Company Presentation

Q2 2016 Cautionary Language

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 are 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.

2 CONSOL Energy: Company Overview Transformative Journey Towards a Pure Play E&P Company

 December 5, 2013 – transaction with Murray Energy Corp. in which we sold half of coal assets and related assets

 April 19, 2014 – CONSOL Energy 150th Anniversary

 June 12, 2014 – Analyst Day to roll out growing Appalachian E&P Division with best in class coal assets

 September 25, 2014 – IPO of CONE Midstream Partners LP (NYSE: CNNX)

 July 1, 2015 – IPO of CNX Coal Resources (NYSE: CNXC)

 July 28, 2015 – Announced first PA Dry Utica well (Gaut 4I) result in Westmoreland County

 March 31, 2016 – Sold Buchanan Mine and associated met reserves

Coal-E&P Revenue Split, 2012 Coal-E&P Revenue Split, 2014 Coal-E&P Revenue Split, 2015, excl. Buchanan

E&P Revenues E&P Revenues E&P Revenues Coal Revenues Coal Revenues Coal Revenues

Transforming this 152 year old coal company into a powerful E&P company

3 E&P Division

4 E&P Operations E&P Division: Q2 2016 Operations Summary Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary Avg. TIL Turned Turned Avg. TIL Sub- Horizontal Lateral Sub- Horizontal Drilled Completed In Line Counties Drilled Completed In Line Lateral Counties Regions Rigs Length Regions Rigs (TIL) (TIL) Length (ft) (ft) Greene, Southwest Core Wet ------Noble, OH ------16 7,100 Washington, PA Surrounding Harrison, Allegheny, PA ------2 5 6,955 Core Wet Belmont, OH Indiana, ---- Monroe, OH; Central PA ------Westmoreland, Marshall, WV PA Dry Utica ------Westmoreland, Barbour, Northern Greene, PA ------Doddridge, WV Dry Lewis, WV Total 0 0 2 5 6,955 Ohio ------Monroe, OH . Production update Greene, North Wet Washington, ─ Operational Improvement: Through our compressor ------Gas PA; Marshall, consolidation project we have realized $806k in operating WV expense savings YTD. Doddridge, South Wet ------Tyler, Ritchie, ─ Lease Operation Strategy: Implementation of additional Gas WV operational efficiencies and rebidding our Marcellus & Utica Total 0 0 0 16 7,100 contract well tending will yield a savings of $737k for the second half of 2016. . Completion update ─ Production Optimization: Workovers, production tubing installs, ─ Dual Fuel: Projecting a ~65% substitution rate for diesel fuel. and artificial lift opportunities yielded 0.823 Bcfe uplift in 2016 ─ Plugless Completions: Currently performing a second which results in an additional $1.14 million gross income plugless completion test on GH58 pad. Continuing efforts to ─ Production Highlights: eliminate post frac intervention and improve economics.  SWITZ-6 pad: Yielded a Q2 average daily rate of 56.6 MMcf/d ─ Balance: Completing DUC’s in our best areas. Exercising with an impressive 15 psi/day managed pressure decline discipline in regards to stage size and scheduling to deliver wells on time AND avoid production water disposal.  GAUT-4I: Cumulative production for Q2 totaled 1.65 BCF while averaging an 17 psi/day pressure decline  Marcellus: During Q2, the top 3 SWPA Marcellus pads combined averaged a rate of 260 MMcf/d from 140k lateral feet 5 E&P Operations 2016 Planned E&P Activity Overview E&P Activity Summary – 2016 Plan

Expected New Drilled Drilled Implied 2016 Wells Drilled in Uncompleted Completed 2016 TIL's 2017 Completions H2 2016 Inventory Inventory Remaining Inventory 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

Implied inventory exiting 2016 anticipated to consist of 91 Marcellus and Utica Shale Wells, including 10 new wells expected in 2016

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 6 County, Ohio. E&P Operations Bridging to Growth

450

400 75 380-385

350 329 (50) 5 23 300

250 Bcfe

200

150

100

50

0 2015 Total Production 2016 Base decline 2016: Gathering De- 2016: Non-Op (Ex NBL/HES) 2016: Production Adds 2016 Total Production bottlenecking Prod. Adds

2016 production growth primarily driven by wells’ productivity improvements, pipeline infrastructure debottlenecking projects and completion of inventory of drilled but uncompleted wells

Note: Guidance as of 7/26/2016. Production volumes reflect the mid-point of their contribution to the 2016 production guidance ranges. Source: Company filings and estimates. 7 E&P Operations: Capital Expenditures Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth

 Deferring activity, increasing capital efficiency 2016 E&P Capital Budget: improvements and identification of additional de- $190-$205 Million bottlenecking activities

 2016 E&P capital budget of $190-$205 million

- Drilling and Completion: $140-$145 million

o Includes $8-$12 million for coalbed methane (CBM) activity

- Midstream of $34-$39 million (including approximately $22 million associated with CONE Midstream capital contributions)

- Other activities (land, permitting, and business development): $17-$22 million

Base case now assumes drilling 10 new wells in 2016, while reducing capital under low-end of previous E&P capital guidance of $205-$325 million 8 E&P Operations - Benchmarking vs Peers Full-cycle Breakeven Operating Metrics Declined from $3.51 to $1.92 Per Mcfe, a 45% Projected Decline

Hired Tim Dugan to run E&P operations $4.00

$3.50

$3.00 $1.17 $1.11 $2.50

$0.82 Cash OpEx $2.00 (plus G&A) of $0.84 $0.59 $1.28/Mcfe, $0.48 plus PUD-to- $1.50 $0.37 PDP CapEx of $0.17 $0.17 $0.09 $0.26 $0.48/Mcfe, $0.09 equals total full $1.00 cycle cash $1.02 $1.10 $1.04 costs of $0.93 $1.92/Mcfe $0.50

