SCOTIA HOWARD WEIL

2017 ENERGY CONFERENCE

MARCH 27-28, 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: 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; with respect to the termination of the joint venture with Noble, any disruption to our business, including customer and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating and financial 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.

Who We Are: Differentiating Ourselves Through Three Pillars

3

Values:

• Never compromised regardless of circumstance

• Operate daily free of injuries and environmental incidents

• Pursuit of perfection driving towards best-in-class performance

• Mitigates business risk profile and supports license to operate in an industry that is subject to intense public scrutiny

Business philosophy:

• NAV/share focused

• Production growth is a byproduct

• Capital allocation process drives decision-making

• Delivering responsible, long-term value

Asset base:

• Substantial drilling inventory equates to scalable advantages

• Considerable percentage of held by production (HBP) acreage provides unique flexibility in development plans

• Largest stacked pay opportunity set in the lowest cost basin in the U.S.

• Marcellus JV separation unlocks significant stacked pay opportunities

The Path Forward: Realization of Value

4

How we plan to close the value gap:

Realization of Value...

Today $15.73 Closing price 3/20/2016 1 GROW EBITDA –

PRUDENT GROWTH OF E&P PRODUCTION EFFICIENT CAPITAL ALLOCATION TO HIGH IRR, NAV ACCRETIVE AOIs

PAY DOWN DEBT – ORGANIC FREE CASH FLOW AND ASSET MONETIZATIONS DRIVE LEVERAGE RATIO IMPROVEMENT BELOW TARGET OF 2.5x

REDUCE SHARE COUNT – OPPORTUNISTICALLY BUY BACK SHARES AS MARKET ALLOWS

2

3

$-

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

2015 2016

$ in

mill

ion

s

Weathered Downturn Without Issuing Equity

5

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

• All seven Appalachian peers have issued follow-on equity since the beginning of 2014

• CONSOL was able to de-lever the balance sheet and improve liquidity through organically growing free cash flow (FCF) and monetizing assets

• Avoiding issuing equity has resulted in not diluting shareholders and providing further upside potential

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

Follow-On Equity Issued Across Energy Industry 2015-2016

EXPLORATION & PRODUCTION

6

Continuous Improvement

7

0%

20%

40%

60%

80%

100%

120%

140%

160%

0.4

60

.60

0.7

80

.83

0.9

71

.04

1.2

71

.43

1.6

41

.95

2.0

42

.20

1.0

31

.09

1.2

41

.47

1.6

31

.85

1.9

81

.99

2.0

32

.16

2.1

92

.41

2.4

92

.55

1.2

71

.52

1.8

82

.22

2.4

32

.45

2.5

62

.64

2.7

12

.96

3.0

13

.11

3.6

03

.74

3.8

84

.34

2014 2015 2016

BTA

X IR

R (

%)

EUR/Capex (Mcfe/$)

Capital Efficiency

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

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

NAV growth being driven by improved capital efficiency

Operational Evolution

8

Key Performance Metrics(1) 2014 2016E

Average EUR (Bcfe/1,000’) 1.4 2.8

Total Marcellus capital ($/ft) 1,345 835

Lease operating expense (LOE) ($/Mcfe) 0.41 0.19

Average drilling days on well 27 18

Average completion days on well 32 15

Completion stage spacing (ft) 300 150-225

Completion proppant volume (lbs/ft) 1,300 2,500-3,000

Improved operational performance:

• Lean manufacturing

• Supply chain management

• Zero-based budgeting

Sustained growth at lower $/EUR

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

Cumulative Production vs. Incremental Wells TIL by Year

0

10

20

30

40

50

60

70

80

0

100

200

300

400

500

2014 2015 2016

Incr

emen

tal W

ells

On

line

Cu

mu

lati

ve G

as P

rod

uct

ion

, BC

F

Marcellus-Utica Cumulative Production New Wells Online

64% increase in Marcellus core acreage:

• Full control of stacked pay opportunity set

• Incremental 85 MMcfe/d of production

• Further strengthens balance sheet

• Higher weighted average EUR, compared to pre-dissolution

Post-Exchange Marcellus Acreage Map

Dissolution of the Marcellus Shale Joint Venture

9

Marcellus Impact

Pre- JV Dissolution

Post- JV Dissolution

Change

Flowing PDP (MMcfe/d)

535 620 +16%

DUCs 37.5 53 +41%

Net acres (1) 336,000 306,000 (30,000)

