Barclays CEO Energy & Power Conference September 9-10, 2015 - - PowerPoint PPT Presentation

Barclays CEO Energy & Power Conference

September 9-10, 2015

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 and coal; 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 gas assets; 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 complete the anticipated drop downs of assets into CNX Coal Resources LP and CONE Midstream LP on acceptable terms; we may be unable to incur indebtedness

• n reasonable terms; 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, 2014 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

• therwise, 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.

Key Takeaways

3

• CONSOL Energy’s E&P Division has demonstrated that it can stand on its own as a premier Appalachian Basin

producer:

 Gas production has grown significantly  Capital intensity and costs are down dramatically  Dry Utica has opened up a new opportunity set

• Our base plan is achievable and will help us to more easily reach our free cash flow targets due to conservative

plan assumptions:

 NYMEX strip gas pricing with conservative basis differentials  Conservative thermal and met pricing  Modest levels of asset sales assumed between $75-$125 million

• CONSOL Energy has approximately $2 billion of assets available for sale and the proceeds of these sales will be

used to further reduce debt

 Not including MLP drop-downs or strategic transactions

CONSOL Energy’s base plan, coupled with additional asset sales, will result in significant flexibility, including the ability, if appropriate, to separate its coal and E&P businesses by means of a spin transaction

Agenda

4

• E&P division

 Increasing 2015E gas production to 320-330 Bcfe, up from 300-310 Bcfe; 20% gas production growth expected in 2016E  Waterfall chart that details bridge to 2015 and 2016 production growth forecast  Marcellus and Utica overview  Emerging dry gas Utica play’s “game changing” potential

• Gas marketing strategy

 Diversity of sales-points and end-markets  Discipline when signing up for FT, weighing pricing uplift vs. burdening company with off-balance sheet liability/commitment  Hedging update – locked in additional NYMEX and basis hedges for 2H15 and 2016 to be about 2/3 hedged on gas

• Coal division

 Premier US coal assets, lowest cost per Btu, highest margin, well capitalized  Positive free cash flow generation with stable production even in current low price environment  Minimized volume and price risk with aggressive contracting program; now entering prime contracting season

• Financial

 Focused on positive free cash flow generation through production growth, operating cost reductions and capex efficiency  Active asset monetization in full gear to supplement free cash flow to go on offense  Providing streamlined 2015 and 2016 operational and financial guidance to model both sides of CONSOL’s business

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Company Overview

Transformative Journey



Eleven years ago – traditional coal producer, the largest underground producer in the world



Ten years ago – created CNX Gas



Five years ago – acquired Dominion Resources’ Appalachian E&P business and became a coal company with a growing natural gas business



Late 2013 – transaction with Murray Energy Corp. that transitioned 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)



December 10, 2014 – Announced intention to pursue the Initial Public Offerings of a Thermal Coal MLP and Metallurgical Coal Subsidiary, in addition to a $250 Million stock repurchase program



June 30, 2015 – IPO of CNX Coal Resources LP (NYSE: CNXC)

We are a growing E&P company focused on developing the Appalachian shale with the benefit of fully capitalized, premier coal assets to help fund E&P growth

6

E&P Division

128 154 156 172 236 320-330 +20% 50 100 150 200 250 300 350 400 450 50 100 150 200 250 300 350 400 450 2010 2011 2012 2013 2014 2015E 2016E Bcfe Marcellus CBM Utica Other

E&P Division

7

Increasing 2015E production guidance by 20 – 30 Bcfe to 320 – 330 Bcfe; +20% year-over-year growth target for 2016E

E&P Production Volumes

Gas Division Production Growth

Source: Company filings. Note: Acquired ~23 Bcfe of Conventional gas production from Dominion E&P in 2010. Divested ~11 Bcfe in 2011.

Production by Area 2015E 2016E Marcellus 51% 50% CBM 23% 18% Utica (Wet & Dry) 19% 26% Other 7% 6%

E&P Division

8

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

Bridging to Growth

Note: Production volumes reflect the mid-point of their contribution to the 2015 and 2016 production guidance ranges. Source: Company filings and estimates. 236

• 38

8 15 104 325

• 50

14 15 86 390 50 100 150 200 250 300 350 400 450

2014 Total Production 2015 Base decline 2015: Gathering De-bottlenecking 2015: Non-Op (Ex NBL/HES)

• Prod. Adds

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

• Prod. Adds

2016: Production Adds 2016 Total Production

Bcfe

Average $2.06 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 CNX $/Mcfe Average $2.14 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 CNX $/Mcfe 9

F&D/Mcfe: Continued Operational Efficiency Improvements

E&P Division

Rate of improvement has accelerated over the last 3 years; CONSOL’s drilling efficiency now ranks among the best in its peer group

Source: Scotia Howard Weil 2014 F&D Cost Study. Note: Drill-bit finding and development (F&D) costs including revisions, defined as total drilling and completion costs divided by total reserve additions and revisions.

2010-2014 Drill-bit F&D Cost: 5-Year Average vs. E&P Peers 2012-2014 Drill-bit F&D Cost: 3-Year Average vs. E&P Peers

10

• ~441,000 CONSOL net

acres

─ ~88% NRI ─ ~91% HBP ─ ~85,000 net fee acres

• 23.9 Tcfe 3P
• Over 8,900 gross potential

wells(1)

• 2015 YTD drilled wells: 60
• Marcellus production grew

93% in 2014 over 2013

• Liquids grew from 2% of

total production in 2013 to 8% in 2014

Producing Pads

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014). (1) Based on 5,000 ft laterals with 86-acre spacing.

Marcellus Shale: Overview

E&P Division

11 Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014). (1) Comprised of ~118,000 net acres in Ohio Utica (~77,000 in the JV and ~41,000 non-JV) and ~302,000 and ~194,000 net prospective acres in PA and WV respectively.

