Company Presentation - CNX Resources Corporationinvestors.cnx.com/~/media/Files/C/CNX-Resources-IR/... · 2018. 6. 8. · Earnings per Diluted Share $0.52 ($0.01) $0.53 $0.52

Company Presentation Q3 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 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.

3

Q3 2015 Overview

Key Takeaways

4

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 (already sold assets for ~$95 million of cash proceeds)

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

5

Net income Attributable to CONSOL Energy Shareholders for the third quarter was $119.0 million

- Includes the following pre-tax items:

$100.9 million benefit related to changes in retiree medical OPEB plan

$99.1 million unrealized gain on commodity derivative instruments

$48.5 million gain on sale of coal assets

$7.7 million in severance payments

$3.1 million related to pension settlement

E&P Division’s third quarter net income was $30.3 million

- Production increased by 33% in the third quarter compared to year-earlier quarter

- Revenue decreased by 22% in the third quarter compared to the prior year due to depressed commodity prices

- Marcellus Shale all-in unit costs were $2.57 per Mcfe in the third quarter, a decrease of $0.12 from $2.69 per Mcfe

in the year-earlier quarter, or (4%)

- Utica Shale production volumes were 15.3 Bcfe in the third quarter, a 128% increase from 6.7 Bcfe in the year-

earlier quarter

- Utica Shale all-in unit costs were $2.14 per Mcfe in the third quarter, a decrease of $0.23 from $2.37 per Mcfe in

the year-earlier quarter, or (10%)

(1) Adjusted EBITDA is a non-GAAP financial measure and a consolidated number, please refer to the reconciliation is provided in the Appendix.

CONSOL Energy: Third Quarter 2015 Results

Q3 2015 Overview

Q3 2015 Summary Y/Y Q-to-Q Seq. Q-to-Q

($ in millions, except per share data) 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change

Net (Loss) Income Attributable to CNX Shareholders $119 ($2) $121 $119 ($603) $722

Earnings per Diluted Share $0.52 ($0.01) $0.53 $0.52 ($2.64) $3.16

Revenue and Other Income $814 $885 ($71) $814 $649 $165

Cash Flow from Operations $110 $293 ($183) $110 $62 $48

Adjusted EBITDA(1) $136 $236 ($100) $136 $138 ($2)

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E&P Division:

- 2015 production projected to be between 325- 330 Bcfe, up from 320-330 Bcfe

- Production volumes expected to grow approximately 20% in 2016 over 2015

- Capital efficiency improvements, including lean manufacturing, achieve same growth with less capital

2016 E&P capital budget guidance of $400 – $500 million

- Continued implementation of zero-based budgeting reducing operating and overhead costs

- Improvements in Appalachia takeaway infrastructure to lower basin differentials and improve realized prices

- Goal is to maintain and improve our strong liquidity position

Coal Division:

- Multi-year sales secured to bring Pennsylvania operations to 74% sold for FY 2016

Source: Company filings. Sum of numbers may differ slightly from totals and financial statements due to rounding.

(1) Approximately $180 million of 3Q 2015 Proceeds from LT debt is comprised entirely of CNXC LT revolver debt, consolidated on CNX financial statements per US GAAP accounting rules.

CONSOL Energy: Net (Decrease)/Increase in Cash

Q3 2015 Overview

Cash Flow Summary Y/Y Q-to-Q Seq. Q-to-Q

($ in millions) 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change

Net Cash Provided by Operations $110 $293 ($183) $110 $62 $48

Capital Expenditures ($259) ($355) $96 ($259) ($342) $82

Proceeds From Asset Sales $76 $8 $68 $76 $5 $71

Other Investing ($26) $148 ($174) ($26) ($12) ($15)

Proceeds From /(Payments on) Short-Term Debt & Misc. Borrowings ($149) ($1) ($148) ($149) $296 ($445)

Proceeds From /(Payments on) Long-Term Debt(1) $180 $3 $177 $180 ($3) $183

Dividends Paid ($2) ($14) $12 ($2) ($14) $12

Proceeds from the sale of MLP interest (CNXC IPO) $148 $0 $148 $148 $0 $148

Other Financing ($4) ($3) ($1) ($4) $13 ($17)

Net (Decrease) / Increase in Cash $73 $78 ($6) $73 $5 $68

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$2 billion Revolving Credit Facility:

5 year credit facility expires June 2019

Gas reserves based lending facility

Obtained the right to separate the coal and gas business subject to a leverage test

Strong Liquidity Position of ~$1 Billion

Q3 2015 Overview

September 30,

Negative Covenants Limit 2015

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 4.9 to 1.0

Minimum Current Ratio < 1.0 to 1.0 2.0 to 1.0

Ample liquidity of over $850 million should continue to improve going forward with

business plans focused on positive free cash flow generation through 2016 and

deleveraging the balance sheet

(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $83 million as of 9/30/2015, $3 million of which was CNXC’s but consolidated per US GAAP accounting

(2) Revolving credit facility as of 9/30/2015

Amount/ Amount Letters Amount

September 30, 2015 ($ in million) Capacity Drawn of Credit Available

Cash and Cash Equivalents(1) $80 - - $80

Revolving Credit Facility(2) $2,000 $945 $281 $774

Total $2,080 $945 $281 $854

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Coal Division: Q3 2015 Results Summary

Q3 2015 Overview

Y/Y Q-to-Q Seq. Q-to-Q

Coal Division 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change

Average Sales Price ($ / ton) $56.34 $62.32 ($5.98) $56.34 $56.78 ($0.44)

Average Costs ($ / ton) $43.39 $49.93 ($6.54) $43.39 $45.69 ($2.30)

Coal Production (millions of tons) 7.3 7.8 (0.5) 7.3 7.5 (0.2)

Sales Volumes (millions of tons) 7.2 7.8 (0.6) 7.2 7.3 (0.1)

Sales Per Ton ($ / ton)

Pennsylvania Operations $56.99 $61.35 ($4.36) $56.99 $56.21 $0.78

Virginia Operations $51.82 $70.57 ($18.75) $51.82 $57.76 ($5.94)

Other Operations $57.36 $58.27 ($0.91) $57.36 $60.84 ($3.48)

79%

14%

7%

FY 2015 Sales Tons by Segment

PA Ops VA Ops Other

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Coal Division: Q4, FY 2015 and 2016 Marketing Update and Forecasts

Q3 2015 Overview

2015 Coal Sales Facts and Goals

Contracted tons for 2015: 98%

- Priced: 97%

~77% of the PA Ops tons are expected to be sold

domestically

~77% of the VA Ops tons are expected to be sold

overseas

100% of the Other tons are expected to be sold

domestically

2016 Coal Sales Facts and Goals

Contracted tons for 2016: 71%

- Priced: 63%

Coal Sales

Guidance(1)