Core(2) 99,000 162,000 +64%

Non-core(3) 237,000 144,000 (39%)

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

New World View: Stacked Pay

10

Rhinestreet

Middlesex

Burkett

West River

Formation Name

Pay

Cashaqua

Tully

Hamilton

Marcellus

Onondaga

Utica

Point Pleasant

Trenton 0 GR 400 LITHOLOGY

• 40+ years of stacked pay inventory(1)

• The JV separation gives CONSOL complete operational control in stacked pay opportunities

• The Upper Devonian provides triple stacked pay potential, on top of Marcellus and Utica

• Stacked pays allow CONSOL to take advantage of a dry gathering system

• $0.10-$0.25/Mcfe Utica gathering

• Stacked pays take advantage of infrastructure sunk capital

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

Stacked Pay Value for SWPA: Pad Level Example

11

Stacked Pay Efficiencies

Unstacked Stacked Unstacked Stacked

LOE ($/Mcf) $0.12 $0.05 $0.15 $0.05

Gathering Rate ($/Mcf) $0.45 $0.39 $0.24 $0.18

Capital ($ in thousands) $5,900 $5,450 $13,200 $12,300

Dry Marcellus Dry Utica

Stacked pay development improves IRR by 10-20 percentage points

• Marginal horizons may be pulled into the development plan due to stacked pay economic improvement

• Stacked pay development concentrates large-scale operations in a small footprint

• Concurrently developing two horizons enables cost effective infrastructure build-out for both plays

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

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

Stacked Pay Pad Economics Example(1)

0%

20%

40%

60%

80%

100%

120%

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$2.00 $2.50 $3.00

BTA

X IR

R (

%)

BTA

X N

PV

($

in m

illio

ns)

Gas Price

Unstacked NPVStacked NPVUnstacked IRR %Stacked IRR %

Delineation Schedule (Gross Wells)

2016 2017 2018 2019

2 3 4 4

Moving Utica Non-Core to Core

12

Delineating the Utica through operated

and non-operated wells, data trades, and data purchases:

• Provides geologic and reservoir data to

evaluate NAV impact and helps assess

development risk

• 170,000 dry Utica core acres

• Potential to increase core position by

250,000+ acres by expanding the core

Delineation Opportunities

Non-Operated TIL Forecast (Gross Wells)

2016 2017 2018

Utica 13 17 15

X X X

GH-9 Greene Co. PA

3rd Party Harrison Co. OH

3rd Party Guernsey Co. OH

3rd Party Washington Co. PA

X

Aikens-5 Westmoreland Co. PA

X X

3rd Party Indiana Co. PA

3rd Party Monongalia Co. WV

X

MAJ-6 Marshall Co. WV

X

SWPA Prospect Allegheny Co. PA

X

CPA Prospect Westmoreland Co. PA

X

SWPA Prospect Greene Co. PA

X

SWPA Prospect Greene Co. PA

X

WV Prospect Monongalia Co. WV

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

Stacked Pay with the Utica: The Size of the Prize

13

360,000+ Net Acres

20 Tcfe

Recoverable Resource in Place

5,000+ Triple Stacked Core Locations

40+ Years of Drilling

• 360,000 net acres of double stacked pay opportunity

in the core and non-core areas

• 180,000 core acres with double stacked pay opportunity

• Utica stacked pay delineation in the next 2 years drives

stacked pay development

• 30 Utica non-operated participation wells

• Concentrates the footprint of stacked pays: Upper Devonian

(Rhinestreet, Burkett), Marcellus and Utica

• Accelerates locations into the near-term plan by uplifting

lower value formations

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

program for over 40 years

• Drilled 14 dry Utica wells and participated in 18 other wells

Two-Year Development Plan

14

• Consistently complete DUCs from December 2016 through 2018

- Total of 33 DUCs to be completed in two-year plan

• High value areas in Monroe County, OH and SWPA will be developed throughout 2017, 2018, and beyond

• Delineation prospects will continue to be drilled and evaluated

2017 2018TD FRAC TIL Capex TD FRAC TIL Capex

Marcellus 12 13 13 $80 54 42 40 $260

Utica 0 0 0 $0 3 3 3 $40

Upper Devonian - 2 3 $15 - - - -

Marcellus - 20 18 $95 - - 2 $10

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

CPA Utica 2 2 2 $25 1 1 1 $15

Utica 17 22 22 $210 12 15 13 $140

3rd Party Utica 20 20 20 $15 16 16 16 $25

VA CBM 61 51 51 $20 28 33 33 $5

TOTAL(1) 31 59 58 $465 70 61 58 $500

SWPA

WV

OH

($ in millions)