Utica Shale: Overview

E&P Division

• ~614,000 CONSOL net

acres(1)

─ Includes ~70,000 net fee

acres in Ohio Utica

• Over 3,000 gross locations

─ 66 wells online, as of

6/30/2015

─ 9 wells TIL in Q2 2015 ─ 6,983 ft average TIL

laterals in Q2 2015

─ 4 wells per pad on

average in 2015

─ 120-acre spacing

(assuming 7,000 ft lateral)

• EURs:

─ Ohio Wet: 2.1 Bcfe

EUR/1,000 ft of lateral

─ Ohio Dry: 2.2 Bcfe

EUR/1,000 ft of lateral

─ PA/WV Dry: 2.4 Bcfe

EUR/1,000 ft of lateral

• 2016E Utica shale

production 480% above 2014 volumes

12

E&P Division

Utica Shale: PA/WV Dry Gas

REXX – Cheeseman 1 IP Gas: 9,200 Mcf/d IP Oil: 0 Bbl/d CHK – Thompson 3H IP Gas: 6,400 Mcf/d IP Oil: 0 Bbl/d RRC– Zahn #1 IP Gas: ~4,500 Mcf/d IP Oil: 0 Bbl/d CHK – Brown 10H IP Gas: 9,500 Mcf/d IP Oil: 0 Bbl/d HES – NAC 3H-3* IP Gas: 11,000 Mcf/d IP Oil: 0 Bbl/d CHK– Hubbard 3H IP Gas: 11,00 Mcf/d IP Oil: 0 Bbl/d RRC Claysville Sportmans Club IP Gas: 59 MMcf/d IP Oil: 0 Bbl/d EQT – Hopkins #590030 Well completed; no reported production CVX – Conner 6H IP Gas: 25,000 Mcf/d IP Oil: 0 Bbl/d Permits submitted for 2 additional laterals HES – Poterfield 1H-17* IP Gas: 17,200 Mcf/d IP Oil: 0 Bbl/d RICE – Bigfoot 9H IP Gas: 42,000 Mcf/d IP Oil: 0Bbd GPOR – Stutzman 1-14 IP Gas: 21,000 Mcf/d IP Oil: 0 Bbd GPOR – Irons 1-4 IP Gas: 30,200 Mcf/d IP Oil: 0 Bbd CNX – Switz 6 4 Utica Wells & 1 Marcellus Frac complete, waiting on pipe MHR – Stalder 3UH IP Gas: 32,500 Mcf/d IP Oil: 0 Bbl/d MHR – Winland Pad IP Gas: 46,500 Mcf/d HGE – Whiteacre 2H IP Gas: 9,000 Mcf/d IP Oil: 0 Bbl/d Eclipse – Tippens 6H IP Gas: 30,000 Mcf/d IP Oil: 0 Bbl/d Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014). *Subsequently sold to Ascent Resources LLC. GST – Simms Pad 4447' Lateral 1st 48 Hour Prod 29.4 MMcf/d IP 33 MMcf/d @ 9000psi CHK – Messenger WTZ 3UH IP Gas: ~30 MMcf/d SGY – Pribble 6US IP Gas: 30 MMcf/d IP Oil: 0 Bbl/d

Dry Utica is being aggressively tested in Northern WV and PA, where CONSOL holds 100% WI in approximately 496,000 net acres

Noble Energy/CNX – MND6 9,000’ lateral Frac complete, waiting on pipeline / production set-up” CNX – GH9 Currently drilling 1 Utica Well <4 Miles from EQT’s Scotts Run CNX – Gaut 4IH 61.4 MMcf/d @ 7,968 psig 24-hr test rate EQT – Scotts Run 24 Hour Prod 72.9 MMcf/d

CONSOL has over 110,000 acres of Utica leasehold in Westmoreland and Indiana Counties, PA

13 CONSOL – GAUT4IH 61.4 MMcf/d 24-hr test rate

• ~ 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
• TIL planned 3Q 2015

Utica Shale: Gaut 4IH Westmoreland County, PA

Gaut 4IH Utica well’s flow and pressure data showing positive indications for production volumes and EUR

14

Utica Shale: Gaut 4IH Westmoreland County, PA

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 10 20 30 40 50 60 70 80 psig mcfd Hours Gas Rate, mcfd Avg Gas Rate for 24 Hr Test Period, mcfd Casing Pressure, psig Avg Flowing Casing Pressure for 24 Hr Test Period, mcfd

61.4 MMcf/d 24 hour flowtest to sales at an average flowing casing pressure of 7,968 psig

Strong pressure and flow data bode well for production and

• EUR. With the well temporarily

shut-in for the installation of permanent production equipment, surface casing pressure has increased to nearly 10,000 psig

15 Range Resources - Claysville Sportsman’s Club #1 IP Gas – 59.0 MMcf/d CONSOL GH9 Drilling underway

• 100% WI to CONSOL
• Expected TVD: 13,500’
• Currently drilling 8.5” curve section

at 13,000’+

• Planned lateral length of 6,800’
• ~30 stage frac scheduled for Q3 2015
• Situated in existing Marcellus field
• Ready supply of water
• Production facilities and gathering

system with available capacity

• TIL planned by YE 2015

EQT – Scotts Run 24 hr IP – 72.9 MMcf/d

CNX’s GH9 Utica well is less than 4 miles away from EQT’s Scotts Run well

Utica Shale: GH 9 Greene County, PA

CONSOL has ~85,000 net acres prospective for the Utica in the SWPA operating area, including ~58,000 net acres in Greene and Washington counties, PA

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Gas Marketing



Targeting pipeline projects that access favorable markets at favorable rates



Will supplement direct FT with firm sales to customers that have matching firm capacity



Near term, will optimize and/or release FT to enhance revenues



Will acquire third-party released firm capacity if needed



Plan to selectively acquire firm capacity while minimizing long- term transportation costs and long-term financial obligations



Stacked pay opportunities will help optimize FT portfolio

17

Gas Marketing

Firm Transportation

Firm transportation capacity to support an 18% production CAGR through 2018; low average demand costs of $0.25/Dth reflects a well balanced portfolio for in- basin/out-of-basin markets; minimum relative long-term balance sheet risk

* Charts also include transportation under precedent agreements TETCO Dominion (DTI) East Tennesse Columbia (TCO) ANR NEXUS 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 1/1/2015 1/1/2016 1/1/2017 1/1/2018 MMBtu/day