$0.23 $0.38 $0.24 $0.00 $0.16 2013 2014 2015 2016E

SG&A Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE As of YE 2015 A B C D E F G Wtd. Avg. CNX E&P Per Unit Future PUD F&D ($/Mcfe) $0.60 $0.75 $0.91 $0.41 $0.48 $0.69 $1.33 $0.79 $0.48

Exceeded cost reduction target of 15% in 2015 with a 22% reduction from 2014 and projecting an additional 25% reduction from 2015

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 Utica Success Normalized Well-to-Well Productivity Comparison 70 66

62 퐀√k: A measure of the strength of a well that normalizes for: 60 • Lateral length • Stage spacing • Pressure management 50 46 This benchmark metric enables comparison between wells 40 37 more accurately than traditional IP testing

30 29 29 30 27 25 24 23 21 19 20 19 19 19 17 17

15 14 Normalized Asqrt(K), md^1/2*ftAsqrt(K), Normalized 10 10 10 10 9 10 7 6 6

0

* 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

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

* Non-Operated well. 10 Utica Shale: Gaut 4IH Westmoreland County, PA

30,000 Flow Rate MCf/Day Casing Pressure 10,000 9,000 25,000 8,000 7,000 20,000 6,000 15,000 5,000 4,000 10,000 Expected to CUM 8.4 BCF at 3,000 the time it hits line pressure 2,000 5,000 1,000 0 0 9/23/15 1/1/16 4/10/16 7/19/16 10/27/16 2/4/17

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

. 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 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 Dry Utica: Switz 6 Pad Monroe County, OH • Increased type curve from 2.4 – 2.8 Bcf/1,000’ • Evaluating proppant test for use on next pads 50000

6F Gas Rate (Mcf/d) 6F Casing Pressure (psig) 45000 6D Gas Rate (Mcf/d) 6D Casing Pressure (psig) 6H Gas Rate (Mcf/d) 6H Casing Pressure (psig) 40000

35000

30000

25000

20000

15000

10000

5000

0

The Switz 6 pad produced 10.8 Bcf through June 30, 2016 while average flowing casing pressure remains strong at approximately 4,000 psi 12 Utica Shale: Monroe Cty, OH Cost Improvements

Days vs. Depth (Wells in order of Horizontal TD Date) 0 SWITZ6B 5,000 SWITZ6F SWITZ6H 10,000 SWITZ6D Expect Additional 15,000 Realized ~60+% Reduction in Days to Drill ~16% Reduction SWITZ16J SWITZ16D Expected

DMeasured DMeasured epth(ft.) 20,000

25,000 0 20 40 60 80 100 120 Days Switz Drilling Cost/Ft. (Wells in order of Tophole TD) $600 $540 $500 $510 $400 $320 $300 $230 $340 $190

$200 Drilling Drilling ($/ft.) Cost $100 Realized ~55% Reduction in Drilling Costs Expect Additional ~8% Reduction $0 Switz 6B Switz 6D Switz 6H Switz 6F Switz 16J Switz 16D Expected Accelerating rate of change in CONSOL’s efficiency improvements: In Monroe County, OH reduced Dry Utica drilling costs by 55% from the 1st well to the 5th

13 Utica Shale: PA Utica D&C Cost Reduction Plan Waterfall Diagram - PA Dry Utica Drilling and Completion Costs Per Well Assume 7000' lateral on a development 4-well pad ($ in millions) $30.0 $26.2 (8.2) $25.0

(2.2) $20.0 (0.4) (0.8) (1.2) (1.1) $15.0 $12.4

$10.0

$5.0

$0.0 (2) (3) Prior AFE Per Well Drilling Efficiency Drilling Science Cost Casing Design Multi-Well Pad (4) Completion Design Proppant Optimization Development AFE Per PA Dry Utica: Drilling and Completion Cost Reductions Well Waterfall Chart Data(1) ($ in millions) Probability(3) Comments Prior Well Cost/AFE (2) $26.2 Initial - Drilling & Completion Cost on Gaut 4I Cost Reductions: Drilling Efficiency (8.2) High Elimination of non-productive time experienced on Gaut 4I; top down drilling saves mobilization/de-mobilization cost and time Drilling Science Cost (2.2) High Elimination of extensive science work conducted on Gaut 4I: geological evaluation - pilot hole, logging, plugback, etc. Casing Design (0.4) Medium Elimination of additional casing string not required by regulation Multi-Well Pad (4) (0.8) Medium Fixed costs shared across wells (ex. pad, mob./de-mob., containment); efficiencies of scale Completion Design (1.2) Medium Hybrid stage spacing; elimination of drill-out phase; utilization of normal dry gas flowback package Proppant Optimization (1.1) High Modification of proppant type (ceramic to resin); 3rd party chemicals; 25% reduction in gel use Total Reductions(3) (13.8) Development Well AFE(3) $12.4 High degree of confidence towards lowering D&C costs in the PA Dry Utica, similar to successful cost reduction efforts in the Marcellus; plans in place targeting more than a 50% reduction in D&C costs per well Notes: Numbers may not sum due to rounding. (1) Data reflects CONSOL Energy Inc.’s estimated per well Authorization for Expenditure (AFE) for drilling, completion and associated costs in the Utica Shale and Point Pleasant intervals in SWPA. (2) Actual costs may vary from AFEs. 14 (3) Estimated, actuals may vary. Gas Marketing

