Company Presentation - CNX Resources...

Company Presentation Q2 2016

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 are included in our

earnings release, and include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we

expect to receive for our natural gas and coal; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately

estimate our economically recoverable natural gas, oil and condensate; we may encounter unexpected operational issues when we drill and mine, including

equipment failures, geological conditions and higher than expected costs for equipment, supplies, services and labor; we may not achieve the efficiencies we

expect to realize in our drilling and completion operations, and as a result, our projected cost savings may not be fully realized; our joint venture partners,

who operate assets in which we have a significant interest, may not perform as we expect; we may not be able to sell non-core assets on acceptable terms;

we may be unable to incur indebtedness on reasonable terms; failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its

obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash

flows; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - disruption to our business, including

customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results; and other

factors, many of which are beyond our control. Additional factors are described in detail under the captions "Forward Looking Statements" and "Risk Factors"

in CONSOL Energy Inc.’s annual report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission (SEC), as

updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this

presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly.

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company

anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We

may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules

strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may

be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of

reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from

aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is

customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform

curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or

otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the oil and gas rights we

control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells.

This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP.

Coal-E&P Revenue Split, 2012

E&P Revenues

Coal Revenues

3

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

December 5, 2013 – transaction with Murray Energy Corp. in which we sold half

of coal assets and related assets

April 19, 2014 – CONSOL Energy 150th Anniversary

June 12, 2014 – Analyst Day to roll out growing Appalachian E&P Division with

best in class coal assets

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

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

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

Westmoreland County

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

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

Coal-E&P Revenue Split, 2014

E&P Revenues

Coal Revenues

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

E&P Revenues

Coal Revenues

4

E&P Division

5

E&P Division: Q2 2016 Operations Summary

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length

(ft)

Counties

Southwest

PA ---- ---- ---- 16 7,100

Greene,

Washington,

Allegheny, PA

Central PA ---- ---- ---- ---- ----

Indiana,

Westmoreland,

PA

Northern

WV Dry ---- ---- ---- ---- ----

Barbour,

Doddridge,

Lewis, WV

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

North Wet

Gas ---- ---- ---- ---- ----

Greene,

Washington,

PA; Marshall,

WV

South Wet

Gas ---- ---- ---- ---- ----

Doddridge,

Tyler, Ritchie,

WV

Total 0 0 0 16 7,100

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length (ft)

Counties

Core Wet ---- ---- ---- ---- ---- Noble, OH

Surrounding

Core Wet ---- ---- 2 5 6,955

Harrison,

Belmont, OH

Dry Utica ---- ---- ---- ---- ----

Monroe, OH;

Marshall, WV

Westmoreland,

Greene, PA

Total 0 0 2 5 6,955

Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary

E&P Operations

Completion update

─ Dual Fuel: Projecting a ~65% substitution rate for diesel fuel.

─ Plugless Completions: Currently performing a second

plugless completion test on GH58 pad. Continuing efforts to

eliminate post frac intervention and improve economics.

─ Balance: Completing DUC’s in our best areas. Exercising

discipline in regards to stage size and scheduling to deliver

wells on time AND avoid production water disposal.

Production update

─ Operational Improvement: Through our compressor

consolidation project we have realized $806k in operating

expense savings YTD.

─ Lease Operation Strategy: Implementation of additional

operational efficiencies and rebidding our Marcellus & Utica

contract well tending will yield a savings of $737k for the second

half of 2016.

─ Production Optimization: Workovers, production tubing installs,

and artificial lift opportunities yielded 0.823 Bcfe uplift in 2016

which results in an additional $1.14 million gross income

─ Production Highlights:

SWITZ-6 pad: Yielded a Q2 average daily rate of 56.6 MMcf/d

with an impressive 15 psi/day managed pressure decline

GAUT-4I: Cumulative production for Q2 totaled 1.65 BCF while

averaging an 17 psi/day pressure decline

Marcellus: During Q2, the top 3 SWPA Marcellus pads

combined averaged a rate of 260 MMcf/d from 140k lateral feet

6

2016 Planned E&P Activity Overview

E&P Activity Summary – 2016 Plan

E&P Operations

Note: Plan as of 6/30/2016. Average net revenue interest for Marcellus/Utica shales is 43.7%. Table includes one 100% CONSOL-owned wells: a dry Utica Shale well in Monroe

County, Ohio.

Implied inventory exiting 2016 anticipated to consist of 91 Marcellus and Utica

Shale Wells, including 10 new wells expected in 2016

Expected New

Wells Drilled in

H2 2016

Drilled

Uncompleted

Inventory

Drilled

Completed

Inventory

2016 TIL's

Remaining

Implied

2017

Inventory

2016

Completions

Remaining

Marcellus

SW PA Operated 2 18 1 7 14 6

SW PA Non-Op - 5 2 - 7 -

WV Operated - 7 - - 7 -

WV Non-Op - 49 - - 49 -

Total Marcellus 2 79 3 7 77 6

Utica

SW PA Operated - - - - - -

OH Operated 8 1 - - 9 -

OH Non-Op - 5 - - 5 -

Total Utica 8 6 - - 14 -

Total Gross Marcellus/Utica

Wells 10 85 3 7 91 6

E&P Operations

7

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: Guidance as of 7/26/2016. Production volumes reflect the mid-point of their contribution to the 2016 production guidance ranges.