CNX's Firm Transportation and Sales*

TETCO Dominion (DTI) East Tennesse Columbia (TCO) ANR NEXUS $0.25 $0.25 $0.25 $0.28 $0.11 $0.11 $0.11 $0.11 $- $0.10 $0.20 $0.30 $0.40 $0.50 2015 2016 2017 2018 $/Dth

CNX's Firm Transportation Costs*

• Avg. Demand
• Avg. Variable

$0.36 $0.36 $0.36 $0.39

FT Capacities Pipeline (MMcf/d) YE 2015 YE 2018 ANR Pipeline 47 47 Columbia (TCO) 204 304 Dominion (DTI) 245 342 East Tennessee 282 282 Nexus

• 150

TETCO 127 127 TETCO (via firm sales) 285 225 1,190 1,477

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Gas Marketing

TETCO M2 TETCO M3 TCO Pool Dominion South East Tennessee TETCO ELA Midwest

Gas Sales CY 2015 Est. CY 2016 Est. Columbia (TCO) 24% 19% TETCO (M2) 19% 25% TETCO (M3) 20% 15% Dominion (DTI) 19% 18% East Tennessee 13% 10% TETCO ELA & WLA 4% 8% Midwest (Chicago) 1% 5% 100% 100%

Natural Gas Sales

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.

TETCO WLA

Short-term uplift in realizations can come at the expense of over-committing to expensive FT incurring long term off-balance sheet liabilities

19 Notes: Peers include RRC, RICE, COG, AR, SWN, GPOR, CHK EQT. Commitments are as of most recently provided company financial statements.

Total Off Balance Sheet Firm Transportation, Gathering and Processing Commitments

Gas Marketing: Firm Transport–Asset or Liability?

$1.1 $1.8 $2.0 $3.6 $4.6 $4.8 $5.5 $16.0 $17.5 Average: $6.3 17% 46% 17% 38% 31% 118% 54% 88% 147% 0% 20% 40% 60% 80% 100% 120% 140% 160% $- $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $16.0 $18.0 $20.0 CNX A B C D E F G H FT Commitments as % of EV $ Billions

Hedged an additional 34 Bcf in 2H15 and an additional 114 Bcf in FY 2016, with approximately 65% of 2H 2015 production hedged(2) and nearly 60% of FY 2016 at prices 16% above NYMEX futures(3)

20 (1) Includes the impact of basis-only hedges. (2) At the midpoint of production guidance. (3) As of 8/31/2015.

Gas Hedges

E&P Hedge Program:



Program and actively monitored hedges

• Program Hedge - protect margins on up to 90% of our Proved Developed Production
• Active Hedge Process - Supplements program hedges up to 80% of our total production including proved

undeveloped production

Gas Marketing: Hedges

$2.80 $3.00 $3.20 $3.40 $3.60 $3.80 $4.00 $4.20 25 50 75 100 125 150 175 200 225 250 FY 2015 Prior FY 2015 NEW FY 2016 Prior FY 2016 NEW Average Price Gas Volumes (Bcf) NYMEX Hedges(1) NYMEX + TCO NYMEX + TETCO Weighted Average Price ($/Mcf)

3Q15 4Q15 FY 2016 Volumes (Bcf) NYMEX Hedges(1) 35.3 50.9 149.0 NYMEX + TCO 12.5 12.5 76.3 NYMEX + TETCO 0.9 0.9

• Total

48.7 64.3 225.3 Average Prices ($/Mcf) NYMEX Hedges(1) 3.52 $ 3.32 $ 3.42 $ NYMEX + TCO 3.84 3.84 3.69 NYMEX + TETCO 3.93 3.93

• Weighted Average

3.61 $ 3.43 $ 3.51 $

21

Coal Division

22

Pennsylvania (“PA”) Operations Virginia (“VA”) Operations Other Type of Coal Primarily Thermal Primarily Met Primarily Thermal Method 5 Longwalls and Continuous Mining Machines 1 Longwall System and Continuous Mining Machines Stripping Shovels and Front-end Loaders Seam Pittsburgh 8 Pocahontas 3 Upper Dorothy (Coalburg), Kittanning, Freeport, Coalburg Rider, Stockton and 5 Block Reserves(1) 785 MT 92 MT 115 MT Mine Life 25+ years 20+ years 20+ years Production Capacity 28 MMT 5.2 MMT 4 MMT

High Quality, Low Cost Assets with Long Mine Life

Coal Division

2

$36.85 $40.15 $52.26 $19-32 Margin $18-152 Margin $8-22 Margin $64 5-yr Avg Price $120 5-yr Avg Price $68 5-yr Avg Price Bailey Buchanan Miller Creek Cash Margin per ton ($) Q2 2015 Cash Cost per Ton ($) (1) Based on end of year 2014 reserve estimate. (2) Cash cost per ton calculated as total cost per ton less DD&A per ton.

79% 14% 7%

2015 Sales Tons by Segment

PA Ops VA Ops Other

23

Coal Division: Q3 and FY 2015 and 2016 Marketing Update and Forecasts

Coal Division

2015 Coal Sales Facts and Goals



Contracted tons for 2015: 96%

• Priced: 94%



Approximately 82% of the PA Ops tons are expected to be sold domestically



Approximately 78% of the VA Ops tons are expected to be sold overseas



100% of the Other tons are expected to be sold domestically

Coal Sales Guidance(1) Q3 2015E Q3 2014 2015E 2014 2016E

PA Ops 5.4-5.6 6.2 22.5-23.5 26.1 25.0-27.0 VA Ops 0.8-1.0 1.0 3.9-4.2 4.1 3.7-4.2 Other 0.4-0.5 0.6 2.0-2.2 2.2 1.9-2.2

Total 6.6-7.1 7.8 28.4-29.9 32.4 30.6-33.4 80% 13% 7%

Q3 2015 Sales Tons by Segment

PA Ops VA Ops Other

Notes: Coal sales guidance in gross tons. Following the recent CNX Coal Resources LP (CNXC) IPO, CONSOL expects to modify its reporting and guidance process for the PA Operations, with CNXC taking a primary role as the operator of these assets. (1) Tons in millions.