Q4 2015E Q4 2014 2015E 2014 2016E

PA Ops 5.1-5.6 6.5 23.0-23.5 26.1 25.0-27.0

VA Ops 0.7-1.0 1.1 3.9-4.2 4.1 3.7-4.2

Other 0.4-0.6 0.5 2.0-2.2 2.2 1.9-2.2

Total 6.2-7.2 8.1 28.9-29.9 32.4 30.6-33.4

80%

13%

7%

Q4 2015 Sales Tons by Segment

PA Ops VA Ops Other

Note: PA Ops tons reflecting volumes at 100% interest and are not pro rata for CNX ownership of the PA Complex or CNXC

(1) Tons in millions

Y/Y Q-to-Q Seq. Q-to-Q

E&P Division 3Q2015 3Q2014 Change 3Q2015 2Q2015 Change

Average Sales Price(1)

($ / Mcfe) $2.35 $3.97 ($1.62) $2.35 $2.68 ($0.33)

Average Costs(2)

($ / Mcfe) $2.63 $3.12 ($0.49) $2.63 $2.90 ($0.27)

Sales Volumes (Bcfe) 86.1 64.9 21.2 86.1 75.5 10.6

Sales Volumes (Bcfe) by Category

Marcellus 44.9 30.7 14.2 44.9 39.0 5.9

CBM 18.5 20.0 (1.5) 18.5 18.8 (0.3)

Utica 15.3 6.7 8.6 15.3 10.6 4.7

Other 7.4 7.5 (0.1) 7.4 7.1 0.3

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Marcellus Shale production now largest part of

mix; Utica volumes growing rapidly as part of

production mix

2015E Marcellus Shale production CAGR ~67%

from 2013

“Other” category includes Shallow Oil and Gas,

Chattanooga Shale in Tennessee, and Upper

Devonian Shale production in PA and WV

E&P Division: Q3 2015 Results Summary

Q3 2015 Overview

(1) Average Sales Prices for 3Q2015, 3Q2014 and 2Q2015 include gains/(losses) on hedges of $0.60, $0.36 and $0.64, respectively.

(2) Average Costs for 3Q2015, 3Q2014 and 2Q2015 include DD&A of $1.02, $1.26 and $1.14, respectively.

51%

23%

19%

7%

FY 2015 Production by Category

Marcellus CBM Utica Other

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E&P Division: Q3 2015 Operations Summary

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length

(ft)

Counties

Southwest

PA 1 3 7 6 7,002

Greene,

Washington,

PA

Central PA ---- ---- ---- ---- ---- Indiana, PA

Northern

WV Dry 1 5 ---- 6 6,787

Barbour,

Doddridge,

Lewis, WV

Ohio ---- ---- ---- ---- ---- Monroe, OH

North Wet

Gas 1 4 4 16 8,038

Greene,

Washington,

PA; Marshall,

WV

South Wet

Gas 1 2 ---- ---- ----

Doddridge,

Tyler,

Ritchie, WV

Total 4 14 11 28 7,276

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length (ft)

Counties

Core Wet ---- ---- ---- ---- ---- Monroe, Noble,

OH

Surrounding

Core Wet 1 5 5 11 7,525

Harrison,

Belmont, OH;

Greene, PA

Dry Utica ---- 1 4 ---- ----

Monroe, OH;

Westmoreland,

PA

Total 1 6 9 11 7,525

Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary

Q3 2015 Overview

Continuous improvement leading to record drilling performance:

─ Cycle time decreased 57% for drilling dry OH Utica in Q3

compared to 2014 One record lateral casing to 10,634’

SWITZ 6D achieved an averaged 24-hour IP of 44.7 MMcf/d at a

pressure of 6,835 psi, well above expectations.

─ Results led increasing the type curve on this area to 2.4 Bcf/1,000’

of lateral from 2.2 bcf/1000’

─ The remaining 3 Utica wells and 1 Marcellus well on the Switz pad

are flowing back at this time.

Strong production response from SWPA gathering system de-

bottlenecking project:

─ De-bottlenecking efforts added ~2.7 BCF in Q3 alone

─ The latest phase in the project occurred in the 2nd week of August, so

have not even seen full quarter impact yet

─ Recent project added ~100 MMdcfd of additional capacity

Completions efficiencies have been dramatically enhanced

through performance incentive contracting:

─ 23% increase in ft./day stimulated through Q3 2015 vs. 2014

─ 29% decrease in completions cost per lateral foot through Q3 2015

vs. 2014 with aggressive cost cutting measures

─ Lean manufacturing driving down cycle times and wells are in-line 8

days earlier on average vs. 2014

128154 156

172

236

325-330

~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

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Increasing 2015E production guidance to 325 – 330 Bcfe;

~20% year-over-year growth target for 2016

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

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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

~328

-50

14

15

~83~390

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

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

Average $2.14

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

CNX

$/M

cfe

14

F&D/Mcfe: Continued Operational Efficiency Improvements

E&P Division

Rate of improvement 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

15

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 of $800 million a 20% reduction vs. original $1.0 billion budget, and ~38% lower than 2014

- 2015 capital budget lowered to $800 million while production guidance range now 325 – 330 Bcfe, up ~1% at the midpoint from prior 320 - 330 Bcfe

- 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

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

- Maintaining 2016 production guidance of approximately 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. Approximately $50 million allocated to Midstream.

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E&P Division

17

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 ~43,000 non-JV) and ~302,000 and ~194,000 net prospective acres in PA and WV respectively..

Utica Shale Overview: A Leading Position in the Utica Shale

Utica Shale

~614,000 CONSOL net

acres(1)

Over 3,000 gross locations

─ 77 wells online, as of

9/30/2015

─ 11 wells TIL in Q3 2015

─ 7,525 ft average TIL

laterals in Q3 2015

─ 4 wells per pad on

average

─ 120-acre spacing

(assuming 7,000 ft lateral)

EURs:

─ Ohio Wet: 2.1 Bcfe

EUR/1,000 ft of lateral

─ Ohio Dry: 2.4 Bcfe


─ PA/WV Dry: 2.4 Bcfe


2016E Utica shale

production 480% above

2014 volumes

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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 Sportman’s Club

IP Gas: 59 MMcf/d

IP Oil: 0 Bbl/d

EQT – Pettit 593066

Spud in Aug. 2015

13,400 ft. TVD; 4,000-4,500 ft. lateral

CVX – Conner 6H


IP Oil: 0 Bbl/d

Permits submitted for 2 add. laterals HES – Potterfield 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 6D

44.7 MMcf/d @ 6,835 psig

24-hr test rate

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

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 flowback

CNX – GH9

Drilled – 6100’ Lateral

Completion in Q4, 2015

CNX – Gaut 4IH

61.4 MMcf/d @ 7,968 psig

24-hr test rate

EQT – Scotts Run

24 Hour Prod 72.9 MMcf/d

CHK – Messenger WTZ 3UH

IP Gas: ~30 MMcf/d

EQT – Big 190

Spud in Sept. 2015

12,700 ft. TVD; 3,500-4,000 ft. lateral

Antero - Rymer

Drilling

CONSOL has over 110,000 acres of Utica leasehold in

Westmoreland and Indiana Counties, PA 19

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

Achieved Peak 24-hr rate of 61.4

MMcf/d in July 2015

Utica Shale: Gaut 4IH – Westmoreland County, PA


Currently testing the reservoir extent and deliverability potential of the well, which

continues to produce at 20+MMcf/d with minimal pressure drawdown of 25-30 psi/day.