Source: Company filings and estimates.

329 (50)

235

75 380-385

0

50

100

150

200

250

300

350

400

450

2015 Total Production 2016 Base decline 2016: Gathering De-bottlenecking

2016: Non-Op (Ex NBL/HES)Prod. Adds

2016: Production Adds 2016 Total Production

Bcfe

8

Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth

E&P Operations: Capital Expenditures

Base case now assumes drilling 10 new wells in 2016, while reducing capital

under low-end of previous E&P capital guidance of $205-$325 million

Deferring activity, increasing capital efficiency

improvements and identification of additional de-

bottlenecking activities

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

- Drilling and Completion: $140-$145 million

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

- Midstream of $34-$39 million (including approximately $22

million associated with CONE Midstream capital

contributions)

- Other activities (land, permitting, and business development):

$17-$22 million

2016 E&P Capital Budget:

$190-$205 Million

$0.23 $0.38 $0.24 $0.16

$1.10$1.02

$1.04$0.93

$0.17 $0.17$0.09

$0.09

$0.84 $0.59

$0.37

$0.26

$1.17

$1.11

$0.82

$0.48

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

2013 2014 2015 2016E

SG&A Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE

9

Full-cycle Breakeven Operating Metrics Declined from $3.51 to $1.92 Per Mcfe, a 45% Projected Decline

E&P Operations - Benchmarking vs Peers

Exceeded cost reduction target of 15% in 2015 with a 22% reduction from 2014

and projecting an additional 25% reduction from 2015

Cash OpEx

(plus G&A) of

$1.28/Mcfe,

plus PUD-to-

PDP CapEx of

$0.48/Mcfe,

equals total full

cycle cash

costs of

$1.92/Mcfe

Hired Tim Dugan to run E&P operations

As of YE 2015 A B C D E F G Wtd. Avg. CNX

E&P Per Unit Future PUD F&D ($/Mcfe) $0.60 $0.75 $0.91 $0.41 $0.48 $0.69 $1.33 $0.79 $0.48

Note: 2016E reflects midpoint of guidance range. Numbers may differ slightly due to rounding.

Source: Company filings and presentations. Peers include AR, COG, EQT, GPOR, RICE, RRC and SWN.

66

62

46

37

30 29 2927

2524

2321

19 19 19 1917 17

15 14

10 10 10 10 97

6 6

0

10

20

30

40

50

60

70

No

rmal

ized

Asq

rt(K

), m

d^1

/2*

ft

Well

10

Utica Success Normalized Well-to-Well Productivity Comparison

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

𝐀√k: A measure of the strength of a well that normalizes for:

• Lateral length

• Stage spacing

• Pressure management

This benchmark metric enables comparison between wells

more accurately than traditional IP testing

*

* Non-Operated well.

‘A’ represents the area in square feet of the contributing hydraulic fracture we create

‘k’ is the permeability in milliDarcy (md) or the ability of the reservoir-hydraulic fracture system to flow gas

104 wells in current Earth Model – 28 wells with production data

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0

5,000

10,000

15,000

20,000

25,000

30,000

9/23/15 1/1/16 4/10/16 7/19/16 10/27/16 2/4/17

Flow Rate MCf/Day Casing Pressure

The Gaut 4IH well has produced 4.4 Bcf through June 30, 2016, while average

flowing casing pressure remains strong at approximately 6,100 psi 11

Utica Shale: Gaut 4IH Westmoreland County, PA

Expected to produce at flat rate for approximately 400 days until hitting line pressure in February 2017

Establishing reaction to reaching line pressure based on extensive JV / NonOp / Partner data set of 28 wells

We are following a managed pressure drawdown where we are currently dropping pressure at 20 psi/day

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

Expected to CUM 8.4 BCF at

the time it hits line pressure

12

Dry Utica: Switz 6 Pad Monroe County, OH

The Switz 6 pad produced 10.8 Bcf through June 30, 2016 while average flowing

casing pressure remains strong at approximately 4,000 psi

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

6F Gas Rate (Mcf/d) 6F Casing Pressure (psig)

6D Gas Rate (Mcf/d) 6D Casing Pressure (psig)

6H Gas Rate (Mcf/d) 6H Casing Pressure (psig)

• Increased type curve from 2.4 – 2.8 Bcf/1,000’

• Evaluating proppant test for use on next pads

$510

$540

$340

$320

$230 $190

$0

$100

$200

$300

$400

$500

$600

Switz 6B Switz 6D Switz 6H Switz 6F Switz 16J Switz 16D Expected

Dri

llin

g C

ost

($

/ft.

)

Switz Drilling Cost/Ft.(Wells in order of Tophole TD)

0

5,000

10,000

15,000

20,000

25,000

0 20 40 60 80 100 120

DM

easu

red

ep

th (

ft.)

Days

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

SWITZ6B

SWITZ6F

SWITZ6H

SWITZ6D

SWITZ16J

SWITZ16D Expected

Realized ~55% Reduction in Drilling Costs

13

Utica Shale: Monroe Cty, OH Cost Improvements

Accelerating rate of change in CONSOL’s efficiency improvements: In Monroe

County, OH reduced Dry Utica drilling costs by 55% from the 1st well to the 5th

Realized ~60+% Reduction in Days to Drill

Expect Additional

~8% Reduction

Expect Additional

~16% Reduction

14

Utica Shale: PA Utica D&C Cost Reduction Plan

$12.4

(0.8)

$26.2 (8.2)

(2.2)

(0.4)(1.2) (1.1)

$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 may not sum due to rounding.

