Company Presentation - CNX Resources

Company Presentation Q1 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 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 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; 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.

3

CONSOL Energy: Execution of Our Game Plan

In 2013 – CONSOL set out to shift focus to being a pure play E&P company

- Sold 5 West Virginia mines

- Dramatically improved our E&P metrics

- Lowered capital intensity

- Lowered unit costs

- Hired a new head of the E&P Division

- Improved management of the rising risk in volatility with higher gas production

- Refinanced debt and improved the balance sheet

- Meaningfully reduced administrative expenses across the company

The results as of year-end 2015 – creating free cash flow for 2016

- E&P production increased faster than peers from 2013 through 2015

- E&P EBITDA now surpassing Coal Division

- Unit costs have declined 21%, faster than peers

- Capital intensity cut in half

- Gas and Liquids hedging meaningfully in place

- Created publicly traded entities to help separate Coal and E&P Divisions

- Refinanced $5 billion of debt and removed approximately $3 billion of legacy liabilities

Coal-E&P Revenue Split, 2012

E&P Revenues

Coal Revenues

4

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

Late 2013 – transaction with Murray Energy Corp. that transitioned half of coal

assets and related assets

April 19, 2014 – CONSOL Energy 150th Anniversary

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

best in class coal assets

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

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

6

E&P Division: Q1 2016 Operations Summary

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length

(ft)

Counties

Southwest

PA ---- ---- 11 17 5,839

Greene,

Washington,

PA

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

Indiana,

Westmoreland,

PA

Northern

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

Barbour,

Doddridge,

Lewis, WV

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

North Wet

Gas ---- ---- ---- 8 10,763

Greene,

Washington,

PA; Marshall,

WV

South Wet

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

Doddridge,

Tyler, Ritchie,

WV

Total ---- ---- 11 25 7,415

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length (ft)

Counties

Core Wet ---- ---- ---- 4 9,220 Noble, OH

Surrounding

Core Wet ---- 6 4 5 8,579

Harrison,

Belmont, OH

Dry Utica ---- ---- ---- 1* 5,964

Monroe, OH;

Marshall, WV

Westmoreland,

Greene, PA

Total ---- 6 4 10 8,574

Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary

E&P Operations

*Dry Utica TIL is GH9A

Production update

─ Operational Improvement: Utilized permanent production

equipment for flowback operations – respective capital savings of

$86k/well in the Marcellus and $112k/well in the Utica.

─ Lease Operation Strategy: Implementation of company well

tenders instead of contractors and rebidding contracts will yield

$2.7 million in annual savings against LOE

─ Production Optimization: Workovers, tubing installs, artificial lift,

and compression opportunities.

─ Production Highlights:

SWITZ-6 pad: Yielded a 30-day average rate of 59.4 MMcf/d

with an impressive 21 psi/day managed pressure decline

GAUT-4I: Cumulative production ending in Q1 2016 has

totaled 2.92 BCF while averaging an 18 psi/day pressure

decline in Q1 only

Marcellus: Q1 TIL’s are at, or outperforming, type curves

Completion update

─ Quality Focus: Completed 10 well pad 35% faster and 10%

cheaper than Q4 2015.

─ Water Chemistry Success: 2 consecutive quarters fracturing

with 100% reused water. Decreasing operating costs while

fostering environmental stewardship.

─ Forward Approach: Continued to make significant strides

toward plugless completions and eliminating post frac

intervention. Providing efficiency, decreased cost, and less

risk.

7

2016 Planned E&P Activity Overview

E&P Activity Summary – 2016 Plan

E&P Operations

Note: Plan as of 4/26/2016. Average net revenue interest for Marcellus/Utica shales is 43.7%. Table includes two 100% CONSOL-owned wells: one dry Utica Shale well in Monroe

County, Ohio and one dry Utica Shale well (GH9) in Greene County, Pennsylvania. Marcellus and Utica wells are horizontal wells, and CBM wells are primarily vertical wells.