15 E&P Marketing Q2 2016 Gas Realization and Marketing Highlights

 CONSOL basin exports are projected to increase approximately 73,000 Dth /day for FY 2016 over FY 2015 as TETCO’s U2GC and TEAM OPEN projects were put into service in late 2015, increasing expected realizations by marketing gas to the higher priced Midwest and Gulf Coast markets

 CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped via Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe

─ The deals, the first of which commenced in April, are expected to yield price premiums compared with in-basin pricing and expose a portion of the company’s LPG portfolio to Brent Crude linked pricing

 Q2 2016 natural gas price reconciliation:

2016 2015 Q2 Q1 Q2 NYMEX natural gas ($/MMBtu) $ 1.95 $ 2.09 $ 2.64 Average differential (0.46) (0.36) (0.68) BTU conversion (MMBtu/Mcf)* 0.09 0.10 0.07 Gain on commodity derivative Instruments-cash settlements 0.91 0.98 0.64 Realized gas price per Mcf $ 2.49 $ 2.81 $ 2.67

*Conversion factor 1.06 1.06 1.04

16 Gas Marketing Firm Transportation 1,800

 Targeting FT opportunities that 1,600 access favorable markets at favorable rates 1,400 NEXUS

1,200 ANR  Will supplement direct FT with Columbia firm sales to customers that 1,000 have matching firm capacity 800 East Tennessee

1000S MMBtu/day 1000S 600  Working with marketing partners Dominion to monetize/utilize regionally 400 underutilized capacity 200 TETCO (via firm sales) TETCO  Near term, will optimize and/or 0 Jan 16 Jan 17 Jan 18 Jan 19 release FT to enhance revenues Charts also include transportation under precedent agreements FT Capacities  Stacked pay opportunities will Avg Demand per MMBtu help optimize FT portfolio $0.35 0.29 Pipeline (MMcf/d) YE 2016 YE 2018 $0.30 0.28 0.24 0.24 ANR Pipeline 47 47 $0.25 Columbia (TCO) 215 514 $0.20 Dominion (DTI) 370 342 $0.15 East Tennessee 282 202 $0.10 Nexus - 150 $0.05 TETCO 174 174 $0.00 2016 2017 2018 2019 TETCO (via firm sales) 285 125 1,373 1,554 Low average demand costs of $0.24 to $0.29/Dth reflect a well balanced portfolio between in-basin/out-of-basin markets; minimum relative long-term financial risk

17 Gas Marketing Natural Gas Sales

Midwest TETCO M3 Dominion South

TCO Pool

TETCO M2 East Tennessee

Gas Sales CY 2016 Est. Columbia (TCO) 19% TETCO (M2) 26% TETCO (M3) 16% Dominion (DTI) 14% East Tennessee 12% TETCO ELA TETCO ELA & WLA 8% TETCO WLA Midwest (Chicago) 5% 100%

Current sales portfolio of 100 active customers priced in seven index markets; actively negotiating with major Midwest, Gulf Coast and LNG customers

Source: SNL Financial. 18 Gas Marketing Natural Gas Processing 500  Contracted capacity meets current requirements 450

400 ─ Inlet wet gas volumes to processing plants were ~105 350 MMcf/d above CONSOL’s 300 aggregate minimum

committed volume in Q2 2016 250 MMcf/day  Maintained the flexibility 200

to leave ethane in the 150 residue gas stream 100  Operational and contractual flexibility to potentially convert 50 a portion of currently 0 processed wet gas volumes to Jan 16 Jan 17 Jan 18 Jan 19 be marketed as dry gas MVC

volumes, which would lower Note: We have processing capacity expansion rights of 110,000 Mcf/d processing fees and improve netbacks

Flexible contracts permit us to optimize the timing and volume of our flows

19 Gas Marketing: Hedges Gas Hedges 280 E&P Hedge Program: 260 Physical Sales With Fixed Basis Exposed to NYMEX

240 NYMEX Only Hedges Exposed to Basis . Program and actively 220 NYMEX + Basis(1) monitored hedges 200 180 ─ Program Hedge - protect 160 margins on up to 90% of our 140 Proved Developed 120 Production 100 80 60 ─ Active Hedge Process - Gas Gas Volumes Hedged (Bcf) 40 supplements program 20 hedges up to 80% of our 0 total production including 3Q 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 proved undeveloped production Q3 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 NYMEX + Basis(1) . Since 3/31/16, added Volumes (Bcf) 72.1 263.6 187.1 108.5 20.6 6.9 approximately 120 Bcf of Average Prices ($/Mcf) $2.79 $3.04 $2.61 $2.69 2.46 2.63 NYMEX gas hedges and 170 Bcf of basis hedges through NYMEX Only Hedges Exposed to Basis (Bcf) 2020, further protecting Volumes (Bcf) - - 37.1 41.6 62.6 20.7 downside Average Prices ($/Mcf) - - $3.01 $3.10 $3.03 $3.19

. Approximately 70% of total Physical Sales With Fixed Basis Exposed to NYMEX FY 2016E production Volumes (Bcf) 3.5 4.9 - - - - volumes hedged(2) 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 (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. 20 Gas Marketing: Liquids Realizations Natural Gas Liquids, Oil, and Condensate Q2 2016 Avg. “NGL Barrel” Composition

 Q2 2016 liquids sold: 10.6 Bcfe 2Q16 Est Natural NGL Sales gasoline Comp  Total weighted average price of liquids increased 13% N-Butane ~23% to $15.73 per Bbl in Q2 2016 from $12.78 per Ethane 15% Bbl in Q1 2016 26%

 Liquids comprised approximately 11% of Q2 2016 Propane 41% production volumes, 11% of E&P sales revenue and I-Butane 10% of total Company revenue 5%