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

(2) Actual costs may vary from AFEs.

(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/AFE (2) $26.2 Initial - Drilling & Completion Cost on Gaut 4I

Cost Reductions:

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

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

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

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

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

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

Total Reductions(3) (13.8)

Development Well AFE(3) $12.4

15

Gas Marketing

CONSOL basin exports are projected to increase approximately 73,000 Dth /day for FY 2016 over FY 2015 as

TETCO’s U2GC and TEAM OPEN projects were put into service in late 2015, increasing expected realizations by

marketing gas to the higher priced Midwest and Gulf Coast markets

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

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

─ The deals, the first of which commenced in April, are expected to yield price premiums compared with in-basin pricing

and expose a portion of the company’s LPG portfolio to Brent Crude linked pricing

Q2 2016 natural gas price reconciliation:

16

E&P Marketing

Q2 2016 Gas Realization and Marketing Highlights

2015

Q2 Q1 Q2

NYMEX natural gas ($/MMBtu) 1.95$ 2.09$ 2.64$

Average differential (0.46) (0.36) (0.68)

BTU conversion (MMBtu/Mcf)* 0.09 0.10 0.07

Gain on commodity derivative

Instruments-cash settlements 0.91 0.98 0.64

Realized gas price per Mcf 2.49$ 2.81$ 2.67$

*Conversion factor 1.06 1.06 1.04

2016

Targeting FT opportunities 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

Stacked pay opportunities will

help optimize FT portfolio

17

Gas Marketing Firm Transportation

Low average demand costs of $0.24 to $0.29/Dth reflect a well balanced portfolio

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

Charts also include transportation under precedent agreements

FT Capacities

Pipeline (MMcf/d) YE 2016 YE 2018

ANR Pipeline 47 47

Columbia (TCO) 215 514

Dominion (DTI) 370 342

East Tennessee 282 202

Nexus - 150

TETCO 174 174

TETCO (via firm sales) 285 125

1,373 1,554

0.24 0.24

0.28 0.29

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

2016 2017 2018 2019

Avg Demand per MMBtu

TETCO

TETCO (via firm sales)

Dominion

East Tennessee

Columbia

ANR

NEXUS

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Jan 16 Jan 17 Jan 18 Jan 19

1000S

MM

Btu

/da

y

18

Gas Marketing

TETCO M2

TETCO M3

TCO Pool

Dominion South

East Tennessee

TETCO ELA

Midwest

Gas Sales CY 2016 Est.

Columbia (TCO) 19%

TETCO (M2) 26%

TETCO (M3) 16%

Dominion (DTI) 14%

East Tennessee 12%

TETCO ELA & WLA 8%

Midwest (Chicago) 5%

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

Contracted capacity meets

current requirements

─ Inlet wet gas volumes to

processing plants were ~105

MMcf/d above CONSOL’s

aggregate minimum

committed volume in Q2 2016

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

19

Gas Marketing Natural Gas Processing

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

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

0

50

100

150

200

250

300

350

400

450

500

Jan 16 Jan 17 Jan 18 Jan 19

MM

cf/

da

y

MVC

20

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

(2) At the midpoint of production guidance.

(3) Hedge positions as of 7/13/2016.

Gas Hedges

Gas Marketing: 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

Since 3/31/16, added

approximately 120 Bcf of

NYMEX gas hedges and 170

Bcf of basis hedges through

2020, further protecting

downside

Approximately 70% of total

FY 2016E production

volumes hedged(2)

Q3 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020

NYMEX + Basis(1)

Volumes (Bcf) 72.1 263.6 187.1 108.5 20.6 6.9

Average Prices ($/Mcf) $2.79 $3.04 $2.61 $2.69 2.46 2.63

NYMEX Only Hedges Exposed to Basis (Bcf)

Volumes (Bcf) - - 37.1 41.6 62.6 20.7

Average Prices ($/Mcf) - - $3.01 $3.10 $3.03 $3.19

Physical Sales With Fixed Basis Exposed to NYMEX

Volumes (Bcf) 3.5 4.9 - - - -

Average Hedged Basis Value ($/Mcf) ($0.29) (0.09)$ - - - -

Total Volumes Hedged (Bcf)(3) 75.6 268.5 224.2 150.1 83.2 27.6

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

3Q 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020

Gas V

olu

mes H

ed

ged

(B

cf)

Physical Sales With Fixed Basis Exposed to NYMEX

NYMEX Only Hedges Exposed to Basis

NYMEX + Basis(1)