Source: EIA 923, MSHA; Number of longwalls indicated in parentheses.

Not All NAPP Longwalls Are Created Equal

Coal Division

24

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5 10 15 20 25 30

CNXC Assets (5) Marion County (1) Monongalia County (1) Emerald (1) Federal (1) Harrison County (1) Mountain View (1) Leer (1) Marshall County (2) Cumberland (1) Century (1) Ohio County (1) Tunnel Ridge (1) Powhatan (1) Sulfur (% as received) Production (million tons) 2014 Production - CNXC Assets 2014 Production - Other Longwalls 2014 Sulfur

PA Mining Complex is uniquely positioned among NAPP longwall producers to provide sustained supply of high-quality coal to rail-served power plants in the eastern U.S.

Closed in 2015

Serve River Markets Primarily Met Coal Producer Mine Mouth Operations Near End of Reserve Life Higher Sulfur

20 40 60 80 100 120 140

Million Tons

Minor MATS Impact – Limited Sales Loss, Potential Remaining Customer Gain

Coal Division

Surviving 2014 CNX Customers (after 2015-2019 retirements)

2014 coal burn Demonstrated capability (2008)

MATS compliance deadlines Only 1.8 million tons of 2014 CONSOL sales affected by retirements in 2015-2016. In 2014, 50 million tons of coal were consumed by units east of the Mississippi that have announced plans to retire in 2015-2019. Coal and gas will compete to replace this demand;

• ur surviving customers have the potential to backfill more than half.

* Includes actual and announced retirements, as well as units converted to natural gas, biomass, or another non-coal fuel

2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 2011 2012 2013 2014 2015 2016 2017 2018 2019

Retired Capacity (MW)

Actual and Announced U.S. Coal Plant Retirements

25

26

Financial

27

Financial: Focused on Free Cash Flow



CNXC IPO



Strong liquidity position



Growing revenue and income

• CONE Midstream cash flows and EBITDA growing
• E&P production volume growth
• Steady coal production with lower cost base



Reductions to operating and overhead costs



Reductions in capital intensity

• Service cost deflation: beating expectations; improves capital spending efficiency
• Leverage in-place infrastructure
• Continue to high-grade development plan (Dry Gas Utica potential)



Reduction in legacy liabilities



Asset monetizations

On track for positive free cash flow growth for the next 18 months

28

CNXC: Organizational Structure

Financial: CNX Coal Resources LP (CNXC) IPO



Sold 10.6 million LP units, or 44.6%, raising approximately $158 million in gross proceeds; CNXC also distributed $197 million in cash to CONSOL related to the revolver drawdown



CONSOL retained a 53.4% interest in the LP units and owns 100% of the GP, which has a 2% interest



CNXC owns a 20% undivided interest(1) in, and

• perational control over, CONSOL Energy’s

Pennsylvania mining complex



CONSOL Energy retained an 80% undivided interest in the Pennsylvania mining complex and

• wns 100% of CNXC’s general partner, as well as

the incentive distribution rights



CONSOL Energy granted CNXC a right of first offer to acquire the remaining 80% undivided interest in the PA complex



CNXC has ROFOs on (1) Buchanan Mine, (2) Cardinal States Gathering System, and (3) Baltimore Marine Terminal CNXC: 20% Undivided interest in Pennsylvania mining complex (Bailey, Enlow Fork and Harvey mines)

(1) Unless otherwise specified, all figures relating to reserves and production of the Pennsylvania mining complex in this presentation are on a 100% basis.

CONSOL strategically aligned with CNXC, with future drop downs supporting CNXC’s growth and CONSOL’s transition to a pure play Appalachian Shale Company

80% undivided

• wnership interest

CNX Coal Resources LP NYSE: CNXC CNX Coal Resources GP LLC Pennsylvania mining complex Public 100% ownership interest limited partner interest 2% general partner interest and IDRs 20% undivided

• wnership interest and

management and control rights limited partner interest CONSOL Energy Inc. ("CONSOL Energy") NYSE: CNX Greenlight Capital

29

CNXC Roadmap to Growing Value and Unitholder Returns

Financial: CNX Coal Resources LP (CNXC)

Optimize Cost Structure Increase Volumes with Solid Cash Margins Pursue Opportunistic Acquisitions Stable Cash Flows Reduced Cost of Capital Distribution Growth Flexible Drop-downs Coal Contracting for 2016-19 Broaden Institutional Appeal

 CONSOL owns 32.1% of CONE Midstream Partners’ (CNNX)

LP units and 50% of the General Partner (GP), which has a 2% interest in CNNX (and rights to IDRs)

 CNNX owns interests in 3 development companies

(ownership structure detailed in Appendix)

 The remaining un-dropped portion of the development

companies’ interests, are held by CONE Gathering LLC, a private Joint Venture between CONSOL and Noble Energy

 CONSOL’s share of CONE Midstream’s Net Income flows

through “Equity in earnings of Affiliates,” which falls within the “Miscellaneous Other Income” line item; distributions run straight through the cash flow statement, in “Return on Equity Investment”

 CNNX’s EBITDA and cash distributions have been growing

strongly, with CNNX recently increasing its quarterly cash distribution 3.5% from its prior run-rate

30

Financial: CONE Midstream & Gathering Growing

(in millions except for per share amounts)

Total LP Units held by CONSOL Energy 19.1 Unit Price (as of close on 9.2.2015) $11.52 CNNX Equity Value to CONSOL Energy $220.0 CONSOL Energy's Ownership Interest in CONE Midstream Partners, LP

Source: CONE Midstream Partners LP and CONSOL Energy Inc.