Drilled

Uncompleted

Inventory

Drilled

Completed

Inventory

2016

Completions

Remaining

2016

TIL's

Remaining

Marcellus

SW PA Operated 18 17 6 23

SW PA Non-Op 5 2 - 2

WV Operated 7 - - -

WV Non-Op 49 - - -

Total Marcellus 79 19 6 25

Utica

SW PA Operated - - - -

OH Operated 1 - - -

OH Non-Op 8 2 3 5

Total Utica 9 2 3 5

CBM

CBM Operated 2 1 24 25

Total Gross Wells 90 22 33 55

Implied DUC inventory exiting 2016 of 79 Marcellus and Utica Shale Wells,

assuming no new drilling in 2016, up by 2 wells from prior quarter due to TIL

deferrals as a result of continued well outperformance

E&P Operations

8

2016 production growth primarily driven by wells’ productivity improvements, pipeline

infrastructure debottlenecking projects and completion of inventory of drilled but

uncompleted wells

Bridging to Growth

Note: Guidance as of 4/26/2016. Production volumes reflect the mid-point of their contribution to the 2016 production guidance ranges.

Source: Company filings and estimates.

329 -50

23 5

71 378

0

50

100

150

200

250

300

350

400

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

9

Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth

E&P Operations: Capital Expenditures

Our base case assumes no new drilling in 2016 and reflects the low-end of the

capital range

Deferring activity, increasing capital efficiency

improvements and identification of additional de-

bottlenecking activities

2016 E&P capital budget of $205-$325 million

- Drilling and Completion: $110-$210 million

o Includes $10-$15 million for coalbed methane (CBM) activity

- Midstream of $40-$50 million (including approximately $22

million associated with CONE Midstream capital

contributions)

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

$55-$65 million

60%

17%

23%

D&C Midstream Other

2016 E&P Capital Budget:

$205-$325 Million

10

CONSOL has fundamentally improved performance over the last couple years

E&P Operations

Average Completed Lateral Length Average Stage Length

Average EUR/ 1000’ FT

1.55

1.32 1.45 1.45

2.13

0.0

0.5

1.0

1.5

2.0

2.5

2011 2012 2013 2014 2015-Present

Bcfe

3,366

5,137 5,483

7,004 7,118

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2011 2012 2013 2014 2015-Present

Feet

282.9 279.2

252.7

168.7

194.7

0

50

100

150

200

250

300

2011 2012 2013 2014 2015-Present

Feet

CONSOL’s Operational Experience Transformation

Combining science with operational excellence . . .

• Longer laterals for drilling efficiency

• From shorter stage spacing to optimized spacing

• Engineering driven completion design

• Site selection optimization

128154 156

172

236

329

~15%

0

50

100

150

200

250

300

350

400

450

2010 2011 2012 2013 2014 2015 2016E

Bcfe

Marcellus CBM Utica Other

E&P Operations - Benchmarking vs Peers

11

Production volumes CAGR of ~30% from 2013-2016 while operating

expenses (excluding DD&A) declined 36% by 4Q15 from 4Q13

E&P Production Volumes

Beginning to outperform peers on growth and unit cost performance

Source: Company filings.

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

Production by Area

2015A 2016E

Marcellus 51% 54%

CBM 23% 19%

Utica (Wet & Dry) 17% 21%

Other 9% 6%

~$1,310 ~$1,240

~$1,140

~$850

2013 2014 2015 2016E

Marcellus CapEx ($) / Lateral Ft E&P Operating Expenses

100

120

140

160

180

200

220

240

260

2012 2013 2014 2015 2016E

Peers CNX

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

Peer Average CNX

2013 2014 2015 2016E

Indexed Production Growth


Note: Peers include AR, COG, EQT and RRC. 2016E per guidance as of 2/19/2016


Note: Operating Expenses excluding DD&A. Peers include AR, COG, EQT, RICE, RRC and SWN.

$0.23 $0.38 $0.24 $0.16

$1.10$1.02

$1.04$1.00

$0.17 $0.17$0.09

$0.07

$0.84 $0.59

$0.37$0.29

$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 Direct Admin Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE

12

Full-cycle Breakeven Operating Metrics Declined from $3.51 To $2.00 Per Mcfe, a 43% decline

E&P Operations - Benchmarking vs Peers

Exceeded cost reduction target of 15% in 2015 with a 19% reduction and

projecting an additional 13% reduction for 2016

Cash OpEx

(plus G&A) of

$1.52/Mcfe,

plus PUD-to-

PDP CapEx of

$0.48/Mcfe,

equals total full

cycle cash

costs of

$2.00/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.

13

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 12/31/2015.