21

Ethane 64%

Propane 22%

I-Butane 3%

N-Butane 6%

Natural gasoline

5%

Maximum

Ethane

Recovery*

Potential

Scenario

* Assumes 85% ethane recovery level

Ethane 26%

Propane 41%

I-Butane 5%

N-Butane 15%

Natural gasoline

13%

2Q16 Est NGL Sales

Comp

CONE Gathering and Midstream systems provide CONSOL unique flexibility to

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

Marcellus ethane rejection or (b) extract ethane when accretive

Gas Marketing: Liquids Realizations Natural Gas Liquids, Oil, and Condensate

Q2 2016 Avg. “NGL Barrel” Composition

Q2 2016 liquids sold: 10.6 Bcfe

Total weighted average price of liquids increased

~23% to $15.73 per Bbl in Q2 2016 from $12.78 per

Bbl in Q1 2016

Liquids comprised approximately 11% of Q2 2016

production volumes, 11% of E&P sales revenue and

10% of total Company revenue

Added 12.7 million gallons of propane hedges from

April of 2016 through March of 2017 at an average

price of $0.47 per gallon

Average price realization (per Bbl):

Q2 Q1 Q2 Q1

NGLs $12.84 $12.30 $12.48 $20.40

Oil $33.72 $30.84 $46.14 $47.82

Condensate $31.68 $14.64 $31.26 $20.82

20152016

22

Financial

23

Debt and Liquidity Profile

Financial: Liquidity (Cont’d)

Note: Some numbers may not match exactly to financial statements due to rounding.

(1) The 2022 and 2023 senior notes includes $5 million and $6 million of unamortized bond premium / discount, which will be amortized over the life of the notes, respectively.

(2) Total Debt of $3.257 billion includes discontinued operations and excludes total unamortized debt issuance costs of $30 million.

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

(4) As of 6/30/2016, CNX had approximately $466 million of borrowings and $309 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,225 million of

availability. CNXC had $198 million outstanding on its revolving credit facility leaving approximately $202 million of availability.

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

(5) Number of MLP units owned by CNX as of 6/30/2016 and unit prices as of market close on 7/19/2016.

(6) CNX Coal Resources liquidity data is as of 6/30/2016 and CONE Midstream data is as of 3/31/2016.

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

reconciliation is provided in the Appendix. Bank methodology EBITDA equals Adjusted EBITDA of $679

million plus gain on sale of assets of $42 million, plus gain related to changes in retiree medical (OPEB)

plan of $211 million, less the $69 million of CNXC EBITDA Attributable to CNX, plus the $39 million of

CNXC cash distributions to CNX, less $18 million of other net adjustments. For a reconciliation of CNXC’s

EBITDA please see the Company’s form 10Q’s and 10K’s. Bank net debt equals debt of $3.059 billion, less

$89 million cash on hand excluding CNXC’s cash, less $3 million of advance mining royalties, plus $241

million of net letters of credit related to firm transportation obligations, mining equipment leases and

insurance policies, less $2 million of debt for discontinued operations.

CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 6/30/2016 6/30/2016 6/30/2016

Capitalization

Cash and Cash Equivalents $98 $9 $89

Revolving Credit Facility Balance 664 198 466

Capital Lease Obligations 38 - 38

Total Secured Debt $702 $198 $504

8.25% Senior Notes due 2020 $74 - $74

6.375% Senior Notes due 2021 21 - 21

5.875% Senior Notes due 2022 (1) 1,855 - 1,855

8.0% Senior Notes due 2023 (1) 494 - 494

Baltimore 5.75% Revenue Bonds due 2025 103 - 103

Miscellaneous Debt 8 - 8

Total Debt (2) $3,257 $198 $3,059

Net Debt (3) $3,159 $189 $2,970

Stockholders’ Equity $4,271 $146 $4,125

Total Capitalization $7,528 $344 $7,184

Liquidity

Cash and Cash Equivalents $98 $9 $89

Revolving Credit Facility Capacity (4) 1,427 202 1,225

Total Liquidity $1,525 $211 $1,314

Equity Value of Ownership in

Affiliated Public MLPs

CNX

Owned LP

Units(5)

Unit

Price(5)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 12.7 $10.90 $138

CONE Midstream Partners LP (CNNX:NYSE) 19.1 $17.00 $325

Total Equity Value of Ownership Interests in Affiliated Public MLPs $463

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity of

Affiliates

CNX Coal Resources LP (6)

$400 $198 $202 $9 $211

CONE Midstream Partners LP (6)

$250 $74 $176 $14 $190

Total Liquidity of Affiliated

Public MLPs $650 $272 $378 $23 $401

Leverage Ratio 6/30/2016

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7)

$884

LTM Bank Net Debt / Adj. EBITDA (7)

3.6x

24

Financial: Daily Cash Management Report

CONSOL remains focused on cash management

($600)

($400)

($200)

-

$200

$400

$600

9/1/14 12/1/14 3/1/15 6/1/15 9/1/15 12/1/15 3/1/16

Cas

h B

ala

nce

($M

M)

Daily Cash Management Report

Cash Excluding CEI Debt Refinancing

1

2

3

4

5

Notes: • CONE MLP IPO

• Challenging bond refi

• Challenging CNXC MLP IPO

• We have stopped the cash burn during brutal pricing environment – cash stabilization wasn’t due to pricing, it was due to arresting spend.

• Buchanan sale included in ~$450MM jump.