$0 $2 $4 $6 $8 $10 $12 $14 $16 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15

CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX

CNX Pro Rata Share of CONE Midstream Partners LP's Cash Distributions CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's EBITDA

$0 $2 $4 $6 $8 $10 $12 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15

CONE Midstream's and Gathering's Pro Rata Net Income Contribution to CNX

CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's Net Income

31

Debt and Liquidity Profile, Pro Forma CNXC Offering

Financial: Liquidity

Note: Some numbers may not match exactly to financial statements due to rounding. (1) The 2022 and 2023 senior notes includes $6 million and $7 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively. (2) As of June 30, 2015, we had $39 million of borrowings and $49 million of outstanding letters of credit under our accounts receivable securitization facility, leaving approximately $1 million of availability. The accounts receivable securitization facility terminated as July 7, 2015 upon the completion of the CNXC initial public offering. (3) As of June 30, 2015, we had $1,058 million of borrowings and $237 million of outstanding letters of credit under our revolving credit facility, leaving approximately $705 million of availability. (4) Net Debt equals Total Debt less Cash and Cash Equivalents (5) The thermal term loan commitment was terminated as July 7, 2015 upon the completion of the CNXC initial public offering. (6) Adjusted EBITDA is a non-GAAP financial measure and the reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $902 million plus gain on sale of non-core Assets

• f $19 million, plus gain related to changes in retiree medical OPEB plan of $34 million; pro forma excluding the $48 million non-controlling interest share of EBITDA associated with the 20% undivided interest
• f the PA Coal Complex owned by CNXC.

Leverage expected to decline over the next 18 months with free cash flow positive

• perating plan and an assumed $75 to $125 million of asset sales

Sources of Funds ($MM)

Actual CNXC PF CNXC IPO

CNXC Initial Public Offering $150

6/30/2015 IPO 6/30/2015

CNXC Revolver Borrowing 200

Cash and Cash Equivalents $10 $10

CNXC Initial Public Offering - Greenshoe 8 Thermal Term Loan Commitment Fees Rebate 5

Accounts Receivable Facility $39 ($39)

• Revolving Credit Facility

1,058 (309) 749

Total Sources of Funds $363

Term Loan Commitment

• Capital Lease Obligations

47 47 Total Secured Debt $1,144 ($348) $796

Uses of Funds ($MM)

8.25% Senior Notes due 2020 $74 $74

Revolver Repayment $309

6.375% Senior Notes due 2021 21 21

Accounts Receivable Facility Repayment 39

5.875% Senior Notes due 2022 (1) 1,856 1,856

CNXC Transaction Fees 8

8.0% Senior Notes due 2023 (1) 493 493

CNXC Cash on Hand 7

Baltimore 5.75% Revenue Bonds due 2025 103 103 Miscellaneous Debt 17 17

Total Uses of Funds $363

Total Debt $3,708 ($348) $3,360 Net Debt (4) $3,698 ($348) $3,350 Stockholders’ Equity $4,682

• $4,682

Total Capitalization $8,390 ($348) $8,042 Cash and Cash Equivalents $10 $10 Accounts Receivable Facility Capacity (2) $1 ($1) $0 Revolving Credit Facility Capacity (3) $705 $260 $965 Thermal Term Loan Commitment (5) $600 ($600) $0 Total Liquidity $1,316 ($341) $975 Actual PF CNXC IPO Leverage Ratio 6/30/2015 6/30/2015 LTM CONSOL Adjusted EBITDA (6) $955 $907 LTM Total Debt / Adj EBITDA 3.9x 3.7x LTM Net Debt / Adj EBITDA 3.9x 3.7x

32

Proceeds from asset monetization opportunity set would significantly reduce leverage beyond base plan and allow for ability to separate the coal and E&P businesses sooner, if appropriate, by means of a spin transaction

Assets available for sale

Financial: Asset Monetizations

Note: Based on CONSOL’s divestiture experience and recent comparable asset transactions. (1) Potential asset divestiture opportunities are as of 8/31/2015.



Engaged several investment bankers and advisors to assist in the sale process



Actively engaged in discussions with prospective buyers on a number of asset packages



Currently running sale processes on approximately 30 asset packages

• Bids are starting to come in for some packages



Asset monetization's do not include MLP drop-downs



Does not assume strategic transaction with coal assets

Asset Type Value Range ($ in millions)

Coal $400

• $600

Gas 1,000

• 1,400

Surface 50

• 100

Midstream 100

• 200

Total $1,550

• $2,300

33

Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth

Financial: E&P Capital Expenditures

Lowering planned capex spend while maintaining 2015 & 2016 growth targets

Note: Capital spending is net of carry and excludes capital spent on land & permitting.

$460 $90 $550 $500 $80 $50 $630 $120 $1,300 $300 $80 $380 $145 $140 $40 $325 $95

$800

($160) ($10) ($170) ($355) $60 ($10) ($305) ($25) ($500)

$400-$500

($300) - ($400)

($1,000) ($500)

• $500

$1,000 $1,500 Marcellus Wet Utica Wet Total Wet Marcellus Dry Utica Dry CBM/Other Dry Total Dry Gathering Total 2015E 2016E $ in MM

CONSOL E&P Capital Spending

2014 2015E YoY Change 2016E

 High-grading locations, capital efficiency improvements and cost reductions driving further E&P capital spending reductions  2015 E&P capital budget lowered by $120 million to $800 million, a 13% reduction vs. prior budget, a 20% reduction vs. original

$1.0 billion budget, and ~38% lower than 2014

• 2015 capital budget lowered to $800 million but increasing production guidance to range of 320 – 330 Bcfe from 300 - 310 Bcfe, a nearly 7% increase
• Spending allocated to highest rate of return wells in Marcellus and Utica and where in-place infrastructure can be leveraged to lower costs
• Benefitting from continued service cost deflation and cycle time improvements

 Introduction of 2016 E&P capital budget guidance of $400 million to $500 million

• Maintaining 2016 production guidance of 20% annual growth
• Built-in logistical flexibility to plan to enable smooth transition to accelerate activity should commodity price improve into next year
• Estimated $350 - $450 million allocated to development activity, almost entirely completions. Approximately $50 million allocated to Midstream.