Maximum  Added 12.7 million gallons of propane hedges from N-Butane Natural Ethane April of 2016 through March of 2017 at an average 6% gasoline Recovery* price of $0.47 per gallon 5% Potential I-Butane Scenario 3% Average price realization (per Bbl): Propane 22% 2016 2015 Ethane Q2 Q1 Q2 Q1 64% NGLs $12.84 $12.30 $12.48 $20.40 Oil $33.72 $30.84 $46.14 $47.82

Condensate $31.68 $14.64 $31.26 $20.82 * Assumes 85% ethane recovery level

CONE Gathering and Midstream systems provide CONSOL unique flexibility to either (a) blend in ethane to meet specifications, allowing for nearly 100% Marcellus ethane rejection or (b) extract ethane when accretive 21 Financial

22 Financial: Liquidity (Cont’d) Debt and Liquidity Profile CNX CNXC: CNX CNX Equity Value of Ownership in Unit Market Consolidated 100% Attributable Owned LP Affiliated Public MLPs Price(5) Value Capitalization and Liquidity 6/30/2016 6/30/2016 6/30/2016 Units(5) CNX Coal Resources LP (CNXC:NYSE) 12.7 $10.90 $138 Capitalization CONE Midstream Partners LP (CNNX:NYSE) 19.1 $17.00 $325 Cash and Cash Equivalents $98 $9 $89 Total Equity Value of Ownership Interests in Affiliated Public MLPs $463 Revolving Credit Facility Balance 664 198 466 Capital Lease Obligations 38 - 38 Total Total Total Secured Debt $702 $198 $504 Outstanding Available Liquidity of Affiliated MLPs Facility Cash Liquidity of Balance Capacity 8.25% Senior Notes due 2020 $74 - $74 Capacity Affiliates 6.375% Senior Notes due 2021 21 - 21 CNX Coal Resources LP (6) $400 $198 $202 $9 $211 (1) 5.875% Senior Notes due 2022 1,855 - 1,855 CONE Midstream Partners LP (6) $250 $74 $176 $14 $190 (1) 8.0% Senior Notes due 2023 494 - 494 Total Liquidity of Affiliated Baltimore 5.75% Revenue Bonds due 2025 103 - 103 Public MLPs $650 $272 $378 $23 $401 Miscellaneous Debt 8 - 8 Total Debt (2) $3,257 $198 $3,059 Net Debt (3) $3,159 $189 $2,970 Leverage Ratio 6/30/2016 (7) Stockholders’ Equity $4,271 $146 $4,125 LTM Bank EBITDA Attributable to CONSOL Energy Shareholders $884 (7) Total Capitalization $7,528 $344 $7,184 LTM Bank Net Debt / Adj. EBITDA 3.6x (5) Number of MLP units owned by CNX as of 6/30/2016 and unit prices as of market close on 7/19/2016. Liquidity (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 Cash and Cash Equivalents $98 $9 $89 reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $679 (4) million plus gain on sale of assets of $42 million, plus gain related to changes in retiree medical (OPEB) Revolving Credit Facility Capacity 1,427 202 1,225 plan of $211 million, less the $69 million of CNXC EBITDA Attributable to CNX, plus the $39 million of Total Liquidity $1,525 $211 $1,314 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.

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

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 23 availability. CNXC had $198 million outstanding on its revolving credit facility leaving approximately $202 million of availability. Financial: Daily Cash Management Report

Daily Cash Management Report

Cash Excluding CEI Debt Refinancing Notes: $600 •1 CONE MLP IPO

$400 •2 Challenging bond refi 1 5 $200 •3 Challenging CNXC MLP IPO

($MM) • We have stopped the cash burn during - 3 4 brutal pricing environment – cash Cash Balance Balance Cash ($200) stabilization wasn’t due to pricing, it was 2 4 due to arresting spend. ($400) •5 Buchanan sale included in ~$450MM ($600) 9/1/14 12/1/14 3/1/15 6/1/15 9/1/15 12/1/15 3/1/16 jump.

CONSOL remains focused on cash management

24 Financial: Legacy Liabilities Significant Legacy Liability Reductions Over Past 3 Years

$4,500 $400 $4,345 $370 $4,000 $350 Projected $106MM Annual Cash $3,500 Servicing Cost for FY 2016, a $300 $31MM reduction from the year- $3,000 end 2015 run-rate of $137MM $250 $2,500 $1,902 $200 $2,000 $1,694 $1,542 $1,492 $1,374 $150 $1,500 $148 $153 $137 $106 $1,000 $100

$500 $50 Legacy Legacy Liabilities in ($ Millions)

$0 $0 Annual Cash Servicing Cost ($ in Millions) FY 2012 FY 2013 FY 2014 FY 2015 Q2 2016 FY 2016E

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 Flows through P&L in operating costs $39 $20 $22 $20 $19 $18 WC (impact reflected in operating cost 180 85 90 83 82 81 CWP guidance) 184 121 126 123 127 126 OPEB Flows through P&L in Coal Division’s “Other Costs” 3,018 1,022 761 672 661 662 Salary Retirement/Pension Flows through Other Segment in 225 53 119 94 90 84 Asset Retirement Obligations “Miscellaneous Operating Expense” 699 601 576 550 513 403 Total Legacy Liabilities Flows through P&L within DD&A $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