20

Utica Shale: Gaut 4IH Westmoreland County, PA

4000.00

5000.00

6000.00

7000.00

8000.00

9000.00

10000.00

0

5,000

10,000

15,000

20,000

25,000

30,000

9/23/2015 9/28/2015 10/3/2015 10/8/2015 10/13/2015 10/18/2015 10/23/2015 10/28/2015

Flow

ing

Casi

ng P

ress

ure

(psi

g)

Gas

Rat

e (M

scf/

d)

Flow Rate MCf/Day Casing Pressure PSIG

Conducting a Modified

Isochronal Test with planned

extended drawdown and

build-up

Consists of alternating

stages of flowing producing

and then shutting-in to

observe the drawdown in

pressure on production and

re-pressurization on shut-in

Resulting data provides

indication of optimal

operating pressure, future

stabilized production rates

and per well drainage area

21

Range Resources - Claysville Sportsman’s Club #1

IP Gas – 59.0 MMcf/d

CONSOL GH9

Drilled, awaiting

Completion. 6,141’

planned treated interval

100% WI to CONSOL

TVD: 13,400’

Currently waiting for completions

Drilled lateral length of 6,141’

~30 stage frac scheduled for Q4 2015

Situated in existing Marcellus field

Ready supply of water

Production facilities and gathering

system with available capacity

EQT – Scotts Run

24 hr IP – 72.9 MMcf/d.

3,221’ Treated interval.

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

EQT – Pettit 593066 Spud in Aug. 2015

13,400 ft. TVD

4,000-4,500 ft. lateral


Utica Shale: Ohio Dry Gas

22

CNX Activity and Recent IP Rates In-and-Around Monroe County, OH

GPOR Irons 1-4H (Utica):

30.3 MMcf/d – Avg 24-hr rate

NBL / CNX MND 6H (Utica):

1 Utica Well

Waiting on flowback

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 Pad (Utica) :

4 Utica Wells & 1 Marcellus

CNX – Switz 6D: 24-hr test rate

44.7 MMcf/d @ 6,835 psig

Remaining wells flowing back

CVX Conner well (Utica):


GST Simms:

4,447' Lateral

1st 48 Hour Prod 29.4mm

IP 33 MMcf/d @ 9000psi

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

Monroe County, OH

23

CONSOL – SWITZ 6 Pad (Utica):

4 Utica wells & 1 Marcellus well

CNX – Switz 6D: 24-hr test rate

44.7 MMcf/d @ 6,835 psig

Remaining wells flowing back

4 Utica Wells and 1 Marcellus Well

Avg. Utica Lateral Length = 8,821’

Longest Utica Lateral = 10,122’

100% WI to CONSOL

Testing 3 proppant types

350K pounds/stage @ 200’ spacing

Multi-Market availability

TIL planned 4Q 2015

Offset pad fully permitted with 5 wells

Utica Shale: Switz 6 Monroe County, OH


0

2000

4000

6000

8000

10000

0

10,000

20,000

30,000

40,000

50,000

10/13/2015 10/14/2015 10/15/2015 10/16/2015 10/17/2015 10/18/2015 10/19/2015 10/20/2015

Flo

win

g C

asin

g P

ress

ure

(p

sig)

Gas

Rat

e (

Mcf

/d)

Gas Rate Casing Pressure

24

Utica Shale: Switz 6D Monroe County, OH

The Switz 6D well had a peak 24-hr IP of ~45 MMcf/d with an average flowing casing

pressure of 6,835 psig, which is the 5th highest IP in the Utica to date and the best in

SE OH

The limited decline in flowing

casing pressure bodes well for

a strong stabilized production

rate going forward

Currently temporarily

shut-in to flowback

other wells on the

SWITZ pad

0

5,000

10,000

15,000

20,000

25,000

0 20 40 60 80 100 120

Mea

sure

d D

epth

(ft

.)

Days

Days vs. Depth (Well in order of Horizontal TD Date)

Switz-6B-HSU

Switz-6F-HSU

Switz-6H-HSU

Switz-6D-HSU

Switz-16J-HSU

$509.76

$540.17

$321.59

$344.98

$231.80

$0

$100

$200

$300

$400

$500

$600

Switz-6B-HSU Switz-6D-HSU Switz-6H-HSU Switz-6F-HSU Switz-16J-HSU

Dri

llin

g C

ost ($

/ft.)

Switz Drilling Cost/Ft. (In order by Tophole TD)

~55% Reduction in Drilling Costs

25

Dry Utica: Monroe County Cost Improvements

Accelerating rate of change in CONSOL’s efficiency improvements: drilling costs

reduced by 55% in the Monroe County, OH between just the 1st Utica well to the 5th

~60+% Reduction in Days to Drill

26

PA Utica: Drilling & Completion Cost Reductions

$12.4

$26.2 (8.2)

(2.2)

(0.4)(1.2) (1.1)

(0.8)

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

Prior AFE Per Well Drilling Efficiency Drilling Science Cost Casing Design Multi-Well Pad (4) Completion Design Proppant Optimization Development AFE PerWell

Waterfall Diagram - PA Dry Utica Drilling and Completion Costs Per WellAssume 7000' lateral on a development 4-well pad

($ in millions)

High degree of confidence towards lowering D&C costs in the PA Dry Utica, similar to

successful cost reduction efforts in the Marcellus; plans in place targeting more than

a 50% reduction in D&C costs per well Notes: Numbers are rounded.

(1) Data reflects CONSOL Energy Inc.’s estimated per well Authorization for Expenditure (AFE) for drilling, completion and associated costs in the Utica Shale and Point Pleasant intervals in SWPA.

(2) Actual costs for Gaut 4IH well. Actual costs may vary from AFEs.

(3) Estimated, actuals may vary.

