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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

on 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

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.

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

5

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

128154 156

172

236

320-330

+20%

0

50

100

150

200

250

300

350

400

450

0

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

86390

0

50

100

150

200

250

300

350

400

450

2014 TotalProduction

2015 Basedecline

2015: GatheringDe-bottlenecking

2015: Non-Op(Ex NBL/HES)

Prod. Adds

2015: ProductionAdds


2016 Basedecline

2016: GatheringDe-bottlenecking

2016: Non-Op(Ex NBL/HES)

Prod. Adds

2016: ProductionAdds


Bcfe

Average $2.06

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

CNX

$/M

cfe

Average $2.14

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

CNX

$/M

cfe

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


(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


─ PA/WV Dry: 2.4 Bcfe


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 Oil: 0 Bbl/d

Permits submitted for 2 additional

laterals

HES – Poterfield 1H-17*


IP Oil: 0 Bbl/d

RICE – Bigfoot 9H


IP Oil: 0Bbd

GPOR – Stutzman 1-14


IP Oil: 0 Bbd

GPOR – Irons 1-4


IP Oil: 0 Bbd

CNX – Switz 6

4 Utica Wells & 1 Marcellus

Frac complete, waiting on pipe

MHR – Stalder 3UH


IP Oil: 0 Bbl/d

MHR – Winland Pad


HGE – Whiteacre 2H

IP Gas: 9,000 Mcf/d

IP Oil: 0 Bbl/d

Eclipse – Tippens 6H


IP Oil: 0 Bbl/d


*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

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

0 10 20 30 40 50 60 70 80

psi

g

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 temporarilyshut-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

16

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

0

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 1/1/2018M

MB

tu/d

ay

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

$/D

th

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

18

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 C

om

mit

me

nts

as

% o

f EV

$ B

illio

ns

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

0

25

50

75

100

125

150

175

200

225

250

FY 2015 Prior FY 2015 NEW FY 2016 Prior FY 2016 NEW

Ave

rage

Pri

ce

Ga

s V

olu

mes

(B

cf)

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

0

5

10

15

20

25

30

CN

XC

Assets

(5)

Marion C

ounty

(1)

Monongalia

County

(1)

Em

era

ld (

1)

Federa

l (1

)

Harr

ison C

ounty

(1)

Mounta

in V

iew

(1)

Leer

(1)

Mars

hall

County

(2)

Cum

berland (

1)

Centu

ry (

1)

Ohio

County

(1)

Tunnel R

idge (

1)

Pow

hata

n (

1)

Su

lfu

r (%

as r

eceiv

ed

)

Pro

du

cti

on

(m

illi

on

to

ns)

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

0

20

40

60

80

100

120

140

Millio

n T

on

s

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;

our 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

0

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

Re

tire

d C

ap

ac

ity (

MW

)

Actual andAnnounced U.S. CoalPlant 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

operational control over, CONSOL Energy’s

Pennsylvania mining complex

CONSOL Energy retained an 80% undivided

interest in the Pennsylvania mining complex and

owns 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

ownership 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

ownership 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

of $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

of the PA Coal Complex owned by CNXC.

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

operating 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

MarcellusWet

Utica Wet Total Wet MarcellusDry

Utica Dry CBM/OtherDry

Total Dry Gathering Total2015E

2016E

$ i

n M

M

CONSOL E&P Capital Spending2014 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

An

nu

al C

ash

Se

rvic

ing

Co

st

Lega

cy L

iab

iliti

es

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

operating 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 Twelve 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


42

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

Appendix


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


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):


MHR 2-MH (Marcellus):

3.7 MMcf/d of gas and 312 Bbls of

condensate per day, peak test

rates


Recent nearby results have surrounded our contiguous Monroe County leasehold,

which contains ~2.1 Tcfe of resource

MHR Stewart Winland Pad:


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):


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


Burkett = 5,460’


Utica = 10,760’

Southwest PA


Burkett = 7,000’


Utica = 12,840’

Dominion Transmission


Burkett = 6,250’


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


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)

654925_1.w or (NY0086JT)

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)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

201

2

201

3

201

4

201

5

201

6

201

7

201

8

201

9

202

0

202

1

202

2

202

3

202

4

202

5

202

6

202

7

202

8

202

9

203

0

TW

h

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

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