25 Financial: CNX Coal Resources LP (CNXC:NYSE) CNXC: Organizational Structure and CNX Ownership CONSOL Energy Inc. (1) CNXC owns a 20% undivided interest in, and ("CONSOL Energy") operational control over, CONSOL Energy’s Pennsylvania NYSE: CNX mining complex (Bailey, Enlow Fork and Harvey mines) 100% ownership  In July 2015 IPO, sold 10.6 million LP units, or 44.6%, interest raising approximately $158 million in gross proceeds; CNXC also distributed $197 million in cash to limited partner CNX Coal Resources GP CONSOL related to the revolver drawdown interest LLC  CONSOL retained a 53.4% interest in the LP units and 80% undivided owns 100% of the GP, which has a 2% interest ownership interest 2% general partner interest Public  CONSOL Energy retained an 80% undivided interest and IDRs in the Pennsylvania mining complex and owns 100% of CNXC’s general partner, as well as the incentive distribution rights CNX Coal Resources LP limited partner NYSE: CNXC interest CONSOL Energy's Ownership Interest in CNX Coal 20% undivided Resources LP (NYSE: CNXC) ownership interest and (in millions except for per unit amounts) management and control Greenlight Total LP Units held by CONSOL Energy 12.7 rights Capital Unit Price (as of close on 7.19.2016) $10.90 CNXC Units Equity Value to CONSOL Energy $138.0 Pennsylvania mining complex

CNXC is an avenue for CONSOL’s transition to a pure play Appalachian Basin E&P Company

(1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis. 26 Financial: CONE’s Growing Cash Contribution

 CONSOL owns 32.7% of CONE Midstream Partners LP’s (NYSE: CNNX) LP units and 50% of the General Partner CONE Midstream's and Gathering's Pro Rata Net (“GP”), which has a 2% interest in CNNX (and rights to Income Contribution to CNX IDRs) $60 $56 $50  CNNX owns interests in 3 development companies $44 $40  The remaining un-dropped portion of the development $29 companies’ interests are held by CONE Gathering LLC $30 (“CGLLC”), a privately held Joint Venture between $20 $15 CONSOL Energy (NYSE: CNNX) and Noble Energy (NYSE: $10 NBL) $10 $0  CNX’s share of CONE Midstream’s Net Income (CNNX & FY 2012 FY 2013 FY 2014 FY 2015 Last Qtr CGLLC) flows into the E&P segment’s “Equity in Earnings Annualized of Affiliates,” which in CNX’s consolidated financial CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's Net Income statements falls within the “Miscellaneous Other Income” Note: ($ in millions) line item CONE Midstream's and Gathering's Pro Rata  Distributions run straight through CNX’s cash flow statement in the “Return on Equity Investment” line item EBITDA Contribution to CNX $100  CNX has seen increasing benefit from CONE’s EBITDA and $80 $80 $68 cash distributions, on top of which CNNX recently $18 increased its cash distribution 3.7% from 1Q16 $60 $17 $34 $40 $15 $62 $20 $10 $50 CONSOL Energy's Ownership Interest in CONE $0 Midstream Partners LP (NYSE: CNNX) FY 2012 FY 2013 FY 2014 FY 2015 Last Qtr (in millions except for per unit amounts) Annualized

Total LP Units held by CONSOL Energy 19.1 CNX Pro Rata Share of CONE Midstream Partners LP's Cash Distributions (as of close on 7.19.2016) Unit Price $17.00 CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's EBITDA CNNX Units Equity Value to CONSOL Energy $324.7 Note: ($ in millions) Note: For a reconciliation of CONE’s EBITDA please see the CNNX’s form 10Q’s and 10K’s. 27 Source: CONE Midstream Partners LP and CONSOL Energy Inc. Guidance

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

Note: Guidance as of 7/26/2016. (1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation). 28 Guidance

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

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 29 and pension settlement charges. Key Takeaways Plans and Goals Aligned to Drive Increased Valuation

. 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

We will continue to be focused on increasing shareholder value while staying within our core values of safety, compliance, and continuous improvement

30 Appendix

31 Appendix Non-GAAP Reconciliation: EBITDA and Adj. EBITDA

Three Months Ended Twelve Months Ended June 30 2016 2016 2016 2016 2015 E&P Coal Total Total ($ in thousands) Other1 Division Division Company 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. 32 Appendix Non-GAAP Reconciliation: Trailing Twelve Months EBITDA and Adj. EBITDA

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

Source: Company filings. 33 Appendix Free Cash Flow Reconciliation

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

Source: Company filings. 34 Appendix Utica Shale: Growth Runway and Depth of Inventory

Utica Shale Upside Potential

 Total Gross Prospective Utica Acreage ~701,000 - Gross Acres within JV ~158,000 - Acres outside JV – 100% CONSOL ~543,000  Acreage spacing per well (assumed 1,100 ft spacing) ~126

 Gross Producing wells (JV - YE2015) 83

 Gross PDNP and PUD locations (YE2015) 106

 Gross prospective unproved locations ~3,500

 Producing wells as % of PDNPs, PUDs, and prospective locations ~2%

~2% of net Utica acreage developed to date

Notes: PA and WV prospective Utica eastern boundary has yet to be delineated. Acreage is risked 40+% in PA and WV. Acreage in Ohio oil window is excluded. Acreage and locations as of December 31, 2015 unless otherwise noted. 35 Appendix Utica Shale: Sub-Regions Summary

Utica Shale

Ohio Wet Ohio Dry PA/WV Dry Total

Net Acres ~89,000 ~30,000 ~503,000 ~622,000

Approximate Gross 1,050 350 2,400 3,800 Locations(1) Avg EURs/1,000 ft 2.3 2.8 3.0 -- (Bcfe)