(2)

(3)

PA Dry Utica: Drilling and Completion Cost Reductions

Waterfall Chart Data(1) ($ in millions) Probability(3) Comments

Prior Well Cost(2) $26.2 Initial - Drilling & Completion Cost on Gaut 4I

Cost Reductions:

Drilling Efficiency (8.2) High Elimination of non-productive time experienced on Gaut 4I; top down drilling saves mobilization/de-mobilization cost and time

Drilling Science Cost (2.2) High Elimination of extensive science work conducted on Gaut 4I: geological evaluation - pilot hole, logging, plugback, etc.

Casing Design (0.4) Medium Elimination of additional casing string not required by regulation

Multi-Well Pad (4) (0.8) Medium Fixed costs shared across wells (ex. pad, mob./de-mob., containment); efficiencies of scale

Completion Design (1.2) Medium Hybrid stage spacing; elimination of drill-out phase; utilization of normal dry gas flowback package

Proppant Optimization (1.1) High Modification of proppant type (ceramic to resin); 3rd party chemicals; 25% reduction in gel use

Total Reductions(3) (13.8)

Development Well AFE(3) $12.4

27

Gas Marketing

Average gas price for the third quarter of 2015, including hedging, was a $(0.43) per MMBtu differential to NYMEX

($2.34 vs. $2.77); excluding hedging, gas price was $(1.00) per MMBtu below NYMEX ($1.77 vs. $2.77)

CONSOL basin exports increased ~100,000 Dth /day in late Q3 as TETCO’s OPEN and U2GC expansion projects

were put into service, increasing realizations by marketing gas to the higher priced Midwest and Gulf Coast

markets

CONSOL entered into ethane, propane, and butane sales agreements under which volumes will be shipped via

Mariner East pipelines to the Marcus Hook Industrial Complex and ultimately exported to Europe

─ The deals, the first of which will commence late this 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 linked pricing.

Q3 2015 natural gas price reconciliation:

28

Gas Marketing E&P Marketing Highlights

2014

Q3 Q2 Q1 Q3

NYMEX natural gas ($/MMBtu) 2.77$ 2.64$ 2.98$ 4.06$

Average differential (1.00) (0.68) 0.03 (0.94)

BTU conversion (MMBtu/Mcf)* 0.09 0.07 0.09 0.12

Hedging impact per Mcf 0.60 0.64 0.48 0.36

Realized gas price per Mcf 2.46$ 2.67$ 3.58$ 3.60$

*Conversion factor 1.05 1.04 1.03 1.04

2015

Targeting pipeline projects that

access favorable markets at

favorable rates

Will supplement direct FT with firm

sales to customers that have

matching firm capacity

Working with marketing partners to

monetize/utilize regionally

underutilized capacity

Near term, will optimize and/or

release FT to enhance revenues

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

29

Gas Marketing Firm Transportation

Low average demand costs of $0.25 to $0.29/Dth reflect a well balanced portfolio

between in-basin/out-of-basin markets; minimum relative long-term financial risk

(1) Charts also include transportation under precedent agreements

$0.25 $0.25 $0.29

$0.11 $0.11 $0.11

$-

$0.10

$0.20

$0.30

$0.40

$0.50

2016 2017 2018

$/D

th

CNX's Firm Transportation Costs

Avg. Demand Avg. Variable

$0.36 $0.36 $0.40

TETCO

Dominion

East Tennessee

Columbia

ANR

NEXUS

-

200

400

600

800

1,000

1,200

1,400

1,600

Jan 15 Jan 16 Jan 17 Jan 181000s M

MB

tu/d

ay

TETCO Dominion East Tennessee Columbia ANR NEXUS

FT Capacities

Pipeline (MMcf/d) YE 2015 YE 2018

ANR Pipeline 47 47

Columbia (TCO) 215 305

Dominion (DTI) 245 342

East Tennessee 282 202

Nexus - 150

TETCO 127 127

TETCO (via firm sales) 285 225

1,201 1,398

(1)

30

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) 22% 19%

TETCO (M2) 21% 18%

TETCO (M3) 17% 16%

Dominion (DTI) 18% 16%

East Tennessee 11% 11%

TETCO ELA & WLA 4% 8%

Midwest (Chicago) 7% 12%

100% 100%

Natural Gas Sales

Source: SNL Financial.

TETCO WLA

Current sales portfolio of 100 active customers priced in seven index markets;

actively negotiating with major Midwest, Gulf Coast and LNG customers

Updated estimated natural

gas sales mix for FY 2016

reflects an improved expected

realization position, including

a greater percentage of out-

of-basin sales, compared to

the prior estimated sales mix

Contracted capacity meets

current requirements

─ Inlet wet gas volumes to

processing plants were ~145

MMcf/d above CONSOL’s

minimum committed volume

in Q3 2015

Maintained the flexibility

to leave ethane in the

residue gas stream

Operational and contractual

flexibility to potentially convert a

portion of currently processed

wet gas volumes to be

marketed as dry gas volumes,

which would lower processing

fees and improve netbacks

31

Gas Marketing Natural Gas Processing

Flexible contracts permit us to optimize the timing and volume of our flows without

risk of penalty

Note: We have processing capacity expansion rights of 110,000 Mcf/d

0

50

100

150

200

250

300

350

400

450

500

Jan 15 Jan 16 Jan 17

MM

cf/

d

Contracted Capacity at Processing Plants

Minimum Volume with Commitments

Short-term uplift in realizations can come at the expense of over-committing to

expensive FT incurring long term off-balance sheet liabilities

32

Notes: Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC and SWN.

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

33

(1) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements

(2) At the midpoint of production guidance

(3) Hedge positions as of 10/9/2015

(4) NYMEX futures as of 10/23/2015

Gas Hedges

Gas Marketing: Hedges

4Q15 FY 2015 FY 2016

NYMEX + Basis (1)

Volumes (Bcf) 43.1 123.6 182.9

Average Prices ($/Mcf) $3.42 $3.62 $3.30

NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) 20.2 49.9 41.1

Average Prices ($/Mcf) $3.50 $3.75 $3.58

Total Volumes Hedged (Bcf)(3) 63.3 173.5 224.0

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

Approximately 57% of total

FY 2016E production

volumes hedged(2)

Approximately 47% of total

FY 2016E production

volumes hedged(3) with fixed

prices (NYMEX + Basis)

more than 18% above FY

2016 NYMEX futures(4)

0

25

50

75

100

125

150

175

200

225

250

4Q15 FY 2015 FY 2016

Gas V

olu

mes H

edged (

Bcf)

NYMEX + Basis (1)

NYMEX Only Hedges Exposed to Basis

Average price realization (per Bbl):