(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

E&P Operations

~622,000 CONSOL net

acres(1)

Over 3,500 gross locations

─ 97 wells online, as of

3/31/2016

─ 10 wells TIL in Q1 2016

─ 8,574 ft average TIL

laterals in Q1 2016

─ 4 wells per pad on

average

─ 180-acre spacing (1,100

ft. inter-lateral 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


14

E&P Operations Utica Shale: PA/WV Dry Gas

REXX – Cheeseman 1

IP Gas: 9,200 Mcf/d

IP Oil: 0 Bbl/d

CHK – Thompson 3H

IP Gas: 6,400 Mcf/d

IP Oil: 0 Bbl/d

RRC– Zahn #1

IP Gas: ~4,500 Mcf/d

IP Oil: 0 Bbl/d

CHK – Brown 10H

IP Gas: 9,500 Mcf/d

IP Oil: 0 Bbl/d

HES – NAC 3H-3*

IP Gas: 11,000 Mcf/d

IP Oil: 0 Bbl/d

CHK– Hubbard 3H

IP Gas: 11,00 Mcf/d

IP Oil: 0 Bbl/d

RRC Claysville Sportman’s Club

IP Gas: 59 MMcf/d

IP Oil: 0 Bbl/d

EQT – Pettit

Spud in Aug. 2015

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

CVX – Conner 6H


IP Oil: 0 Bbl/d

Permits submitted for 2 add. laterals HES – Potterfield 1H-17*


IP Oil: 0 Bbl/d

RICE – Bigfoot 9H


IP Oil: 0Bbd

GPOR – Stutzman 1-14


IP Oil: 0 Bbd

GPOR – Irons 1-4


IP Oil: 0 Bbd CNX – Switz 6D

44.7 MMcf/d @ 6,835 psig

24-hr test rate

MHR – Stalder 3UH


IP Oil: 0 Bbl/d

MHR – Winland Pad


HGE – Whiteacre 2H

IP Gas: 9,000 Mcf/d

IP Oil: 0 Bbl/d

Eclipse – Tippens 6H


IP Oil: 0 Bbl/d

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.

GST – Simms Pad

4447' Lateral

1st 48 Hour Prod 29.4 MMcf/d

IP 33 MMcf/d @ 9000psi

SGY – Pribble 6US

IP Gas: 30 MMcf/d

IP Oil: 0 Bbl/d

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

holds 100% 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

61.4 MMcf/d @ 7,968 psig

24-hr test rate

EQT – Scotts Run

24 Hour Prod 72.9 MMcf/d

CHK – Messenger WTZ 3UH

IP Gas: ~30 MMcf/d

EQT – Big 190

Spud in Sept. 2015

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

Antero – Rymer 4HD

20 MMcf/d 20-day avg. rate

CONSOL has over 110,000 acres of Utica leasehold in

Westmoreland and Indiana Counties, PA 15

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

Utica Shale: Gaut 4IH – Westmoreland County, PA


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

9/25/2015 10/25/2015 11/25/2015 12/25/2015 1/25/2016 2/25/2016 3/25/2016

Flow Rate Mcf/Day Casing Pressure

The well has produced 2.8 Bcf through March 31, 2016 while average flowing casing

pressure remains strong at approximately 6,800 psi 16

Utica Shale: Gaut 4IH Westmoreland County, PA

Conducted a Modified Isochronal Test with planned extended drawdown and build-up

Results of test have provided reliable values for reservoir pressure, height, permeability and extent together with well-spacing for future wells

We are following a managed pressure drawdown where we are currently dropping pressure at 20-25 psi/day

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

17

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

Utica Shale: GH 9 Greene County, PA

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


Utica Shale: Ohio Dry Gas

18

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 19

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

Utica Shale: Switz 6 Monroe County, OH


20

Dry Utica: Switz 6 Pad Monroe County, OH

The Switz 6 pad produced ~5.7 Bcf through March 31, 2016 while average

flowing casing pressure remains strong at approximately 5,000 psi

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

10/13/2015 11/13/2015 12/13/2015 1/13/2016 2/13/2016 3/13/2016 4/13/2016

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

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

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

Production

Casing Pressure

0

5,000

10,000

15,000

20,000

25,000

0 20 40 60 80 100 120

Mea

sure

d D

epth

(ft

.)

