CONSOL Energy Company Presentation - July 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

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)
23
5
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 29
27
25
24
23
21
19 19 19 19
17 17
15 14
10 10 10 10 9
7
6 6
0
10
20
30
40
50
60
70
NormalizedAsqrt(K),md^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
$600
Switz 6B Switz 6D Switz 6H Switz 6F Switz 16J Switz 16D Expected
DrillingCost($/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
DMeasuredepth(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
$30.0
Prior AFE Per Well Drilling Efficiency Drilling Science Cost Casing Design Multi-Well Pad (4) Completion Design Proppant Optimization Development AFE Per
Well
Waterfall Diagram - PA Dry Utica Drilling and Completion Costs Per Well
Assume 7000' lateral on a development 4-well pad
($ 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

 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
1000SMMBtu/day

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
MMcf/day
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
GasVolumesHedged(Bcf)
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

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
Capacity
Cash
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
$600
9/1/14 12/1/14 3/1/15 6/1/15 9/1/15 12/1/15 3/1/16
CashBalance($MM)
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
$4,500
FY 2012 FY 2013 FY 2014 FY 2015 Q2 2016 FY 2016E
AnnualCashServicingCost($inMillions)
LegacyLiabilities($inMillions)
Total Legacy Liabilities (left axis) Annual Legacy Liabilities Cash Servicing Cost (right axis)
As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 6/30/2016 12/31/2016E
Legacy Liabilities ($ 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 Qtr
Annualized
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
$100
FY 2012 FY 2013 FY 2014 FY 2015 Last Qtr
Annualized
CONE Midstream's and Gathering's Pro Rata
EBITDA Contribution to CNX
CNX Pro Rata Share of CONE Midstream Partners LP's Cash Distributions
CNX Total Pro Rata Share of CNNX and CONE Gathering, LLC's EBITDA
Note: ($ 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

32
Non-GAAP Reconciliation: EBITDA and Adj. EBITDA
Appendix
Three Months Ended
June 30
2016 2016 2016 2016 2015
($ in thousands)
E&P
Division
Coal
Division
Other
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
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
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
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
acres
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
acres
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
acres
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
Limestone0 GR 400 LITHOLOGY
Total
Appendix

CONSOL Energy Company Presentation - July 2016

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CONSOL Energy Company Presentation - July 2016