Legacy liabilities reduced by 60% and cash servicing costs reduced by 65% from 2012 through 1H 2015, with further reductions expected going forward

34

Significant Legacy Liability Reductions Over Past 3 Years

Financial: Legacy Liabilities

(1) Servicing cost associated with 12/31/15 balance represents forecasted cash payments to service the legacy liabilities in 2016. Servicing cost associated with 6/30/15 balance represents forecasted cash payments to service the legacy liabilities in 2H 2015. Servicing cost associated with 12/31/14 balance represents forecasted cash payments to service the legacy liabilities in

• 2015. Servicing cost associated with 12/31/13 balance represents forecasted cash payments to service the legacy liabilities in 2014. Servicing cost associated with the 12/31/12 balance

represents an estimate of 2013 servicing costs based upon interim fiscal year 2013 payments extrapolated to a full year as though the Murray Sale were not to occur.

• Est. Change

As of Period End: 12/31/2012 12/31/2013 12/31/2014 6/30/2015 12/31/2015E FY15E / FY14 % Legacy Liabilities ($MM) LTD $39 $20 $22 $21 $20 ($2) (9%) WC 180 85 90 89 91 1 1% CWP 184 121 126 127 125 (1) (1%) OPEB 3,018 1,022 761 703 682 (79) (10%) Salary Retirement/Pension 225 53 119 113 107 (12) (10%) Asset Retirement Obligations 699 601 576 579 619 43 7% Total Legacy Liabilities $4,345 $1,902 $1,694 $1,632 $1,644 ($50) (3%) Annual Legacy Liabilities Cash Servicing Cost (1) $370 $148 $153 $129 $122 ($31) (20%)

$4,345 $1,902 $1,694 $1,644 $370 $148 $153 $122 $100 $125 $150 $175 $200 $225 $250 $275 $300 $325 $350 $375 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 12/31/2012 12/31/2013 12/31/2014 12/31/2015E Annual Cash Servicing Cost Legacy Liabilities Projected:

• $50MM Reduction in Legacy Liabilities
• and $31MM Reduction in Annual Cash

Servicing Cost by year-end 2015

Flows through P&L in operating costs (impact reflected in

• perating cost guidance)

Flows through P&L in Coal Division’s “Other Costs” Flows through P&L within: E&P–Operating Expense Coal Divisions–Other Costs

35

Financial: Guidance Summary

Note: Guidance as of 9/9/2015. (1) 3Q 2015 production guidance also revised to 79-83 Bcfe. (2) Excludes land CapEx. (3) Unutilized firm transportation expense of approximately $26.5 and $18.0 million at the midpoint in 2015 and 2016 respectively, less approximately $12.0 and $5.5 million of gathering revenue (resold firm transportation) at the midpoint in 2015 and 2016, respectively.

E&P Segment Guidance 2015E 2016E

Production Volumes:(1) Natural Gas (Bcf) 280

• 285

336

• 342

NGLs (MBbls) 5,500 - 5,900 6,600 - 7,080 Oil (MBbls) 85

• 95

102

• 114

Condensate (MBbls) 1,150 - 1,450 1380 - 1740 Total Production (Bcfe) 320

• 330

384

• 396

Natural Gas Basis Differential to NYMEX ($/Mcf)

• $0.55
• $0.50 - -$0.60

NGL Realized Price ($/Bbl) $15.00 - $16.00 $16.00 - $17.00 Condensate Realized Price % of WTI 45% - 50% 43% - 46% Oil Realized Price % of WTI 93% - 95% 93% - 95% Capital Expenditures:

($ in millions)

Drilling and Completion $705 $350 $450 Midstream 95 50 Total E&P and Midstream CapEx (2) $800 $400 - $500 Average per unit operating expenses:

($/Mcfe)

Lease Operating Expenses 0.32

• 0.34

0.27

• 0.32

Impact Fees/ Ad Valorem/ Production Taxes 0.10

• 0.12

0.10

• 0.12

Gathering, Transportation, Compression & Processing 1.09

• 1.11

1.04

• 1.06

Direct Administrative and Selling 0.15

• 0.17

0.13

• 0.15

Depreciation, Depletion and Amortization 1.08

• 1.10

0.98

• 1.00

Total Production and Gathering Costs 2.74 2.84 2.52 2.65 Other Expenses

($ in millions)

General and Administrative $60.0 - $65.0 $50.0 - $57.0 Unutilized Firm Transporation, net:(3) $14.0 - $15.0 $12.0 - $13.0

36

Financial: Guidance Summary

Note: Guidance as of 7/28/2015.

Coal Segment 2015E 2016E

Total Operations

(in millions of tons)

Estimated Total Coal Sales 28.4

• 29.9

30.6

• 33.4

Total Committed (Priced) 27.5 15.6 % Committed 94% 49% Capital Expenditures: Production ($/Ton) $5.00 $5.00

($ in millions)

Production $142 - $150 $153 - $167 Other (Land/Water/Safety/Terminal) $30

• $35

$60

• $70

Total Coal CapEx $172 - $185 $213 - $237 Average per unit operating expenses:

($/Ton)

Total Production Costs (including DD&A) $42.34 - $45.36 $41.44 - $44.98 Depreciation, Depletion and Amortization $6.93 - $7.33 $6.35 - $6.44 Other Expenses:

($ in millions)

General and Administrative $20

• $25

$20

• $23

Other Corporate 2015E 2016E

Divestitures ($MM) $75 - $125

37

• Milestones:



Coal MLP – executed



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



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



CONE MLP growth – July 15th announced 3.5% increase to quarterly distribution to $0.22 per unit



Positive initial operated Utica well results (Guat 4IH), on target for additional Utica results in 2H 2015 – sets up future stacked pay opportunities

• Continued focus on zero-based budgeting – expecting significantly reduced costs and improved balance sheet
• MetCo IPO on hold for now due to met coal price declines; currently evaluating multiple possibilities, including a future

drop-down into CNXC, partnering with a 3rd party to grow the assets through opportunistic consolidations, and others; decision expected by year-end 2015

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

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

• Asset Monetizations – multiple asset packages under active processes
• Use of free cash flow and asset sales to de-lever and buy back debt and stock
• Our management team is motivated and incentivized long-term to increase return on capital employed and stock
• price. We will do so within our core values of safety, compliance, and continuous improvement