1

2

3

4

5

$4,345

$1,902 $1,694 $1,542 $1,492 $1,374

$370

$148 $153 $137

$106

$0

$50

$100

$150

$200

$250

$300

$350

$400

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

FY 2012 FY 2013 FY 2014 FY 2015 Q2 2016 FY 2016E

An

nu

al C

ash

Se

rvic

ing

Co

st (

$ in

Mill

ion

s)

Lega

cy L

iab

iliti

es

($ in

Mill

ion

s)

Total Legacy Liabilities (left axis) Annual Legacy Liabilities Cash Servicing Cost (right axis)

As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 6/30/2016 12/31/2016E

Legacy Liabilities ($ in Millions)

LTD $39 $20 $22 $20 $19 $18

WC 180 85 90 83 82 81

CWP 184 121 126 123 127 126

OPEB 3,018 1,022 761 672 661 662

Salary Retirement/Pension 225 53 119 94 90 84

Asset Retirement Obligations 699 601 576 550 513 403

Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,492 $1,374

FY 2012 FY 2013 FY 2014 FY 2015 Q2 2016 FY 2016E

Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $137 $106

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

since 2012, with further reductions expected going forward

25

Significant Legacy Liability Reductions Over Past 3 Years

Financial: Legacy Liabilities

Projected $106MM Annual Cash

Servicing Cost for FY 2016, a

$31MM reduction from the year-

end 2015 run-rate of $137MM

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 DD&A

Flows through Other Segment in

“Miscellaneous Operating Expense”

26

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 7.19.2016) $10.90

CNXC Units Equity Value to CONSOL Energy $138.0

CONSOL Energy's Ownership Interest in CNX Coal

Resources LP (NYSE: CNXC)

$10$15

$29

$44

$56

$0

$10

$20

$30

$40

$50

$60

FY 2012 FY 2013 FY 2014 FY 2015 Last QtrAnnualized

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 32.7% of CONE Midstream Partners LP’s

(NYSE: 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

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 (NYSE: CNNX) and Noble Energy (NYSE:

NBL)

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 3.7% from 1Q16

27

Financial: CONE’s Growing Cash Contribution

Note: For a reconciliation of CONE’s EBITDA please see the CNNX’s form 10Q’s and 10K’s.

Source: CONE Midstream Partners LP and CONSOL Energy Inc.

(in millions except for per unit amounts)

Total LP Units held by CONSOL Energy 19.1

Unit Price (as of close on 7.19.2016) $17.00

CNNX Units Equity Value to CONSOL Energy $324.7

CONSOL Energy's Ownership Interest in CONE

Midstream Partners LP (NYSE: CNNX)

$50$62

$17

$18

$10 $15

$34

$68 $80

$0

$20

$40

$60

$80

$100

FY 2012 FY 2013 FY 2014 FY 2015 Last QtrAnnualized

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

Note: ($ in millions)

Note: ($ in millions)

28

Guidance

Note: Guidance as of 7/26/2016.

(1) Represents estimated unutilized firm transportation and processing expense less estimated gathering revenue (resold firm transportation).

E&P Segment Guidance 2016E

Production Volumes:

Natural Gas (Bcf) 338 - 342

NGLs (MBbls) 6,150 - 6,300

Oil (MBbls) 62 - 68

Condensate (MBbls) 850 - 900

Total Production (Bcfe) 380 - 385

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

NGL Realized Prices ($Bbl) $12.00 - $14.00

Condensate Realized Prices % of WTI 55% - 60%

Oil Realized Prices % of WTI 85% - 90%

Capital Expenditures ($ in millions):

Drilling and Completion $140 - $145

Midstream $34 - $39

Land and Other $17 - $22

Total E&P and Midstream CapEx $190 - $205

Average per unit operating expenses ($/Mcfe):

Lifting (including Direct Admin.) $0.24 - $0.28

Impact Fees/Ad Valorem/Production Taxes $0.08 - $0.10

Gathering, Transportation, Compression & Processing $0.91 - $0.95

Depreciation, Depletion and Amortization $1.04 - $1.07

Total Production and Gathering Cost $2.27 - $2.40

Other Expenses ($ in millions):

Selling, General and Administrative Costs $58 - $62

Unutilized Firm Transportation Expense, net:(1) $15 - $16

29

Guidance

Note: Guidance as of 7/26/2016.

(1) Includes estimated contribution from Miller Creek and Other Coal Operations for fiscal year 2016 and 1Q16 for Buchanan, and excludes Loss on Sale of Buchanan and the

expected Loss on Sale for the Miller Creek and Fola mines.

(2) Includes miscellaneous other income (net of applicable expenses) associated with the company's Terminal Operations, Rental Income, Coal Royalty Income, and other

miscellaneous land income.

(3) Includes Legacy Liability Costs of approximately $80-85 million; Other Coal-Related Corporate Expenses, and other miscellaneous items. Excludes stock-based compensation

and pension settlement charges.