Potential resource of ~30 Tcfe

Note: Acreage and locations as of December 31, 2015 unless otherwise noted. 36 Appendix: E&P Division Utica Shale Overview: A Leading Position in the Utica Shale . ~622,000 CONSOL net acres(1) . Over 3,000 gross locations ─ 101 wells online, as of 6/31/2016 ─ 5 wells TIL in Q2 2016 ─ 6,955 ft average TIL laterals in Q2 2016 ─ 4 wells per pad on average ─ 180-acre spacing (assuming 7,000 ft lateral)

. EURs: ─ Ohio Wet: 2.3 Bcfe EUR/1,000 ft of lateral ─ Ohio Dry: 2.8 Bcfe EUR/1,000 ft of lateral ─ PA/WV Dry: 3.0 Bcfe EUR/1,000 ft of lateral

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). Gross locations are as of 6/30/2016. (1) Comprised of ~119,000 net acres in Ohio Utica (~79,000 in the JV and ~40,000 non-JV) and ~306,000 and ~197,000 net prospective acres in PA and WV respectively. 37 Appendix: E&P Division Utica Shale: OH, PA & WV Dry Gas

CHK– Hubbard 3H IP Gas: 11,00 Mcf/d CHK – Brown 10H CNX – Gaut 4IH IP Gas: 9,500 Mcf/d Prod. Net 4.5 Bcf in 250 days (managed) HES – NAC 3H-3* RRC Claysville Sportman’s Club IP Gas: 11,000 Mcf/d IP Gas: 59 MMcf/d HES – Potterfield 1H-17* RRC DMC Properties IP Gas: 17,200 Mcf/d ~18 MMcf/d with Managed Pressure RICE – Bigfoot 9H CVX – Conner 6H IP Gas: 42,000 Mcf/d IP Gas: 25,000 Mcf/d GPOR – Irons 1-4 Permits submitted for 2 add. laterals IP Gas: 30,200 Mcf/d EQT – Shipman CNX – Switz 6D Producing 7,000 ft lateral 44.7 MMcf/d @ 6,835 psig EQT – Pettit 24-hr test rate Producing 5,200 ft lateral GPOR – Stutzman 1-14 EQT – West Run IP Gas: 21,000 Mcf/d Drilling 5,800 ft lateral Eclipse – Fauchs 4H EQT – Scotts Run IP Gas: 21,000 Mcf/d 24 Hour Prod 72.9 MMcf/d Eclipse – Tippens 6H CNX – GH9 IP Gas: 30,000 Mcf/d 61.9 MMcf/d @ 8,312 psig MHR – Stalder 3UH 24-hr test rate IP Gas: 32,500 Mcf/d Noble Energy/CNX – MND6 HGE – Whiteacre 2H 39.1 MMcf/d @ 7,126 psig IP Gas: 9,000 Mcf/d 24-hr test rate EQT – Big 177 Tugg Hill (GST) – Simms Pad Spud Q2 2016 4447' Lateral 5,200 ft. lateral 1st 48 Hour Prod 29.4 MMcf/d MHR – Winland Pad IP 33 MMcf/d @ 9000psi IP Gas: 46,500 Mcf/d CHK – Messenger WTZ 3UH EQT – Big 190 IP Gas: ~30 MMcf/d Producing 6,200 ft lateral. SGY – Pribble 6US Antero – Rymer 4HD IP Gas: 30 MMcf/d 20 MMcf/d 20-day avg. rate

Dry Utica is being aggressively tested in Northern WV and PA, where CONSOL holds 100% working interest in approximately 503,000 net acres Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 38 *Subsequently sold to Ascent Resources LLC. Appendix: Gaut 4IH Dry Utica Shale

CONSOL – GAUT4IH 61.4 MMcf/d 24-hr IP rate @ 7,968 psi; 5,840 ft. lateral

. ~ 5,800’ single lateral; 100% WI to CONSOL . 30 stage completion . 200’ stages with 500k# proppant: 160k# 100 mesh + 200k # 40/80 ceramic + 140k# 30/50 ceramic . Ready supply of water . Production facilities and gathering system with available capacity . Underutilized FT available . Achieved Peak 24-hr rate of 61.4 MMcf/d in July 2015 CONSOL has over 110,000 acres of Utica leasehold in Westmoreland and Indiana Counties, PA

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 39 Appendix: GH9 Dry Utica Shale

Range Resources - Claysville Sportsman’s Club #1 IP Gas – 59.0 MMcf/d

EQT – Pettit Spud in Aug. 2015 13,400 ft. TVD 4,000-4,500 ft. lateral

. 100% WI and 96% NRI to CONSOL EQT – Scotts Run 24 hr IP – 72.9 MMcf/d. . TVD: 13,400’ 3,221’ Treated interval.

. Frac’d in Q4 2015 CNX’s GH9 Utica well is less than 4 miles away from . 24-hour IP of 61.9 MMcf/d at 8,312 psi EQT’s Scotts Run well . Drilled lateral length of 6,141 ft. CONSOL GH9 . Situated in existing Marcellus field 24 hr IP – 61.9 MMcf/d @ 8,312 psig . Ready supply of water 6,141 ft. lateral . Production facilities and gathering system with available capacity

CONSOL has ~84,000 net acres prospective for the Utica in the SWPA operating area, including ~58,000 net acres in Greene and Washington Counties, PA

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 40 Appendix: Ohio Dry Utica Shale CNX Activity and Recent IP Rates In-and-Around Monroe County, OH

CVX Conner well (Utica): GPOR Irons 1-4H (Utica): 25.0 MMcf/d – Avg 24-hr rate 30.3 MMcf/d – Avg 24-hr rate