Plans and Goals Aligned to Drive Increased Valuation

We expect to see rising NAV and continue to focus on increasing shareholder value

Financial: Summary

Key Takeaways

38

• CONSOL Energy’s E&P Division has demonstrated that it can stand on its own as a premier Appalachian Basin

producer:

 Gas production has grown significantly  Capital intensity and costs are down dramatically  Dry Utica has opened up a new opportunity set

• Our base plan is achievable and will help us to more easily reach our free cash flow targets due to conservative

plan assumptions:

 NYMEX strip gas pricing with conservative basis differentials  Conservative thermal and met pricing  Modest levels of asset sales assumed between $75-$125 million

• CONSOL Energy has approximately $2 billion of assets available for sale and the proceeds of these sales will be

used to further reduce debt

 Not including MLP drop-downs or strategic transactions

CONSOL Energy’s base plan, coupled with additional asset sales, will result in significant flexibility, including the ability, if appropriate, to separate its coal and E&P businesses by means of a spin transaction

39

Questions

40

Appendix

41

Non-GAAP Reconciliation: Quarter-over-Quarter EBITDA and Adj. EBITDA

Appendix

Three Months Ended June 30 ($ in thousands) 2015 2014 Net Income / (Loss) ($603,301) ($24,935) Add: Interest Expense 46,507 64,211 Less: Interest Income (364) (676) Add: Income Taxes (291,929) 1,214 (Loss) Earnings Before Interest & Taxes (EBIT) (849,087) 39,814 Add: Depreciation, Depletion & Amortization 154,497 137,899 (Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) ($694,590) $177,713 Adjustments: Impairment of E&P Properties 828,905

• Unrealized loss on Commodity Derivative Instruments

24,936

• Backstop Loan Fees

7,334

• Other Transaction Fees

4,968

• Loss on Debt Extinguishment

17 74,277 OPEB Plan Changes (33,649)

• Pension Settlement
• 20,707

Revolver Modification

• 2,989

Coal Contract Buyout

• (30,000)

Total Pre-tax Adjustments $832,511 67,973 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $137,921 $245,686

Source: Company filings.

42

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

Appendix

Source: Company filings.

Twelve Months Ended June 30 ($ in thousands) Net Income / (Loss) ($452,250) Add: Interest Expense 210,051 Less: Interest Income (2,510) Add: Income Taxes (312,888) (Loss) Earnings Before Interest & Taxes (EBIT) (557,597) Add: Depreciation, Depletion & Amortization 609,276 (Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) $51,679 Adjustments: Impairment of E&P Properties 828,905 Unrealized gain on Commodity Derivative Instruments (35,068) Backstop Loan Fees 7,334 Other Transaction Fees 4,968 Loss on Debt Extinguishment 88,741 OPEB Plan Changes (33,649) Long-Term Liability Plan Changes 10,100 Pension Settlement 8,388 Gain on Sale of Non-Core Assets (19,830) Blacksville Fire Settlement (9,750) Total Pre-tax Adjustments 850,139 Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $901,818 2015

43

Non-GAAP Reconciliation: Adjusted Net Cash Provided by Continuing Operations

Appendix

Source: Company filings.

Three Months Ended June 30 ($ in thousands) Net Cash Provided by Continuing Operations $61,742 Addback: Revolver Amendment (2,302) Addback: Thermco and Metco Transaction Fees (2,078) Changes in Working Capital: Changes in Operating Assets: Accounts and Notes Receivable 63,861 Inventories (6,450) Prepaid Expenses 45,084 Changes in Other Assets 10,222 Changes in Operating Liabilities: Accounts Payable (79,882) Accrued Interest (16,570) Other Operating Liabilities (28,267) Changes in Other Liabilities (36,090) Addback: Net Changes in Working Capital (48,092) Adjusted Net Cash Provided by Continuing Operations $114,214 2015



Average gas price for the second quarter of 2015, including hedging, was $(0.06) per MMBtu below NYMEX ($2.58 vs. $2.64); excluding hedging, gas price was $(0.68) per MMBtu below NYMEX ($1.96 vs. $2.64)



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, which commence late next year, are expected to yield price premiums compared with in-basin pricing and expose a portion of the company’s LPG portfolio to Brent Crude pricing.



Q2 2015 natural gas price reconciliation:

44

Appendix

Second Quarter Highlights

2014 Q2 Q1 Q2 NYMEX natural gas ($/MMBtu) 2.64 $ 2.98 $ 4.67 $ Average basis (0.68) 0.03 (0.59) BTU conversion (MMBtu/Mcf)* 0.07 0.09 0.15 Hedging impact per Mcf 0.64 0.48 (0.13) Realized gas price per Mcf 2.67 $ 3.58 $ 4.10 $

*Conversion factor 1.035 1.031 1.036

2015

45

Ethane 64% Propane 22% I-Butane 3% N-Butane 6% Natural gasoline 5% Maximum Ethane Recovery* Potential Scenario

* Assumes 85% ethane recovery level

Ethane 0% Propane 58% I-Butane 9% N- Butane 18% Natural gasoline 15% 2Q15 Actual (~100% Ethane Rejection)

CONE Gathering and Midstream systems provide CONSOL unique flexibility to blend in ethane to meet specifications, allowing for nearly 100% ethane rejection and maximizing economics when fractionation is unattractive

Appendix

Natural Gas Liquids, Oil, and Condensate

Q2 2015 Avg. “NGL Barrel” Composition



Q2 liquids revenue composed 4% of total Company revenue and 12% of E&P sales revenue



Q2 liquids sold: 9.1 Bcfe

Average price realization (per Bbl): Q1 Q2 NGLs $20.40 $12.48 Oil $47.82 $46.14 Condensate $20.82 $31.26 2015

46

Appendix

Source: CONE Midstream Partners LP.

Appendix

47

Utica Shale: Ohio Dry Gas

GPOR Irons 1-4H (Utica): 30.3 MMcf/d – Avg 24-hr rate NBL / CNX MND 6H (Utica): 1 Utica Well Frac complete, waiting on pipeline / production set-up MHR 3-UH (Utica): 32.5 MMcf/d – Avg 24-hr rate MHR 2-MH (Marcellus): 3.7 MMcf/d of gas and 312 Bbls of condensate per day, peak test rates Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2014).