Coal Segment Guidance 2016E

Estimated Total Consolidated Coal Division Sales Volumes (in millions of tons) 24.5 - 27.5

Total Volumes Sold 26.8

% Committed 100%

Total Consolidated Coal Division Capital Expenditures ($ in millions):

Production $85 - $95

Other (Land/Water/Safety/Terminal) $20 - $30

Total Coal Capital Expenditures $105 - $125

Adjusted EBITDA Guidance

CNXC EBITDA $59 - $69

5x

100% PA Coal Complex Operating EBITDA $295 - $345

Less: Noncontrolling Interest ($26) - ($31)

Plus: Other Coal Operating EBITDA(1)

$23 - $28

Plus: Other Coal Misc. EBITDA(2)

$16 - $24

Less: Other Costs and Expenses (including Legacy Liabilities' Cash Costs)(3)

($108) - ($116)

CNX Pro Rata Coal EBITDA $200 - $250

30

Milestones:

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

service cost deflation

Adding two rigs while maintaining disciplined on capital expenditures

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

CONE MLP growth – July 22nd announced 3.7% increase to quarterly distribution to $0.254 per unit, the 5th consecutive

increase since July 2015

Positive initial well results from operated dry Utica (Gaut 4IH, GH9, and Switz 6D)– sets up future stacked pay

opportunities

Improved free cash flow and opportunistic asset sales to de-lever

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

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

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

Our management team is motivated and incentivized to generate FCF and NAV/share, which is consistent with the

metrics used in the short and long term incentive programs for 2016

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

Key Takeaways

31

Appendix

32

Non-GAAP Reconciliation: EBITDA and Adj. EBITDA

Appendix

Three Months Ended Twelve Months Ended

June 30

2016 2016 2016 2016 2015

($ in thousands)E&P

Division

Coal

DivisionOther

1 Total

Company

Total

Company

Net (Loss)/Income ($294,499) ($212,235) $38,085 ($468,649) ($603,301)

Less: Loss from Discontinued Operations - 235,639 - 235,639 26,078

Add: Interest Expense 755 2,153 44,519 47,427 46,506

Less: Interest Income (320) - (227) (547) (364)

Add: Income Taxes Benefit - - (100,354) (100,354) (301,669)

(Loss)/Earnings Before Interest & Taxes (EBIT) from Continuing Operations (294,064) 25,557 (17,977) (286,484) (832,750)

Add: Depreciation, Depletion & Amortization 105,151 30,069 1 135,221 138,135

(Loss)/Earnings Before Interest, Taxes and DD&A (EBITDA) from

Continuing Operations ($188,913) $55,626 ($17,976) ($151,263) ($694,615)

Adjustments:

Unrealized Loss on Commodity Derivative Instruments 279,715 - - 279,715 24,936

Coal Contract Buyout - (6,288) - (6,288) -

Severance Expense 525 26 900 1,451 -

Pension Settlement - - 13,696 13,696 -

Impairment of E&P Properties - - - - 828,905

Backstop Loan Fees - - - - 7,334

Other Transaction Fees - - - - 4,968

OPEB Plan Changes - - - - (33,649)

Loss on Debt Extinguishment - - - - 17

Total Pre-tax Adjustments $280,240 ($6,262) $14,596 $288,574 $832,511

Adjusted EBITDA $91,327 $49,364 ($3,380) $137,311 $137,896

Less: Noncontrolling Interest - (1,179) (1,179) -

Adjusted EBITDA Attributable to Continuing Operations $91,327 $48,185 ($3,380) $136,132 $137,896

Source: Company filings.

Note: Income tax effect of Total Pre-tax Adjustments was $104,855 and $313,327 for the three months ended June 30, 2016 and June 30, 2015, respectively. Adjusted net income

attributable to CONSOL Energy shareholders for the three months ended June 30, 2016 is calculated as GAAP net loss from continuing operations of $233,010 plus total pre-tax

adjustments of $288,574, less the tax benefit of $104,855, equals the adjusted net loss from continuing operations of $49,291.

(1) CONSOL Energy's Other Division includes expenses from various other corporate activities including income tax expense that are not allocated to E&P or Coal Divisions.

33

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

Appendix


Three Months Ended Three Months Ended Three Months Ended Three Months Ended Twelve Months Ended

September 30 December 31 March 31 June 30 June 30

($ in thousands) 2015 2015 2016 2016 2016

Net Income / (Loss) $125,470 $34,325 ($96,463) ($468,649) ($405,317)

Less: Loss from Discontinued Operations 4,566 11,733 53,752 235,639 305,690

Add: Interest Expense 48,558 49,081 49,865 47,427 194,931

Less: Interest Income (361) (431) (214) (547) (1,553)

Add: Income Taxes 66,524 126,472 (23,217) (100,354) 69,425

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 244,757 221,180 (16,277) (286,484) 163,176

Add: Depreciation, Depletion & Amortization 146,845 139,986 154,988 135,221 577,040

Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from

Continuing Operations $391,602 $361,166 $138,711 ($151,263) $740,216

Adjustments:

OPEB Plan Changes (100,947) (109,879) - - (210,826)

Unrealized Gain/(Loss) on Commodity Derivative Instruments (99,138) (62,388) 29,271 279,715 147,460

Pension Settlement 3,132 15,921 - 13,696 32,749

Industrial Supplies Working Capital Settlement - 6,258 - - 6,258

Gain/(Loss) on Sale of Non-core Assets (48,468) (7,551) 13,735 - (42,284)

Severance Expense 7,683 - 2,918 1,451 12,052

Coal Contract Buyout - - - (6,288) (6,288)

Total Pre-tax Adjustments (237,738) ($157,639) $45,924 $288,574 ($60,879)

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $153,864 $203,527 $184,635 $137,311 $679,337

Less: Noncontrolling Interest ($6,490) ($3,920) ($1,114) ($1,179) ($12,703)