NBL / CNX MND 6H (Utica): 1 Utica Well 39.1 MMcf/d 24-hr IP @7,126 psi CNX SWITZ 6 Pad (Utica) : 9,345 ft. lateral 4 Utica Wells & 1 Marcellus CNX – Switz 6D: 24-hr test rate 44.7 MMcf/d @ 6,835 psi 9,761 ft. lateral

MHR 3-UH (Utica): ECR Shroyer 2-well pad (Utica): 32.5 MMcf/d – Avg 24-hr rate 7,819 – Avg later length MHR 2-MH (Marcellus): 42.5 MMcf/d – Combined Rate 3.7 MMcf/d of gas and 312 Bbls of condensate per day, peak test rates

GST Simms: 4,447' Lateral 1st 48 Hour Prod 29.4mm IP 33 MMcf/d @ 9000psi

MHR Stewart Winland Pad: 46.5 MMcf/d – Avg 24-hr rate

Recent nearby results have surrounded our contiguous Monroe County leasehold, which contains ~2.1 Tcfe of resource

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 41 Appendix: Switz 6 Dry Utica Shale

CONSOL – SWITZ 6 Pad (Utica): 4 Utica wells & 1 Marcellus well

CNX – Switz 6D: 24-hr test rate 44.7 MMcf/d @ 6,835 psig

. 4 Utica Wells and 1 Marcellus Well . Avg. Utica Lateral Length = 8,821’ . Longest Utica Lateral = 10,122’ . 100% WI to CONSOL . Tested 3 proppant types . 350K pounds/stage @ 200’ spacing . Multi-Market availability . Offset pad fully permitted with 5 wells

CONSOL has over 13,000 contiguous acres of Utica leasehold in Monroe County, OH

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). 42 Appendix: Marcellus Shale Overview

. ~436,000 CONSOL net acres ─ ~88% NRI ─ ~91% HBP

. 23.9 Tcfe 3P . Over 8,900 gross potential wells(1)

. Marcellus production grew at a 71% CAGR from 2013 to 2015

Producing Pads Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2015. 43 Appendix Marcellus Shale: Growth Runway and Depth of Inventory

Marcellus Shale Upside Potential

 Total Gross Prospective Marcellus Acreage ~785,000 - Gross Acres within JV ~699,000 - Acres outside JV – 100% CONSOL ~86,000  Acreage per well (assumed 750 ft spacing) ~86

 Gross Producing wells (JV - YE2015) 448

 Gross PDNP and PUD locations (YE2015) 146

 Gross prospective unproved locations ~8,000

 Producing wells as % of PDNPs, PUDs, and prospective locations 5%

~563 MMcfe/d net being produced from ~5% of net Marcellus acreage

Note: Acreage and locations as of December 31, 2015 unless otherwise noted. 44 Appendix Marcellus Shale: Sub-Regions Summary

Marcellus Shale

North South SWPA CPA WV Ohio(1) Total Wet Wet

Net Acres ~44,000 ~108,000 ~111,000 ~14,000 ~52,000 ~107,000 ~436,000

Approximate Gross 900 2,200 2,250 150 1,000 2,200 ~8,700 Locations(2) Avg EURs/1,000 ft 2.1 1.6 1.8 -- 1.8 2.1 -- (Bcfe)

Marcellus Shale is one of the main growth drivers of the E&P Division

Note: Acreage and locations as of December 31, 2015 unless otherwise noted. (1) Non-JV acreage is located in Monroe County, OH. 45 (2) Based on 5,000 ft laterals with 86-acre spacing. Appendix Marcellus Shale: Southwest PA Overview . ~44,000 CONSOL net

acres NV56 Pad (1) 6 Wells . Over 900 gross locations 8,753’ Avg Lateral Length per well 9,230 Mcfe Avg 30-day IP per well ─ 222 wells online, as of NV57 Pad NV36 Pad 6/31/2016 8 Wells 7 Wells 8,914’ Avg Lateral Length per well 5,021’ Avg Lateral Length per well ─ 16 wells TIL in Q2 2016 10,435 Mcfe Avg 30-day IP per well 6,159 Mcfe Avg 30-day IP per well ─ 8 wells per pad on average in 2016 . 2.1 Bcfe EUR/1,000 ft of lateral . 750 ft inter-lateral spacing

MOR10 Pad 6 Wells 4,771’ Avg Lateral Length per well 6,341 Mcfe Avg 30-day IP per well

Producing Pads Competitor Pads

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 6/30/2015. 46 Appendix Marcellus Shale: North Wet Gas Overview . ~52,000 CONSOL net acres . Over 1,000 gross locations(1) ─ 144 wells online as of 6/31/2016 ─ 0 wells TIL in Q2 2016 ─ 8 wells per pad on average . 1.8 Bcfe EUR/1,000 ft of lateral . 750 ft inter-lateral spacing Condensate yield: 5 . SHL13 Pad Bbls/MMcf 7 Wells 5,299’ Avg Lateral Length per well . NGLs yield: 49 Bbls/MMcf 4,039 Mcfe Avg 30-day IP per well WFN6 Pad 8 Wells SHL23 Pad 6,451’ Avg Lateral Length per well 5 Wells 8.5 MMcf/d Avg 24-hour IP per well 7,245’ Avg Lateral Length per well 6,800 MMcf/d 60-day IP per well 6,620 Mcfe Avg 30-day IP per well

WFN3 Pad 4 Wells 7,380’ Avg Lateral Length per well 7,079 Mcfe Avg 30-day IP per well 4,800 MMcf/d 60-day IP per well Producing Pads Competitor Pads