Q3 Q2 Q1

NGLs $4.80 $12.48 $20.40

Oil $54.18 $46.14 $47.82

Condensate $27.84 $31.26 $20.82

2015

34

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%

3Q15 Actual (~100% Ethane

Rejection)

CONE Gathering and Midstream systems provides CONSOL unique flexibility to

either (a) blend in ethane to meet specifications, allowing for nearly 100% ethane

rejection or (b) extract ethane when accretive

Gas Marketing Natural Gas Liquids, Oil, and Condensate

Q3 2015 Avg. “NGL Barrel” Composition

Q3 2015 liquids sold: 12.1 Bcfe

─ Assuming maximum ethane recovery scenario

Q3 total production volumes would have been

2.7 Bcfe higher

Liquids composed approximately 14% of Q3

production volumes, 10% of E&P sales revenue and

3% of total Company revenue

35

Coal Division

$33.50 $43.73 $53.48

$23-35 Margin

$8-148 Margin

$4-21 Margin

5-yr Avg Price: $64

5-yr Avg Price: $111

5-yr Avg Price: $72

Bailey Buchanan Miller Creek

Cash Margin per ton ($)

36

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

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.

2

(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

Coal Division

37

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)

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

Not All NAPP Longwalls Are Created Equal

Coal Division

38

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

39

40

Financial

41

Financial: Focused on Free Cash Flow

Strong and improving liquidity

CNXC and CONE

- CONE Midstream cash flows and EBITDA growing

Asset monetizations

Reduction in legacy liabilities

Guidance: Production, price realizations, operating and capital costs

- Growing E&P production volumes

- Reductions to operating and overhead costs

- Reductions in E&P 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)

- Steady coal production with lower cost base

CONSOL remains focused on lowering costs and deleveraging the balance sheet

through organic operations and potential asset sales

42

Debt and Liquidity Profile

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 9/30/2015, CNX had approximately $945 million of borrowings and $281 million of outstanding letters of credit under its revolving credit facility, leaving approximately $774 million

of availability. CNXC had $180 million outstanding on its revolving credit facility leaving approximately $220 million of availability.

(3) Net Debt equals Total Debt less Cash and Cash Equivalents

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

CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 9/30/2015 9/30/2015 9/30/2015

Capitalization

Cash and Cash Equivalents $83 $3 $80

Revolving Credit Facility Balance 1,125 180 945

Capital Lease Obligations 46 - 46

Total Secured Debt $1,171 $180 $991

8.25% Senior Notes due 2020 $74 - $74

6.375% Senior Notes due 2021 21 - 21

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

8.0% Senior Notes due 2023 (1) 493 - 493

Baltimore 5.75% Revenue Bonds due 2025 103 - 103

Miscellaneous Debt 16 - 16

Total Debt $3,734 $180 $3,554

Net Debt (3) $3,651 $177 $3,474

Stockholders’ Equity $4,888 $155 $4,733

Total Capitalization $8,622 $335 $8,287

Liquidity

Cash and Cash Equivalents $83 $3 $80

Revolving Credit Facility Capacity (2) 994 220 774

Total Liquidity $1,077 $223 $854

CNX

Onwed LP

Units(4)

Unit

Price(4)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 12.7 $12.19 $154

CONE Midstream Partners LP (CNNX:NYSE) 19.1 $10.17 $194

Total Equity Value of Ownership Interests in Affiliated Public MLPs $349

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity of

Affiliates

CNX Coal Resources LP (5)

$400 $180 $220 $3 $223

CONE Midstream Partners LP (5)

$250 $23 $227 $0 $227

Total Liquidity of Affiliated

Public MLPs $650 $203 $447 $3 $450

Leverage Ratio 9/30/2015

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (6) $967

LTM Bank Net Debt / Adj. EBITDA (6)

3.8x

Equity Value of Ownership in Affiliated Public MLPs

(4) Number of MLP units owned by CNX as of 9/30/2015 and unit prices as of market close on 10/20/2015.

(5) CNX Coal Resources liquidity data is as of 9/30/2015 and CONE Midstream data is as of 6/30/2015.

(6) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the

reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $801

million plus gain on sale of assets of $68 million, plus gain related to changes in retiree medical (OPEB)

plan of $135 million, less the $92 million of CNXC EBITDA Attributable to CNX, plus the $53 million of

CNXC cash distributions to CNX and plus $2 million of other net adjustments. Bank net debt equals net

debt of $3.5 billion, less $13 million of advance mining royalties, plus $187 million of net letters of credit

related to firm transportation obligations, mining equipment leases and insurance policies.

43

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) Coal monetizations reduced for announced $101 million of coal asset related divestitures announced on 10/6/2015.

(2) Potential asset divestiture opportunities are as of 10/27/2015.

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

- In early Oct. announced $101 million of divestitures of non-core coal assets with projected 2016 EBITDA of

$6 million, a nearly 17x multiple

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(1) $300 - $500

Gas 1,000 - 1,400

Surface 50 - 100

Midstream 100 - 200

Total(2) $1,450 - $2,200

Legacy liabilities reduced and cash servicing costs reduced by more than 60%

since 2012, with further reductions expected going forward

44

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 9/30/15 balance represents

forecasted cash payments to service the legacy liabilities for FY 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 9/30/2015 12/31/2015E FY15E / FY14 %

Legacy Liabilities ($MM)

LTD $39 $20 $22 $21 $20 ($2) (8%)

WC 180 85 90 89 85 (5) (6%)

CWP 184 121 126 126 119 (7) (6%)

OPEB 3,018 1,022 761 696 662 (99) (13%)

Salary Retirement/Pension 225 53 119 95 107 (12) (10%)

Asset Retirement Obligations 699 601 576 576 573 (3) (1%)

Total Legacy Liabilities $4,345 $1,902 $1,694 $1,603 $1,565 ($129) (8%)

Annual Legacy Liabilities Cash Servicing Cost (1) $370 $148 $153 $143 $107 ($10) (30%)

$4,345

$1,902 $1,694 $1,565

$370

$148 $153 $143

$107 $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 FY 2016E

An

nu

al C

ash

Se

rvic

ing

Co

st

Lega

cy L

iab

iliti

es

Projected $107MM Annual Cash

Servicing Cost for FY 2016, a

$46MM reduction from the year-

end 2014 run-rate of $153MM

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

45

CNXC: Organizational Structure and CNX Ownership

Financial: CNX Coal Resources LP (CNXC:NYSE)

In July 2015 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

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

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

operational control over, CONSOL Energy’s 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.

