

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.

(5) Number of MLP units owned by CNX as of 12/31/2016 and unit prices as of market close on 1/20/2017. (6) CNX Coal Resources liquidity data is as of 12/31/2016 and CONE Midstream data is pro forma as of 9/30/2016 to account for acquisition of additional interest in Anchor System funded in part by $140 million draw on revolving credit facility. (7) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the reconciliation is provided in the Appendix. Bank methodology LTM EBITDA equals LTM Adjusted EBITDA of $687 million less a loss on sale of assets of $12 million, plus coal contract buyout of $6 million, less the $51 million of CNXC EBITDA net of cash distributions attributable to CNX, less $6 million of severance payments, plus $4 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 of $2,741 equals debt of $2.802 billion, less $51 million cash on hand excluding CNXC’s cash, less $201 million of CNXC revolver debt, less $3 million of advance mining royalties, plus $243 million of net letters of credit related to firm transportation obligations, mining equipment leases, and insurance policies.

(2) Total Debt of $2.802 billion excludes total unamortized debt issuance costs of $28 million. (3) Net Debt equals Total Debt less Cash and Cash Equivalents. (4) As of 12/31/2016, CNX had approximately $326 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,674 million of availability. CNXC

had $201 million outstanding on its revolving credit facility leaving approximately $199 million of availability.

Finance: Leverage Ratio and Liquidity Projection

(1) Leverage ratio equals expected year-end net debt divided by expected EBITDA. CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

(2) Excludes letters of credit of $243 million Note: Assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018 Forecasts based on strip pricing for open volumes as of 1/3/2017

• Year-end 2016 leverage ratio below prior forecast; 2017E and 2018E targets reduced by 0.2x and 0.3x, respectively

• Path to reaching and maintaining a sub-2.5x leverage ratio

• Liquidity rises by estimated $1 billion in free cash flow by 2018

• Plan Upside: - Increased efficiencies - Rising commodity prices - Accelerated drops - Additional asset sales

12

Leverage Ratio 2016-2018E(1)

Liquidity 2016-2018E

Asset Sales Organic

FCF Sources 2017E-2018E

4.4

2.2

1.4

0.0

1.0

2.0

3.0

4.0

5.0

2016 2017E 2018E

1.7

2.3

2.8

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2016 2017E 2018E

$ in

bill

ion

s

(2) (2)

Finance: Legacy Liabilities

Significant legacy liability reductions over

past three years: • Miller Creek/Fola transaction drove

substantial reduction in legacy liabilities

in 2016

• Continue to actively manage the reduction

of legacy liabilities

13

Balance Sheet Liability Long-Term Liability Guidance

12/31/2016 FY 2017E FY 2018E

LTD $19

WC 80 CWP 119

OPEB 700

Salary Retirement/Pension 115

Asset Retirement Obligations 233

Total Legacy Liabilities $1,266

Total Cash Servicing Cost $92 $74 - $79 $70 - $75

EBITDA Impact ($60 - $65) ($18 - $23) ($21 - $26)

$4,187

$1,703 $1,497

$1,362 $1,266 $1,229

$365

$144 $139 $133

$92$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 2017E

An

nu

al C

ash

Se

rvic

ing

Co

sts

($ in

Mill

ion

s)

Lega

cy L

iab

iliti

es

($ in

mill

ion

s)

Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost

Note: 12/31/16 liability balance includes approximately $27 million and $40 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 closing.

Finance: E&P Guidance

Note: Guidance as of 1/31/2017 (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

14

E&P Segment Guidance 2017E 2018E

Production Volumes:

Natural Gas (Bcf) 375 445 NGLs (MBbls) 5,800 5,950 Oil (MBbls) 45 40 Condensate (MBbls) 740 730

Total Production (Bcfe) 415 485 % Liquids 10% 8%

Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.63) ($0.50) NGL Realized Price ($/Bbl) 19.70 19.50 Condensate Realized Price % of WTI 70% 70% Oil Realized Price % of WTI 90% 90%

Capital Expenditures ($ in millions):

Drilling and Completions $465 Midstream $40 Land, Permitting and Other $50

Total E&P and Midstream CapEx $555 $600 Average per unit operating expenses ($/Mcfe):

Lease Operating Expense 0.23 Production, Ad Valorem, and Other Fees 0.07 Transportation, Gathering and Compression 0.77

Total Cash Production and Gathering Costs 1.06 1.05

Other Expenses ($ in millions):

Selling, General, and Administrative Costs(1) $70 $70

Other Corporate Expenses(2) $80 $60

Finance: PA Mining Operations Guidance

15

• Capital expenditures expected to be approximately $5 per ton in 2017 and beyond

PA Mining Operations – Consolidated 100% Basis 2017E 2018E

Estimated Total Coal Sales Volumes (in millions of tons) 26.0 26.0 Total Committed Volumes (Contracted & Priced) 25.4

% Committed 98% Capital Expenditures ($ in millions):

Production $120 Other (Land/Water/Safety) $15 Total Coal Capital Expenditures ($ in millions) $135 $140

Note: Guidance as of 1/31/2017

Finance: Raising 2017E EBITDA Guidance

(1) Includes forecasted Earnings of Equity Affiliates of $36 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream. This income is reflected within Miscellaneous Other Income in the CNX Income Statement.