Days

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

Switz-6B-HSU

Switz-6F-HSU

Switz-6H-HSU

Switz-6D-HSU

Switz-16J-HSU

$509.76

$540.17

$321.59

$344.98

$231.80

$0

$100

$200

$300

$400

$500

$600

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

Drilli

ng C

ost ($

/ft.)

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

~55% Reduction in Drilling Costs

21

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

~60+% Reduction in Days to Drill

22

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

23

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

Q1 2016 natural gas price reconciliation:

24

E&P Marketing

Q1 2016 Gas Realization and Marketing Highlights

2016 2015

NYMEX natural gas ($/MMBtu) 2.09$ 2.98$

Average differential (0.36) 0.03

Btu conversion (MMBtu/Mcf)* 0.10 0.09

Gain on Commodity Derivative Instruments-Cash Settlements 0.98 0.48

Realized gas price per Mcf 2.81$ 3.58$

*Conversion factor 1.06 1.03

First Quarter

25

Gas Marketing

TETCO M2

TETCO M3

TCO Pool

Dominion South

East Tennessee

TETCO ELA

Midwest

Gas Sales CY 2016 Est.

Columbia (TCO) 20%

TETCO (M2) 26%

TETCO (M3) 16%

Dominion (DTI) 14%

East Tennessee 10%

TETCO ELA & WLA 8%

Midwest (Chicago) 6%

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

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

26

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) 195 494

Dominion (DTI) 370 342

East Tennessee 282 202

Nexus - 150

TETCO 174 174

TETCO (via firm sales) 285 125

1,353 1,534

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

Pipelines are being built to take gas away from Appalachia to demand centers,

which will have a positive impact on in-basin pricing.

Large Pipelines Are Coming to Debottleneck Gas

($8)

($6)

($4)

($2)