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

(in millions except for per unit amounts)

Total LP Units held by CONSOL Energy 12.7

Unit Price (as of close on 10.20.2015) $12.19

CNXC Units Equity Value to CONSOL Energy $154.3

CONSOL Energy's Ownership Interest in CNX Coal

Resources LP (CNXC:NYSE)

$5

$8

$11

$10

$13

$15

$11$9

$4$4

$0

$4

$8

$12

$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

$4

$7

$10$9

$8$9

$0

$4

$8

$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

CONSOL owns 32.1% of CONE Midstream Partners LP’s

(CNNX:NYSE) 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

(“CGLLC”), a privately held Joint Venture between

CONSOL Energy (CNX:NYSE) and Noble Energy

(NBL:NYSE)

CNX’s share of CONE Midstream’s Net Income (CNNX &

CGLLC) flows into the E&P segment’s “Equity in Earnings

of Affiliates,” which in CNX’s consolidated financial

statements falls within the “Miscellaneous Other Income”

line item

Distributions run straight through CNX’s cash flow

statement in the “Return on Equity Investment” line item

CNX has seen increasing benefit from CONE’s EBITDA and

cash distributions, on top of which CNNX recently

increased its cash distribution 3.5% from its prior run-rate

46

Financial: CONE’s Growing Cash Contribution

Source: CONE Midstream Partners LP and CONSOL Energy Inc.

Net Income and EBITDA saw slight dips in 4Q14 and 1Q15 due to CNNX

IPO costs and temporary operational impacts from the unusually cold

winter. Subsequently, CONE has resumed its growth trend and action

has been taken operationally to limit weather impact in the future.

(in millions except for per unit amounts)

LP Units held by CONSOL Energy 19.1

Unit Price (as of close on 10.20.2015) $10.17

CNNX Units Equity Value to CONSOL Energy $194.3

CONSOL Energy's Ownership Interest in CONE

Midstream Partners LP (CNNX:NYSE)

47

Financial: Guidance Summary

Note: Guidance as of 10/27/2015.

(1) 4Q 2015 total production guidance of 92-97 Bcfe.

(2) Excludes land CapEx.

(3) Unutilized firm transportation, net equal to estimated unutilized firm transportation expense less estimated gathering revenue (resold firm transportation).

E&P Segment Guidance 2015E 2016E

Production Volumes:(1)

Natural Gas (Bcf)

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

Oil (MBbls) 85 - 95 102 - 114

Condensate (MBbls) 1,150 - 1,450 1,380 - 1,740

Total Production (Bcfe) 325 - 330

Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.55) ($0.40) - ($0.50)

NGL Realized Price ($/Bbl) $12.00 - $13.00 $12.00 - $14.00

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 Expense $60.0 - $60.0 $50.0 - $55.0

Unutilized Firm Transportation Expense, net:(3)$19.0 - $20.0 $15.0 - $16.0

~285 ~20%

~20%

48

Financial: Guidance Summary

Note: Guidance as of 10/27/2015.

Coal Segment 2015E 2016E

Total Coal Operations

(in millions of tons)

Estimated Total Coal Sales Volumes 28.9 - 29.9 30.6 - 33.4

Total Committed Volumes (Contracted & Priced) 28.6 20.2

% Committed 97% 63%

Estimated Total Average Price ($/Ton) $57.00 - $59.00 $50.00 - $55.00

Capital Expenditures:

($ in millions)

Production $130 - $140 $140 - $155

Other (Land/Water/Safety/Terminal) 60 - 70 30 - 35

Total Coal CapEx $190 - $210 $170 - $190

Average per unit operating expenses: ($/Ton)

Total Production Costs (including DD&A) $41.61 - $45.36 $41.44 - $44.98

Depreciation, Depletion and Amortization $6.81 - $7.33 $6.35 - $6.44

Other Expenses: ($ in millions)

General and Administrative $25 - $30 $20 - $25

Other Corporate 2015E 2016E

Divestitures ($MM) $75 - $125

49

Milestones:

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 and Switz 6D), on target for additional Utica results in 4Q 2015 –

sets up future stacked pay opportunities

Asset monetizations off to strong start, multiple processes still underway

- Continued focus on zero-based budgeting – expecting significantly reduced costs and improved balance sheet

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

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

- 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

NAV/share.

Plans and Goals Aligned to Drive Increased Valuation

We will continue to be focused on increasing shareholder value while staying within

our core values of safety, compliance, and continuous improvement

Financial: Summary

50

Appendix

51

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

Appendix


Three Months Ended Twelve Months Ended

September 30

($ in thousands) 2015 2014

Net Income / (Loss) $125,470 ($1,645)

Add: Interest Expense 48,558 55,397

Less: Interest Income (361) (527)

Add: Income Taxes (Benefit) 58,143 (1,388)

Earnings Before Interest & Taxes (EBIT) from Continuing Operations 231,810 51,837

Add: Depreciation, Depletion & Amortization 152,989 148,673

Earnings Before Interest, Taxes and DD&A (EBITDA) $384,799 $200,510

Adjustments:

OPEB Plan Changes (100,947) -

Unrealized Gain on Commodity Derivative Instruments (99,138) -

Gain on sale of Western Allegheny Energy (48,468) -

Severance Expense 7,683 -

Pension Settlement 3,132 4,785

Loss on Debt Extinguishment - 20,990

Long-term Liability Plan Changes - 10,100

Total Pre-tax Adjustments ($237,738) $35,875

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $147,061 $236,385

Less: Noncontrolling Interest* ($11,092) -

Adjusted EBITDA Attributable to CONSOL Energy Shareholders $135,969 $236,385

52

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

Appendix


Twelve Months Ended

September 30

($ in thousands)

Net Income / (Loss) ($325,135)

Add: Interest Expense 203,212

Less: Interest Income (2,344)

Add: Income Taxes (Benefit) (253,357)

Earnings Before Interest & Taxes (EBIT) from Continuing Operations (377,624)

Add: Depreciation, Depletion & Amortization $613,600

(Loss) Earnings Before Interest, Taxes and DD&A (EBITDA) $235,976

Adjustments:

Impairment of E&P Properties 828,905

OPEB Plan Changes (134,596)

Unrealized gain on Commodity Derivative Instruments (134,206)

Gain on Sale of Non-core Assets (68,298)

Blacksville Fire Settlement (9,750)

Backstop Loan Fees 7,334

Other Transaction Fees 4,968

Severance Expense 7,683

Pension Settlement 6,735

Loss on Debt Extinguishment 67,751

Total Pre-tax Adjustments $576,526

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $812,502

Less: Noncontrolling Interest* ($11,092)

Adjusted EBITDA Attributable to CONSOL Energy Shareholders $801,410

2015

53

Joint Ventures

(1) CONSOL holds ~89,023 net acres outside of the Marcellus JV. As of 12/31/2014.