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

E&P Capital Expenditure Guidance

15

($ in millions) 2017E 2018E

Drilling and Completion $465

Midstream $40

Land, Permitting, and Other $50

Total E&P and Midstream Capital $555 $600

Total Production (Bcfe) 415 485

Expected Production Growth 5% 17%

2017E E&P Capital Plans

• Capital expenditure projections based on current market conditions and forecast

- Flexibility exists to adjust spending as necessitated by commodity fluctuations

• Increase in Land, Permitting, and Other capital driven by return to activity and blocking up acreage

• Running three rigs by end of 2017

• To hold 2016 production flat in 2017, maintenance capital would be approximately $250-$300 million

Drilling & Completions

84%

Midstream 6%

Land, Permitting, and Other

10%

E&P Capital and Production Plans

E&P Marketing: Gas Hedges

16

(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

DIVERSIFIED BUSINESS UNITS

17

CONSOL has a strong track record of successful divestitures:

• 20 NAV-enhancing divestitures since 2012

• Over $5 billion of combined value

Team is now focused on divesting E&P assets:

• Recent Marcellus JV separation provides more control and flexibility with asset base

• Continually evaluating NAV-accretive opportunities

CONSOL has a significant asset base:

• 60+ years of drilling inventory

• Acres all throughout the Appalachian basin in all horizons

Flexible approach:

• Outright sales

• Swaps and trades

• AMI / participations

• Acquisitions

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

Business Development: Strategy

18

Finance: Legacy Liabilities

19

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

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

20

Financial Outlook: NAV/Share Value Drivers Accelerating

We expect growth while generating free cash flow:

• Stringent focus on capital allocation to drive the highest NAV per share decisions

• Become a leader in capital allocation, when compared to the best global companies

• Invest when rates of return are meaningfully higher than the cost of capital

• Reduce capital intensity across the whole enterprise

We have improved transparency and predictability:

• Extending out public forecasts across all business units

• Providing the tools to build out the NAV of the company

- Asset development provides 22 years of core development with large upside – JV dissolution reset

- Fast delineation of our acreage position to capture large NAV optionality

Our plan forecasts strengthening financial metrics:

• Maintain strong liquidity above $1.5 billion

• Improving credit metrics and leverage ratio below 2.5x

• Provide flexibility to finish separating the E&P and coal businesses

• Use the approximately $1 billion of free cash flow through 2018 to reduce debt and equity

• Drive down E&P cost of capital to 8% by year-end 2018

21

Conditions Improving for Complete Separation from CNXC

22

Path to Completing Separation from CNXC

Financial Conditions

Improving CNXC Performance

Capital Market Strength Reduction in financing costs

Growing revenue and margins

Growing CNX Free Cash Flow Greater sponsor flexibility

Pursuing 3 parallel paths:

- Outright sale

- Spin-off

- Additional dropdowns of undivided

interest into CNXC

Finance: Leverage Ratio and Liquidity Projection

23

(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: Guidance as of 1/31/2017. 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

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: E&P Guidance

24

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

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

25

• 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: 2017E EBITDA Guidance

26

(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: Guidance as of 1/31/2017. 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

($ 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

CONSOL Energy Represents a Unique Value Story

27

Focus on NAV/Share Growth

Driving NAV/share growth:

• Significant increases to estimated ultimate recoveries (EURs)

• Reducing drilling and completion (D&C) costs and capital intensity

• Proving up and de-risking reserves

• Accelerating activity

• Continued focus on de-levering the balance sheet

E&P Assets

Asset base is unique:

• Prolific stacked pay positions create significant competitive advantage

• Early efforts to delineate the Utica Shale are driving up net present value

(NPV) estimates

• Large inventory of acreage for potential monetization opportunities

Supplementary Value Drivers

Supplemental value drivers growing over time:

• Diversified Business Units (DBU), which includes:

- CONVEY Water Systems and the Baltimore Marine Terminal

• CNX Coal Resources LP

• CONE Midstream Partners LP

APPENDIX

28

Finance: Q4 2016 Review

29

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

30

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

31

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