-

$2

$4

$6

$8

$10

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

$/M

MB

tu

Colorado Interstate Gas Mainline Basis

Regional prices should improve as pipelines are built to take

excess supply out of the region

Over 22 Bcf/d of pipeline capacity is planned to be built in Appalachia

in 2016-2018

Historically, we have seen basis improve in other regions (see

Colorado basis chart below) as pipelines are built out

Some of these projects will be delayed or sized lower

The debate is how much will basis improve and by when

REX pipeline became fully

operational in November

2009

27

ProjectID Markets Year Mo. Status MMcf/d

Leidy Southeast NorthEast 2016 1 Construction 395

Capacity enhancement Midwest 2016 10 Committed 800

AIM Algonquin NorthEast 2016 11 Committed 342

Lebanon West II Midwest 2016 11 Announced 130

Gulf Markets Expansion 1 Gulf 2016 11 Committed 250

Total 2016 1,917

Rover phase 1 Midwest, Canada 2017 6 Delayed to 2Q2017 1,200

Rayne express Gulf 2017 6 Committed 1,000

Rover Canada Midwest, Canada 2017 11 Delayed to 2H2017 1,100

Rover phase 2 Midwest 2017 11 Delayed to 2H2017 825

Atlantic Sunrise South 2017 7 Committed 1,700

Constitution NorthEast 2016 7 DELAYED 650

Gulf Markets Expansion 2 Gulf 2017 8 Committed 100

Leidy South Mid-Atlantic 2017 10 Committed 155

Atlantic Bridge Northeast 2017 11 Open Season 132

SoNo (South to North) Northeast, Canada 2017 11 Open Season 650

Nexus Project Midwest, Canada 2017 11 Committed 1,200

Broad Run Expansion II Gulf 2017 11 DELAYED TO 2018 200

Access South Gulf 2017 11 Committed 320

Adair SW South 2017 11 Committed 320

Lebanon Extension Midwest 2017 11 Open Season 102

Northern Access 2016 Canada 2017 11 DELAYED TO 2017 497

Total 2017 10,151

LDC NorthEast 2018 1 Announced 200

Access Northeast NorthEast 2018 11 Announced 925

SW LA Supply - Cameron Gulf 2018 11 Announced 100

WB Express West Midwest 2018 6 Announced 800

Marcellus to Milford Northeast 2018 6 Announced 135

PennEast South 2018 7 8 month delay 1,000

Mountaineer Express TCO Pool 2018 11 Open Season 1,500

WB Express East South 2018 11 Announced 1,200

Atlantic Coast Pipeline South 2018 11 Announced 1,500

Northeast Energy Direct Northeast 2018 11 CANCELED -

Mountain Valley South 2018 12 Committed 2,000

Total 2018 9,360

Grand Total 21,428

Northeast Pipeline Projects

28

Regional Basis – Location, Location, Location

Dawn Pipeline Projects

Dawn

CY 2016: $0.07

CY 2019: $0.08

Southeast Pipeline Projects

Transco Zone 5

CY 2016: $0.04

CY 2019: $0.81

TCO Pool Basis

CY 2016: - $0.14

CY 2019: - $0.20

East LA

CY 2016: - $0.08

CY 2019: - $0.07

Gulf Market Pipelines

Source: SNL Financial, Velocity, CME

Prices as of 4/04/16

TETCO M2

CY 2016: - $0.83

CY 2019: - $0.55

TETCO M3

CY 2016: -$0.52

CY 2019: -$0.04

Dominion South

CY 2016: -$0.83

CY 2019: -$0.54

Chicago

CY 2016: - $0.02

CY 2019: $0.04

Leidy

CY 2016: -$0.90

CY 2019: -$0.72

Northeast Pipeline Projects

$1.2 $2.0

$2.4

$4.0 $4.6 $4.9

$5.5

$14.3

$17.5

Average: $6.3 Bn

20% 19%

71%

52% 36%

167%

70%

95%

152%

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

$-

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$16.0

$18.0

$20.0

CNX A B C D E F G H

FT C

om

mit

me

nts

as

% o

f EV

$ B

illio

ns

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

expensive FT incurring long term off-balance sheet liabilities

29

Notes: As of 12/31/2015. Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC and SWN.

Commitments are as of most recently provided company financial statements.

Total Off Balance Sheet Firm Transportation, Gathering and Processing Commitments

Gas Marketing: Firm Transport–Asset or Liability?

Contracted capacity meets

current requirements

─ Inlet wet gas volumes to

processing plants were ~115

MMcf/d above CONSOL’s

aggregate minimum

committed volume in Q1 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

30

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

31

(1) Includes the impact of NYMEX, index and basis-only

hedges as well as physical sales agreements.

(2) Hedge positions as of 4/14/2016.

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

Added approximately 190

Bcf of additional gas hedges

through 2019, further

protecting downside

Approximately 69% of total

FY 2016E production

volumes hedged

2Q16 FY 2016 FY 2017 FY 2018 FY 2019

NYMEX + Basis (1)

Volumes (Bcf) 67.3 259.7 122.5 65.4 -

Average Prices ($/Mcf) $2.87 $3.07 $2.67 $2.68 -

NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) - - 88.3 47.9 54.9

Average Prices ($/Mcf) - - $2.98 $3.08 $2.96

Physical Sales With Fixed Basis Exposed to NYMEX

Volumes (Bcf) 3.4 2.9 - - -

Average Hedge Basis Value ($/Mcf) ($0.20) ($0.04) - - -

Total Volumes Hedged (Bcf)(2) 70.7 262.6 210.8 113.3 54.9

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

2Q16 FY 2016 FY 2017 FY 2018 FY 2019

Ga

s V

olu

me

s H

ed

ge

d (

Bcf)

Physical Sales With Fixed Basis Exposed to NYMEX

NYMEX Only Hedges Exposed to Basis

NYMEX + Basis (1)

32

Ethane 64%

Propane 22%

I-Butane 3%

N-Butane 6%

Natural gasoline

5%

Maximum

Ethane

Recovery*

Potential

Scenario

* Assumes 85% ethane recovery level

Ethane 14%

Propane 49%

I-Butane 8%

N-Butane 15%

Natural gasoline

14%

1Q16 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

Q1 2016 Avg. “NGL Barrel” Composition

Q1 2016 liquids sold: 11.4 Bcfe

Total weighted average price of liquids decreased

~22% to $12.78 per Bbl in Q1 2016 from $16.34 per

Bbl in Q4 2015

Liquids comprised approximately 12% of Q1 2016

production volumes, 9% of E&P sales revenue and

4% of total Company revenue

Added 7.5 million gallons of propane hedges from

April of 2016 through March of 2017 at an average

price of $0.43 per gallon

Average price realization (per Bbl):