Base plan assumes NYMEX as of 1/3/2017 $3.38 per MMBtu + weighted average basis of ($0.65) per MMBtu on open volumes. Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

EBITDA Guidance by Segment – 2017E

16

($ in millions) E&P(1) Coal Other Current

Total (1/31/17)

Prior Total

(12/13/16)

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

$705 $390 ($15) $1,080 $840

Adjustments:

Unrealized Loss/(Gain) on Commodity Derivative Instruments

(200) - - (200) (5)

Stock-Based Compensation 20 10 - 30 30

Adjusted EBITDA $525 $400 ($15) $910 $865

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

Adjusted EBITDA Attributable to CNX $525 $355 ($15) $865 $820

APPENDIX

17

Finance: Q4 2016 Review

18

Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA

Source: Company filings. Note: Income tax effect of Total Pre-tax Adjustments was $90,956 and $36,257 for the three months ended December 31, 2016 and December 31, 2015, respectively. Adjusted net income for the three months ended December 31, 2016 is calculated as GAAP net loss from continuing operations of $321,198 plus total pre-tax adjustments from the above table of $245,826, less the associated tax expense of $90,956, plus a valuation allowance charge of $166,798 for alternative minimum tax credits equals the adjusted net income from continuing operations of $470. (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.

Three Months Ended

December 31,

2016 2016 2016 2016 2015

($ in thousands)

E&P Division

PA Mining

Operations

DivisionOther(1) Total Company Total Company

Net (Loss) Income ($222,454) $50,121 ($129,301) ($301,634) $34,325

Less: (Income) Loss from Discontinued Operations, net - - (19,564) (19,564) 11,017

Add: Interest Expense 646 2,502 43,719 46,867 49,081

Less: Interest Income - - (532) (532) (431)

Add: Tax Valuation Allowance - - 166,798 166,798 65,395

Add: Income Taxes - - (84,990) (84,990) 60,347

(Loss) Earnings Before Interest & Taxes (EBIT) (221,808) 52,623 (23,870) (193,055) 219,734

Add: Depreciation, Depletion & Amortization 105,730 42,861 7,992 156,583 139,988

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

Continuing Operations ($116,078) $95,484 ($15,878) ($36,472) $359,722

Adjustments:

Unrealized Gain/(Loss) on Commodity Derivative Instruments 236,802 - - $236,802 (62,388)

Severance Expense - - 424 $424 -

Pension Settlement - - 4,848 $4,848 15,921

Marcellus Dissolution - - 3,752 $3,752 -

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

OPEB Plan Changes - - - - (109,879)

Gain on Sale of Non-Core Assets - - - - (7,551)

Total Pre-tax Adjustments $236,802 - $9,024 $245,826 ($157,639)

Adjusted EBITDA $120,724 $95,484 ($6,854) $209,354 $202,083

Less: Net Income Attributable to Noncontrolling Interest - 4,413 - 4,413 3,920

Adjusted EBITDA Attributable to Continuing Operations $120,724 $91,071 ($6,854) $204,941 $198,163

Finance: Q4 2016 Review

19

Non-GAAP Reconciliation: Trailing Twelve Months EBIT, EBITDA, and Adjusted EBITDA

Source: Company filings.

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Year

Ended

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

($ in thousands) 2016 2016 2016 2016 2016

Net Income / (Loss) ($96,458) ($468,649) $27,593 ($301,634) ($839,148)

Less: Loss from Discontinued Operations 53,167 234,605 34,975 (19,564) 303,183

Add: Interest Expense 49,865 47,427 47,317 46,867 191,476

Less: Interest Income (214) (547) (214) (532) (1,507)

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

Add: Income Taxes (23,800) (100,856) 52,858 (84,990) (156,788)

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations (17,440) (288,020) 162,529 (193,055) (335,986)

Add: Depreciation, Depletion & Amortization 154,988 135,220 151,712 156,583 598,503

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

Continuing Operations $137,548 ($152,800) $314,241 ($36,472) $262,517

Adjustments:

Unrealized Gain/(Loss) on Commodity Derivative Instruments 29,271 279,715 (159,555) 236,802 386,233

Severance Expense 2,918 1,451 952 424 5,745

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

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

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

Gain/(Loss) on Sale of Non-core Assets 12,636 - - - 12,636

Total Pre-tax Adjustments $44,825 $288,574 ($154,951) $245,826 $424,274

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $182,373 $135,774 $159,290 $209,354 $686,791

Less: Noncontrolling Interest $1,114 $1,179 $2,248 $4,413 $8,954

Adjusted EBITDA Attributable to Continuing Operations $181,259 $134,595 $157,042 $204,941 $677,837

Finance: Q4 2016 Review

20

Free Cash Flow Reconciliation

Source: Company filings.

Three Months Ended Year Ended

December 31, December 31,

($ in thousands) 2016 2016

Net Cash provided by Continuing Operations $87,139 $459,350

Capital Expenditures (47,431) (226,820)

Net Investment in Equity Affiliates 78,298 73,743

Organic Free Cash Flow From Continuing Operations $118,006 $306,273

Net Cash Provided By Operating Activities $82,647 $469,285

Capital Expenditures (47,431) (226,820)

Net Investment in Equity Affiliates 78,298 73,743

Proceeds from Noble Exchange 213,295 213,295

Proceeds from Sale of Assets 20,925 59,902

Capital Expenditures of Discontinued Operations - (8,295)

Payments on Sale of Miller Creek/Fola - (28,271)

Proceeds from Sale of Buchannan Mine 1,000 403,817

Free Cash Flow $348,734 $956,656