Adjusted EBITDA Attributable to Continuing Operations $147,374 $199,607 $183,521 $136,132 $666,634

34

Free Cash Flow Reconciliation

Appendix


Three Months Ended Six Months Ended

June 30 June 30

($ in thousands) 2016 2016

Net Cash provided by Continuing Operations 83,571$ 206,307$

Capital Expenditures (37,593) (115,257)

Net Investment in Equity Affiliates - (5,578)$

Organic Free Cash Flow From Continuing Operations 45,978$ 85,472$

Net Cash Provided By Operating Activities 95,299$ 223,740$

Capital Expenditures (37,593) (115,257)

Capital Expenditures of Discontinued Operations (1,254) (8,295)

Net Investment in Equity Affiliates - (5,578)

Proceeds From Sales of Assets 9,831 421,090

Total Free Cash Flow 66,283$ 515,700$

35 Notes: PA and WV prospective Utica eastern boundary has yet to be delineated. Acreage is risked 40+% in PA and WV. Acreage in Ohio oil window is excluded.

Acreage and locations as of December 31, 2015 unless otherwise noted.

~2% of net Utica acreage developed to date

Utica Shale Upside Potential

Utica Shale: Growth Runway and Depth of Inventory

Total Gross Prospective Utica Acreage ~701,000

- Gross Acres within JV ~158,000

- Acres outside JV – 100% CONSOL ~543,000

Acreage spacing per well (assumed 1,100 ft spacing) ~126

Gross Producing wells (JV - YE2015) 83

Gross PDNP and PUD locations (YE2015) 106

Gross prospective unproved locations ~3,500

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

Appendix

36

Potential resource of ~30 Tcfe

Note: Acreage and locations as of December 31, 2015 unless otherwise noted.

Utica Shale

Ohio Wet Ohio Dry PA/WV Dry Total

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

Approximate Gross

Locations(1) 1,050 350 2,400 3,800

Avg EURs/1,000 ft

(Bcfe) 2.3 2.8 3.0 --

Utica Shale: Sub-Regions Summary

Appendix

37

Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). Gross locations are as of 6/30/2016.

(1) Comprised of ~119,000 net acres in Ohio Utica (~79,000 in the JV and ~40,000 non-JV) and ~306,000 and ~197,000 net prospective acres in PA and WV respectively.

Utica Shale Overview: A Leading Position in the Utica Shale

Appendix: E&P Division

~622,000 CONSOL net

acres(1)

Over 3,000 gross locations

─ 101 wells online, as of

6/31/2016

─ 5 wells TIL in Q2 2016

─ 6,955 ft average TIL

laterals in Q2 2016

─ 4 wells per pad on

average

─ 180-acre spacing

(assuming 7,000 ft lateral)

EURs:

─ Ohio Wet: 2.3 Bcfe

EUR/1,000 ft of lateral

─ Ohio Dry: 2.8 Bcfe


─ PA/WV Dry: 3.0 Bcfe


38

Appendix: E&P Division Utica Shale: OH, PA & WV Dry Gas

CHK – Brown 10H

IP Gas: 9,500 Mcf/d

HES – NAC 3H-3*

IP Gas: 11,000 Mcf/d

CHK– Hubbard 3H

IP Gas: 11,00 Mcf/d

RRC Claysville Sportman’s Club

IP Gas: 59 MMcf/d HES – Potterfield 1H-17*


RICE – Bigfoot 9H


GPOR – Stutzman 1-14


GPOR – Irons 1-4


CNX – Switz 6D

44.7 MMcf/d @ 6,835 psig

24-hr test rate

MHR – Stalder 3UH


MHR – Winland Pad


HGE – Whiteacre 2H

IP Gas: 9,000 Mcf/d

Eclipse – Tippens 6H


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

*Subsequently sold to Ascent Resources LLC.

Tugg Hill (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

Dry Utica is being aggressively tested in Northern WV and PA, where CONSOL

holds 100% working interest in approximately 503,000 net acres

Noble Energy/CNX – MND6

39.1 MMcf/d @ 7,126 psig

24-hr test rate

CNX – GH9

61.9 MMcf/d @ 8,312 psig

24-hr test rate

CNX – Gaut 4IH

Prod. Net 4.5 Bcf in 250 days (managed)

EQT – Scotts Run

24 Hour Prod 72.9 MMcf/d

CHK – Messenger WTZ 3UH

IP Gas: ~30 MMcf/d EQT – Big 190

Producing 6,200 ft lateral.

Antero – Rymer 4HD

20 MMcf/d 20-day avg. rate

Eclipse – Fauchs 4H


EQT – Big 177

Spud Q2 2016

5,200 ft. lateral

EQT – Shipman

Producing 7,000 ft lateral

EQT – West Run

Drilling 5,800 ft lateral

RRC DMC Properties

~18 MMcf/d with Managed Pressure

EQT – Pettit

Producing 5,200 ft lateral

CHK– Hubbard 3H

IP Gas: 11,00 Mcf/d

RRC Claysville Sportman’s Club

IP Gas: 59 MMcf/d

CNX – Gaut 4IH

Prod. Net 4.5 Bcf in 250 days (managed)