2016

Q1 Q4 Q1

NGLs $12.30 $14.16 $20.40

Oil $30.84 $39.06 $47.82

Condensate $14.64 $25.38 $20.82

2015

33

Financial

34

Financial: Focused on Free Cash Flow

Strong liquidity position

CNXC and CONE

Asset monetization program

Reduction in legacy liabilities

Guidance: Production, price realizations, operating and capital costs

- Growing E&P production volumes

- Reductions to operating and overhead costs

- Reductions in E&P capital intensity

Service cost deflation: beating expectations; improves capital spending efficiency

Leverage in-place infrastructure

Continue to high-grade development plan (Dry Gas Utica potential)

- Steady coal production with lower cost base

CONSOL remains focused on lowering costs and deleveraging the balance sheet

through organic operations and potential asset sales

107

90

80

85

90

95

100

105

110

2015 2016E

Total Company SG&A($ in Millions)

Corporate Cost Reductions

35

Focused on reducing overhead costs

Zero-Based Budgeting

Includes key SG&A line items such

as:

Wages and Salaries

Payroll Taxes

Employee Benefits

Professional/Consulting

Telephone & Internet

Communications

Travel & Entertainment

Advertising & Promotion

Rent: Buildings and Equipment

Trade Association Dues

Notes: 2015 G&A adjusted to reflect 1Q16 accounting change removing direct admin. line item and reallocating expense to operating costs and G&A as appropriate

36

Debt and Liquidity Profile

Financial: Liquidity

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

(1) The 2022 and 2023 senior notes includes $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 $3.648 billion excludes total unamortized debt issuance costs of $32 million.

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

(4) As of 3/31/2016, CNX had approximately $852 million of borrowings and $286 million of outstanding letters of credit under its revolving credit facility, leaving approximately $862 million of availability.

CNXC had $200 million outstanding on its revolving credit facility leaving approximately $200 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 3/31/2016 and unit prices as of market close on 4/22/2016.

(6) CNX Coal Resources liquidity data is as of 3/31/2016 and CONE Midstream data is as of 12/31/2015.

(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 $669

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

plan of $244 million, less the $78 million of CNXC EBITDA Attributable to CNX, plus the $43 million of

CNXC cash distributions to CNX, less $31 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 $3.648 billion, less

$418 million cash on hand excluding CNXC’s cash, less $6 million of advance mining royalties, plus $224

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

insurance policies.

CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 3/31/2016 3/31/2016 3/31/2016

Capitalization

Cash and Cash Equivalents $427 $9 $418

Revolving Credit Facility Balance 1,052 200 852

Capital Lease Obligations 41 - 41

Total Secured Debt $1,093 $200 $893

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) $3,648 $200 $3,448

Net Debt (3) $3,221 $191 $3,030

Stockholders’ Equity $4,739 $150 $4,589

Total Capitalization $8,387 $350 $8,037

Liquidity

Cash and Cash Equivalents $427 $9 $418

Revolving Credit Facility Capacity (4) 1,062 200 862

Total Liquidity $1,489 $209 $1,280

CNX

Owned LP

Units(5)

Unit

Price(5)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 12.7 $9.10 $115

CONE Midstream Partners LP (CNNX:NYSE) 19.1 $14.25 $272

Total Equity Value of Ownership Interests in Affiliated Public MLPs $387

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity of

Affiliates

CNX Coal Resources LP (6)

$400 $200 $200 $9 $209

CONE Midstream Partners LP (6)

$250 $74 $176 $0 $176

Total Liquidity of Affiliated

Public MLPs $650 $274 $376 $9 $385

Leverage Ratio 3/31/2016

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7) $889

LTM Bank Net Debt / Adj. EBITDA (7)

3.7x

Equity Value of Ownership in Affiliated Public MLPs

$4,345

$1,902 $1,694 $1,542 $1,522 $1,508

$370

$148 $153 $137 $109

$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 Q1 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 3/31/2016 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 1,022 761 672 665 667

Salary Retirement/Pension 225 53 119 94 89 79

Asset Retirement Obligations 699 601 576 550 540 537

Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,522 $1,508

FY 2012 FY 2013 FY 2014 FY 2015 Q1 2016 FY 2016E

Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $137 $109

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

since 2012, with further reductions expected going forward

37

Significant Legacy Liability Reductions Over Past 3 Years

Financial: Legacy Liabilities

Projected $109MM Annual Cash

Servicing Cost for FY 2016, a

$28MM 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”