(2) CONSOL holds ~40,592 net acres outside of the Utica JV, which includes ~13,000 net acres in Monroe County, OH. As of 12/31/2014.

(3) The remaining carry balance on a cash basis is $1.62 billion for Marcellus and $54 million for Utica, respectively. Utica carry has an accrued cash balance of

$14 million as of end of 3Q 2015.

(1) (2)

(3) (3)

Description Marcellus / Noble Energy Inc. Utica / Hess Corporation

Ownership 50/50 50/50

Acreage 350,904 76,132

Zones PA and WV Marcellus, Burkett to Onondaga OH Utica

Carry

Noble to pay 1/3 of CNX 50% share of eligible

charges

Maximum annual payment of $400 million per year

Henry Hub spot price averages over $4.00 per

month for three consecutive months

Hess to pay 50% of CNX 50% share of eligible

charges (i.e. CNX pays 25%)

Total carry amount $1.85 billion, of which $1.62 billion remains as of

end of 3Q15

$335 million, of which $40 million remains as of end

of 3Q15

Carry eligible* Capital - D&C, facilities, site construction Capital - D&C, facilities, site construction, seismic

Non-carry eligible

(pay straight WI %) LOE, leases, delay rentals, seismic LOE, leases, delay rentals

Summary of JV Carry Eligible Capital

Appendix

54

~441,000 CONSOL net

acres

─ ~88% NRI

─ ~91% HBP

23.9 Tcfe 3P

Over 8,900 gross potential

wells(1)

~93% Marcellus

production growth in 2014

compared to 2013

Liquids growth from 2% in

2013 to 8% of total

production in 2014

Producing Pads


(1) Based on 5,000 ft laterals with 86-acre spacing.

Marcellus Shale: Overview

Appendix

55

Marcellus Shale: Offset Peer Acreage

Appendix

Notes: CNX acreage position as of 12/31/2014. CNX acreage shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres.

Source: Third party acreage positions based on GIS data from Western Land Services.

56

Total Gross Prospective Marcellus Acreage ~790,000

- Gross Acres within JV ~701,000

- Acres outside JV – 100% CONSOL ~89,000

Acreage per well (assumed 750 ft spacing) ~86

Gross Producing wells (JV - YE2014) 384

Gross PDNP and PUD locations (YE2014) 828

Gross prospective unproved locations ~8,000

Producing wells as % of PDNPs, PUDs, and prospective locations 4%

Note: As of December 31, 2014 unless otherwise noted.

~490 MMcfe/d net being produced from ~4% of net Marcellus acreage

Marcellus Shale Upside Potential

Marcellus Shale: Growth Runway and Depth of Inventory

Appendix

57

Marcellus Shale

SWPA CPA WV Ohio(1) North

Wet

South

Wet Total

Net Acres ~45,000 ~110,000 ~117,000 ~13,000 ~54,000 ~102,000 ~441,000

Approximate

Gross

Locations(2)

800 2,000 2,400 100 1,400 2,200 ~8,900

Avg

EURs/1,000 ft

(Bcfe)

2.1 1.6 1.8 -- 1.8 2.1 --

Marcellus Shale is the main growth driver of the E&P Division

Marcellus Shale: Sub-Regions Summary

Note: Acreage as of December 31, 2014 unless otherwise noted.

(1) Non-JV acreage is located in Monroe County, OH.


Appendix

58

Appendix Marcellus Shale: Southwest PA Overview



~45,000 CONSOL net

acres

Over 800 gross locations(1)


9/30/2015


─ 7,002 ft average TIL

laterals in Q3 2015


average in 2015


(assuming 8,800 ft

lateral)

2.1 Bcfe EUR/1,000 ft of

lateral

750 ft inter-lateral spacing

NV36 Pad

7 Wells

5,021’ Avg Lateral Length per well

6,159 Mcfe Avg 30-day IP per well

MOR10 Pad

6 Wells



Producing Pads

Competitor Pads

NV56 Pad

6 Wells



NV57 Pad

8 Wells



59

Appendix Marcellus Shale: North Wet Gas Overview



WFN3 Pad

4 Wells



4,800 MMcf/d 60-day IP per well

~54,000 CONSOL net

acres

Over 1,400 gross

locations(1)

─ 139 wells online as of

9/30/2015


─ 8,038 ft average laterals

in Q3 2015


average


(assuming 7,900 ft

lateral)


lateral

Increasing use of

RCS/SSL


Condensate yield: 5

Bbls/MMcf

NGLs yield: 49 Bbls/MMcf

WFN6 Pad

8 Wells


8.5 MMcf/d Avg 24-hour IP per well

6,800 MMcf/d 60-day IP per well

Producing Pads

Competitor Pads

SHL13 Pad

7 Wells



SHL23 Pad

5 Wells



60

Appendix



DAVIES (EQT)

7 Wells


487 MMcf/well – 1st 6-Month Cum

1562 Bbl/well – 1st 6-Month Cum

HARPER (EQT)

3 Wells




WEESE (Triad Hunter)

3 Wells




~102,000 CONSOL net

acres

Over 2,200 gross

locations(1)


9/30/2015


average


(assuming 8,100 ft

lateral)


lateral


Condensate yield: 10

Bbls/MMcf

NGLs yield: 51 Bbls/MMcf

PENS1 Pad

9 Wells

~6,824’ Avg Lateral Length per well

Marcellus Shale: South Wet Gas Overview

SHR1 Pad

6 Wells

~8,741’ Avg Lateral Length per well


PENS2 Pad

12 Wells

Currently under flowback

OXF1 Pad

6 Wells

~6,353 Avg Lateral Length per well


Producing Pads

Competitor Pads

DTI Storage Fields

61

Marcellus Shale: Northern WV Dry Overview

PHL4 Pad

3 Wells



720 MMcf/well – 1st 6-month Cum

ANDERSON (PDC Mountaineer)

3 Wells



~117,000 CONSOL net

acres

Over 2,400 gross

locations(1)


9/30/2015


─ 6,787 ft average laterals

in Q3 2015


(assuming 6,800 ft

lateral)


lateral




AUD3 Pad

1 Well Delineation




CENT3 Pad

1 Well Delineation


4,973’ Mcfe Avg 30-day IP per well


PHL13 Pad

6 Wells




Producing Pads

Competitor Pads

DTI Storage Fields

AUD7 Pad

1 Well Delineation



PHL10 Pad

6 Wells



Appendix

62

Marcellus Shale: Central PA Overview

GAUT4 Pad

4 Wells




COOK (Atlas/Chevron)

2 Wells



GREENAWALT (Chevron

Appalachia)

3 Wells



SMITH (Atlas/Chevron)

2 Wells



~110,000 CONSOL net

acres

Over 2,000 gross

locations(1)


9/30/2015


average


(assuming 6,900 ft

lateral)


lateral




KUHNS3 Pad

5 Wells




SHAW Pad

3 Wells


7,817 Mcfe Avg 24-hr IP per well

523 MMcf/well – 1st-4-month Cum

MMS Pad

5 Wells



636 MMcf/well – 1st-4 month Cum

Producing Pads

Competitor Pads

CRAWFORD 5 Pad

2 Wells


13,586 Mcfe Avg 24-hr IP per well

624 Mmcfe/well – 60 day Cum

MARCHAND 3I Well

6,418’ Lateral Length

735 Mmcfe – 150 day Cum

Appendix

63 Notes: PA and WV prospective Utica eastern boundary has yet to be delineated. Acreage is risked 50+% in PA and WV. Acreage in Ohio oil window is excluded after risking.