RRC DMC Properties

~18 MMcf/d with Managed Pressure

CVX – Conner 6H


Permits submitted for 2 add. laterals

CONSOL has over 110,000 acres of Utica leasehold in

Westmoreland and Indiana Counties, PA 39

CONSOL – GAUT4IH

61.4 MMcf/d 24-hr IP rate @

7,968 psi; 5,840 ft. lateral

~ 5,800’ single lateral; 100% WI to

CONSOL

30 stage completion

200’ stages with 500k# proppant:

160k# 100 mesh + 200k # 40/80

ceramic + 140k# 30/50 ceramic

Ready supply of water

Production facilities and gathering

system with available capacity

Underutilized FT available

Achieved Peak 24-hr rate of 61.4

MMcf/d in July 2015

Appendix: Gaut 4IH Dry Utica Shale


40

Range Resources - Claysville Sportsman’s Club #1

IP Gas – 59.0 MMcf/d

CONSOL GH9

24 hr IP – 61.9 MMcf/d

@ 8,312 psig

6,141 ft. lateral

100% WI and 96% NRI to CONSOL

TVD: 13,400’

Frac’d in Q4 2015

24-hour IP of 61.9 MMcf/d at 8,312 psi

Drilled lateral length of 6,141 ft.

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

Appendix: GH9 Dry Utica Shale

CONSOL has ~84,000 net acres prospective for the Utica in the SWPA operating

area, including ~58,000 net acres in Greene and Washington Counties, PA

EQT – Pettit Spud in Aug. 2015

13,400 ft. TVD

4,000-4,500 ft. lateral


Appendix: Ohio Dry Utica Shale

41

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

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 psi

9,761 ft. lateral

CVX Conner well (Utica):


GST Simms:

4,447' Lateral

1st 48 Hour Prod 29.4mm

IP 33 MMcf/d @ 9000psi

NBL / CNX MND 6H (Utica):

1 Utica Well

39.1 MMcf/d 24-hr IP @7,126 psi

9,345 ft. lateral

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

Monroe County, OH 42

CONSOL – SWITZ 6 Pad (Utica):

4 Utica wells & 1 Marcellus well

CNX – Switz 6D: 24-hr test rate

44.7 MMcf/d @ 6,835 psig

4 Utica Wells and 1 Marcellus Well

Avg. Utica Lateral Length = 8,821’

Longest Utica Lateral = 10,122’

100% WI to CONSOL

Tested 3 proppant types

350K pounds/stage @ 200’ spacing

Multi-Market availability

Offset pad fully permitted with 5 wells

Appendix: Switz 6 Dry Utica Shale


43

~436,000 CONSOL net

acres

─ ~88% NRI

─ ~91% HBP

23.9 Tcfe 3P

Over 8,900 gross potential

wells(1)

Marcellus production grew

at a 71% CAGR from 2013

to 2015

Producing Pads


(1) Based on 5,000 ft laterals with 86-acre spacing. Locations are as of 12/31/2015.

Overview

Appendix: Marcellus Shale

44

Total Gross Prospective Marcellus Acreage ~785,000

- Gross Acres within JV ~699,000

- Acres outside JV – 100% CONSOL ~86,000

Acreage per well (assumed 750 ft spacing) ~86

Gross Producing wells (JV - YE2015) 448

Gross PDNP and PUD locations (YE2015) 146

Gross prospective unproved locations ~8,000

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


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

Marcellus Shale Upside Potential

Marcellus Shale: Growth Runway and Depth of Inventory

Appendix

45

Marcellus Shale

SWPA CPA WV Ohio(1) North

Wet

South

Wet Total

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

Approximate

Gross

Locations(2)

900 2,200 2,250 150 1,000 2,200 ~8,700

Avg

EURs/1,000 ft

(Bcfe)

2.1 1.6 1.8 -- 1.8 2.1 --

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

Marcellus Shale: Sub-Regions Summary


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

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

Appendix

46

Appendix Marcellus Shale: Southwest PA Overview



~44,000 CONSOL net

acres

Over 900 gross locations(1)


6/31/2016



average in 2016

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



47

Appendix Marcellus Shale: North Wet Gas Overview



WFN3 Pad

4 Wells



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

~52,000 CONSOL net

acres

Over 1,000 gross

locations(1)

─ 144 wells online as of

6/31/2016



average


lateral


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



48

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




~107,000 CONSOL net

acres

Over 2,200 gross

locations(1)


6/31/2016


average


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

49

Marcellus Shale: Northern WV Dry Overview

PHL4 Pad

3 Wells



720 MMcf/well – 1st 6-month Cum

ANDERSON (PDC Mountaineer)

3 Wells



~111,000 CONSOL net

acres

Over 2,250 gross

locations(1)


6/31/2016



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

50

Marcellus Shale: Central PA Overview

GAUT4 Pad

4 Wells




COOK (Atlas/Chevron)

2 Wells



GREENAWALT (Chevron

Appalachia)

3 Wells



SMITH (Atlas/Chevron)

2 Wells



~108,000 CONSOL net

acres

Over 2,200 gross

locations(1)


6/31/2016



average


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

51

Stacked pays provide a large inventory and rich opportunity set

Wet

Net Acres

Dry

Net Acres

Total

Net Acres

190,000

173,000

89,000

452,000

155,000

263,000

951,000

345,000

436,000

622,000

1,403,000

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

Stacked Pay Potential: Appalachian Shale Acreage

533,000

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

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