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 6/30/2015. 47 Appendix Marcellus Shale: South Wet Gas Overview . ~107,000 CONSOL net SHR1 Pad 6 Wells acres ~8,741’ Avg Lateral Length per well WEESE (Triad Hunter) PENS1 Pad 10,143 Mcfe Avg 30-day IP per well 3 Wells . Over 2,200 gross 9 Wells 3,711’ Avg Lateral Length per well (1) ~6,824’ Avg Lateral Length per well 530 MMcf/well – 1st 6-Month Cum locations 2473 Bbl/well – 1st 6-Month Cum ─ 31 wells online, as of 6/31/2016 DAVIES (EQT) 7 Wells ─ 6 wells per pad on 3,756’ Avg Lateral Length per well 487 MMcf/well – 1st 6-Month Cum average 1562 Bbl/well – 1st 6-Month Cum PENS2 Pad . 2.1 Bcfe EUR/1,000 ft of 12 Wells lateral Currently under flowback . 750 ft inter-lateral spacing . Condensate yield: 10 Bbls/MMcf . NGLs yield: 51 Bbls/MMcf HARPER (EQT) 3 Wells OXF1 Pad 3,684’ Avg Lateral Length per well 6 Wells 448 MMcf/well – 1st 6-Month Cum ~6,353 Avg Lateral Length per well 472 Bbl/well – 1st 6-Month Cum 5,517 Mcfe Avg 30-day IP per well

Producing Pads Competitor Pads DTI Storage Fields

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 6/30/2016. 48 Appendix Marcellus Shale: Northern WV Dry Overview . ~111,000 CONSOL net acres ANDERSON (PDC Mountaineer) . Over 2,250 gross 3 Wells PHL10 Pad locations(1) 4,859’ Avg Lateral Length per well 6 Wells 595 MMcf/well – 1st 6-Month Cum 4,636’ Avg Lateral Length per well ─ 49 wells online, as of 3,148 Mcfe Avg 30-day IP per well 6/31/2016 PHL13 Pad ─ 0 wells TIL in Q2 2016 6 Wells AUD7 Pad 7,949’ Avg Lateral Length per well . 1.8 Bcfe EUR/1,000 ft of 1 Well Delineation 6,869 Mcfe Avg 30-day IP per well lateral 9,745’ Avg Lateral Length per well 923 MMcf/well – 1st 6-month Cum 7,120 Mcfe Avg 30-day IP per well . 750 ft inter-lateral spacing

AUD3 Pad PHL4 Pad 1 Well Delineation 3 Wells 8,691’ Avg Lateral Length per well 6,533’ Avg Lateral Length per well 6,099 Mcfe Avg 30-day IP per well 5,212 Mcfe Avg 30-day IP per well 917 MMcf/well – 1st 6-month Cum 720 MMcf/well – 1st 6-month Cum

CENT3 Pad 1 Well Delineation 7,470’ Avg Lateral Length per well 4,973’ Mcfe Avg 30-day IP per well 635 MMcf/well – 1st 6-month Cum

Producing Pads Competitor Pads DTI Storage Fields

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 6/30/2016. 49 Appendix Marcellus Shale: Central PA Overview . ~108,000 CONSOL net acres CRAWFORD 5 Pad 2 Wells . Over 2,200 gross 7,305’ Avg Lateral Length per well locations(1) 13,586 Mcfe Avg 24-hr IP per well 624 Mmcfe/well – 60 day Cum ─ 56 wells online, as of 6/31/2016 MARCHAND 3I Well SHAW Pad 6,418’ Lateral Length 735 Mmcfe – 150 day Cum ─ 0 wells TIL in Q2 2016 3 Wells 3,965’ Avg Lateral Length per well 7,817 Mcfe Avg 24-hr IP per well ─ 5 wells per pad on 523 MMcf/well – 1st-4-month Cum GAUT4 Pad average 4 Wells 7,941’ Avg Lateral Length per well . 1.6 Bcfe EUR/1,000 ft of 6,619 Mcfe Avg 30-day IP per well lateral 759 MMcf/well – 1st 6-month Cum COOK (Atlas/Chevron) . 750 ft inter-lateral spacing 2 Wells KUHNS3 Pad 3,352’ Avg Lateral Length per well 5 Wells 400 MMcf/well – 1st 6-Month Cum 7,237’ Avg Lateral Length per well 7,259 Mcfe Avg 30-day IP per well 937 MMcf/well – 1st 6-month Cum

MMS Pad 5 Wells 8,040’ Avg Lateral Length per well 6,677 Mcfe Avg 30-day IP per well 636 MMcf/well – 1st-4 month Cum

GREENAWALT (Chevron Appalachia) SMITH (Atlas/Chevron) 3 Wells 2 Wells 3,725’ Avg Lateral Length per well 2,680’ Avg Lateral Length per well 800 MMcf/well – 1st 6-Month Cum 722 MMcf/well – 1st 6-Month Cum Producing Pads Competitor Pads

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). (1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 6/30/2016. 50 Appendix Stacked Pay Potential: Appalachian Shale Acreage

P a Formation y Name Wet Dry Total Net Acres Net Acres Net Acres

Rhinestreet Shale Upper

Cashaqua Shale Devonian 190,000 155,000 345,000

Middlesex Shale

West River Shale Burkett Shale Tully Limestone

Hamilton Shale

Marcellus Marcellus 173,000 263,000 436,000 Shale Onondaga Limestone

Utica Shale Utica(1) 89,000 533,000 622,000

Point Pleasant Shale

Trenton 0 GR 400 LITHOLOGY Limestone Total 452,000 951,000 1,403,000

Stacked pays provide a large inventory and rich opportunity set

(1) Dry Utica includes 503,000 net prospective acres in Pennsylvania and West Virginia. As of December 31, 2015. 51