As of December 31, 2014 unless otherwise noted.

~1% of net Utica acreage developed to date

Utica Shale Upside Potential

Utica Shale: Growth Runway and Depth of Inventory

Total Gross Prospective Utica Acreage ~690,000

- Gross Acres within JV ~153,000

- Acres outside JV – 100% CONSOL ~537,000

Acreage spacing per well (assumed 750 ft spacing) ~86

Gross Producing wells (JV - YE2014) 44

Gross PDNP and PUD locations (YE2014) 88

Gross prospective unproved locations ~3,000

Producing wells as % of PDNPs, PUDs, and prospective locations ~1%

Appendix

64

Potential resource of ~30 Tcfe

Note: Acreage as of December 31, 2014 unless otherwise noted.


Utica Shale

Ohio Wet Ohio Dry PA/WV Dry Total

Net Acres ~88,000 ~30,000 ~496,000 ~614,000

Approximate Gross

Locations(1) 500 300 2,200 3,000

Avg EURs/1,000 ft

(Bcfe) 2.1 2.4 2.4 --

Utica Shale: Sub-Regions Summary

Appendix

65

~614,000 CONSOL net

acres in Utica

─ ~302,000 net acres in

PA

─ ~194,000 net acres in

WV

─ 30,000 net acres in OH

Dry

~13,000 net acres in

Monroe County, OH

─ 88,000 net acres in OH

Wet

Majority of acreage

offset to peers with

strong results

─ The main area without

offset results was

Westmoreland County

where CNX drilled the

Gaut 4IH which had the

2nd highest IP in the

Utica to date

Utica Shale: Offset Peer Acreage

Appendix

Notes: CNX acreage position as of 12/31/2014. CNX acreage shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres.

Source: Third party acreage positions based on GIS data from Western Land Services.

66 Note: Peer data based on publicly available information. CONSOL wells are 24-hour IP rates. Other producers’ IP rates may be different. Townships shown in yellow where CONSOL holds

3,000 or more acres (as of 12/31/2014).

Utica Shale: CNX Acreage Position in the Core OH Wet Gas Utica

Appendix

CNX - NBL 18

IP GAS: 8,213 Mcf/d per well

IP OIL: 834 Bbl/d per well

CNX - NBL 30



GPOR - Boy Scout 33H

IP GAS: 5,300 Mcf/d

IP OIL: 1,560 Bbl/d

CHK - Buell 8H

IP GAS: 9,500 Mcf/d

IP OIL: 1,425 Bbl/d

GPOR - Wagner 1-28H

IP GAS: 14,000 Mcf/d

IP OIL: 432 Bbl/d

AR - Miley 5HA

IP GAS: 7,700 Mcf/d

IP OIL: 1,285 Bbl/d

GPOR - Shugert 1-12H


IP OIL: 300 Bbl/d

HES – Cadiz A

IP GAS: 8,006 Mcf/d

IP OIL: 399 Bbl/d

REXX - Guernsey 2H

IP GAS: 8,082 Mcf/d

IP OIL: 564 Bbl/d

GPOR - Irons 1-4H


IP OIL: 0 Bbl/d

CNX - NBL 16A


IP OIL: 750 Bbl/d

CNX - NBL 19



CNX - NBL 16B

IP GAS: 5,630 Mcf/d

IP OIL: 522 Bbl/d

HES – Cadiz B


IP OIL: 191 Bbl/d

HES – Athens A

IP GAS: 7,745 Mcf/d

IP OIL: 330 Bbl/d ~34,000 net core wet acres

17% of liquid hydrocarbon sweet spot controlled by CONSOL JV

~88,000 CONSOL net acres

~34,000 CONSOL net acres

in core

Type curve reflects core

area

Over 500 gross core area

locations(1)


9/30/2015

─ 11 wells online in Q3 2015

─ 7,525 ft average laterals in

Q3 2015

─ 4-5 wells per pad on

average


(assuming 7,000 ft

laterals)


lateral

RCS/SSL standard for new

drills


67

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

Note: Townships shown in yellow where CONSOL holds 3,000 or more acres (as of 12/31/2014).

68

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

454,000

155,000

265,000

946,000

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

69

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 6.8 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

70

Appendix

Source: CONE Midstream Partners LP.

CONE Corporate Structure

71

Coal Division: Low-cost, Highly Productive Longwall Mining Operations

The design of the Pennsylvania mining complex is optimized to

produce large quantities of coal on a cost efficient basis.

Pittsburgh No. 8 coal seam is a large, continuous formation of

uniform, high-Btu thermal coal that is ideal for high productivity,

low-cost longwall mining operations.

Highly automated and technologically advanced underground mining operation (1) Includes FELP, ARLP, RNO and WMLP as reported in the respective 10-K filings.

(2) Including transportation costs for FELP.

$25.27

$11.80

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

PA Mining Complex Other Coal MLP's (incl. transp. cost)

2014 Average Cash Margin

($ /ton)

(1) (2)

Longwall Mining

CNXC

Other NAPP Other

Coal MLPs

ILB

PRB

8,000

10,000

12,000

14,000

Btu Content

CNXC

Other Coal MLPs

ILB

Other NAPP

0.00%

0.40%

0.80%

1.20%

1.60%

2.00%

2.40%

2.80%

3.20%

3.60%

Sulfur Content

Advantaged Coal Characteristics

(1)

(2)

(2)

(1)

(btu/lb)

(1)

(1)

(1)

During 2014, the PA mining complex generated the

highest cash margin of any of our coal peers (1)(2)

Appendix

Documents

Company Presentation - CNX Resources Corporationinvestors.cnx.com/~/media/Files/C/CNX-Resources-IR/... · 2018. 6. 8. · Earnings per Diluted Share $0.52 ($0.01) $0.53 $0.52