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

MHR Stewart Winland Pad: 46.5 MMcf/d – Avg 24-hr rate ECR Shroyer 2-well pad (Utica): 7,819 – Avg later length 42.5 MMcf/d – Combined Rate CNX SWITZ 6 (Utica) : 4 Utica Wells & 1 Marcellus Currently drilling-out CVX Conner well (Utica): 25.0 MMcf/d – Avg 24-hr rate GST Simms: 4,447' Lateral 1st 48 Hour Prod 29.4mm IP 33 MMcf/d @ 9000psi

48

Monroe County/Moundsville Rhinestreet = 5,930’ Burkett = 6,110’ Marcellus = 6,190’ Utica = 10,680 PIT Airport Rhinestreet = 5,340’ Burkett = 5,460’ Marcellus = 5,690’ Utica = 10,760’ Southwest PA Rhinestreet = 6,730’ Burkett = 7,000’ Marcellus = 7,270’ Utica = 12,840’ Dominion Transmission Rhinestreet = 6,070’ Burkett = 6,250’ Marcellus = 6,360’ Utica = 10,890’

Stacked pay provides CONSOL with substantial contiguous acres for capital-efficient development

Stacked Pay Potential: CONSOL’s Shale Fairway

Appendix

Central PA Marcellus = 7,370’ Utica = 13,110’

49

Stacked pays provide a large inventory and rich opportunity set

Wet Net Acres Dry Net Acres Total Net Acres 190,000 176,000 88,000 449,000 155,000 265,000 913,000 345,000 441,000 614,000 1,400,000

(1) Dry Utica includes 496,000 net prospective acres in Pennsylvania and West Virginia.

Stacked Pay Potential: Appalachian Shale Acreage

526,000 Upper Devonian Marcellus Utica(1)

Rhinestreet Shale Middlesex Shale Burkett Shale West River Shale

Formation Name

P a y

Cashaqua Shale Tully Limestone Hamilton Shale Marcellus Shale Onondaga Limestone Utica Shale Point Pleasant Shale Trenton Limestone

0 GR 400 LITHOLOGY

Total

Appendix

50

Proved Estimated Potential Locations (Gross) Tcfe Proved(2) Unproven Total Marcellus Shale 4.2 1,633 8,000 9,633 Utica Shale(1) 0.5 171 3,000 3,171 Upper Devonian 0.02 11 2,700 2,711 CBM 1.5 3,833 5,200 9,033 Conventional 0.5 11,672 66,000 77,672 Total 6.7 17,320 84,900 102,220

40+ year organic drilling inventory in Appalachian Shale

Note: All reserves and counts are as of YE2014 and exclude Huron, Chattanooga, and New Albany shales. Locations are based on acreage prospective to each reservoir/play considering culture and geography and allocated based on expected drainage areas. Drilling inventory assumes 300 wells drilled per year. (1) Utica shale includes prospective acreage in West Virginia, Pennsylvania, and Ohio. (2) Proved includes PDPs, PDNPs, and PUDs.

E&P Division: Resource and Opportunity Rich Portfolio

Appendix

(1) For the period ending and as of 12/31/2014. (2) Source: EIA. Represents average power plant deliveries for the twelve months ended 12/31/2014. (3) Source: Company filings from FELP, ARLP, WMLP and RNO.

Pennsylvania Mining Complex

Appendix

51



Pennsylvania mining complex consists of three like-new underground mines and related infrastructure with high-Btu bituminous coal (785.6 million tons proven and probable(1))

• PA mining complex– 785.6 million tons reserves / 28.5 million tons

annual capacity(1)



Train loadout facility (up to 9,000 tons per hour) with dual rail access with Norfolk Southern and CSX



High-Btu bituminous thermal coal is primarily sold to utility companies in the eastern United States - 13,000 Btus per pound average gross heat content and 2.37% average sulfur content



Reserves are mined from the Pittsburgh No. 8 Coal Seam located in the Northern Appalachian Basin



Five longwalls and 18 continuous mining sections



Access to seaborne markets through CONSOL-owned Baltimore Marine Terminal for exporting thermal and metallurgical coal

Mine Total Recoverable Reserves (tons) (1) Average Gross Heat Content (Btu/lb) (1) Average Sulfur Content (1) Annual Production Capacity (tons) (1) Production (tons) (1) Bailey 254.5 12,929 2.68% 11.5 12.3 Enlow Fork 322.8 12,942 2.21% 11.5 10.6 Harvey 208.3 13,080 2.24% 5.5 3.2 Total 785.6 12,974 2.37% 28.5 26.1 Illinois Basin 11,396 2.94% Other NAPP 12,134 3.19% Other Coal MLPs 11,619 2.74%

(2) (3)

                                                                                                 

Baltimore Terminal PA Mining Complex

Active Complex Port/Dock CNXC Customers

We couldn't fine the original artwork 655159_Graphic.ai NY0086JT so we had to ungroup it and make the edits.

(2)

200 400 600 800 1000 1200 1400 1600 1800 2000 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

TWh Year

Coal Natural Gas Nuclear Renewable Petroleum Other

Source: EIA AEO 2015.

52

Coal Continues to be the Low-Cost Choice for Electricity Generation



U.S. power generation will remain highly dependent on thermal coal for the foreseeable future



Coal generation maintains a market share of 37-39% through 2030



Coal increases its advantage over natural gas on a delivered price basis, assuring that coal will be “in the money”

Delivered Cost of Fuel to U.S. Electric Power Sector, $/mmBtu (EIA Data)

2012 2014 2016 2020 2030 Natural Gas $3.59 $5.17 $4.53 $5.52 $6.38 Coal $2.41 $2.27 $2.25 $2.38 $2.67 Spread $1.18 $2.90 $2.28 $3.14 $3.71

U.S. Electricity Generation by Fuel

Widening Cost spread

Appendix