38

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 4.22.2016) $9.10

CNXC Units Equity Value to CONSOL Energy $115.2

CONSOL Energy's Ownership Interest in CNX Coal

Resources LP (CNXC:NYSE)

$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

$50$61

$17$18

$10 $15

$34

$68 $79

$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

CONSOL owns 32.1% of CONE Midstream Partners LP’s

(CNNX:NYSE) LP units and 50% of the General Partner

(“GP”), which has a 2% interest in CNNX (and rights to

IDRs)

CNNX owns interests in 3 development companies

(ownership structure detailed in Appendix)

The remaining un-dropped portion of the development

companies’ interests are held by CONE Gathering LLC

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

CONSOL Energy (CNX:NYSE) and Noble Energy

(NBL:NYSE)

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

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

of Affiliates,” which in CNX’s consolidated financial

statements falls within the “Miscellaneous Other Income”

line item

Distributions run straight through CNX’s cash flow

statement in the “Return on Equity Investment” line item

CNX has seen increasing benefit from CONE’s EBITDA and

cash distributions, on top of which CNNX recently

increased its cash distribution 3.5% from 4Q15 run-rate

39

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)

LP Units held by CONSOL Energy 19.1

Unit Price (as of close on 4.22.2016) $14.25

CNNX Units Equity Value to CONSOL Energy $272.2

CONSOL Energy's Ownership Interest in CONE

Midstream Partners LP (CNNX:NYSE)

40

Guidance

Note: Guidance as of 4/26/2016.

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

E&P Segment Guidance

Production Volumes:

Natural Gas (Bcf)

NGLs (MBbls)

Oil (MBbls)

Condensate (MBbls)

Total Production (Bcfe)

Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.35) - ($0.45)

NGL Realized Price ($/Bbl) $8.00 - $10.00

Condensate Realized Price % of WTI 43% - 46%

Oil Realized Price % of WTI 93% - 95%

Capital Expenditures ($ in millions):

Drilling and Completion $110 - $210

Midstream $40 - $50

Land and Other $55 - $65

Total E&P and Midstream CapEx $205 - $325

Average per unit operating expenses ($/Mcfe):

Lifting (including Direct Admin.) $0.27 - $0.30

Impact Fees/ Ad Valorem/ Production Taxes 0.06 - 0.08

Gathering, Transportation, Compression & Processing 0.98 - 1.02

Depreciation, Depletion and Amortization 1.00 - 1.07

Total Production and Gathering Costs $2.31 - $2.47

Other Expenses ($ in millions):

General and Administrative Expense $58.0 - $62.0

Unutilized Firm Transportation Expense, net:(1)$15.0 - $16.0

2016E

335

6,000

65

1,000

~+15%

41

Guidance

Note: Guidance as of 4/26/2016.

* Includes FY 2016 for Miller Creek and Other Coal Operations and 1Q16 for Buchanan, excludes Loss on Sale of Buchanan Complex

** Includes Other Income (net of applicable expense) associated with the Company's Terminal Operations, Coal Royalty Income, and other miscellaneous land income

*** Includes Legacy Liability Costs approximating $90-95M; Other Coal-Related Corporate Expenses (STIC, stock-based compensation), and other miscellaneous items (coal

reserve holding costs)

Coal Segment Guidance

Estimated Total Consolidated Coal Division Sales Volumes (in millions of tons) 23.9 - 27.4

Total Volumes Sold

% Committed

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 ($ in millions):

CNX Coal Resources LP ("CNXC") Adjusted EBITDA (20% undivided interest of

PA Operations) $59 - $69

x5 (@ 100% interest) $295 - $345

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

Plus: CONSOL's Other Coal Division EBITDA* $22 $27

Plus: CONSOL's Other Miscellaneous Coal EBITDA** $15 - $20

Less: CONSOL's Other Coal Division Costs and Expenses (including legacy

liabilities' costs)*** ($126) - ($131)

CONSOL Energy's Pro Rata Coal Division Adjusted EBITDA $180 - $230

98%

25.0

2016E

42

Milestones:

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

service deflation

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

CONE MLP growth – April 21st announced 3.7% increase to quarterly distribution to $0.245 per unit, the 4th increase

since the IPO in October 2014

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

opportunities

- 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.

- Use of free cash flow and opportunistic asset sales to de-lever

Our management team is motivated and incentivized long-term to increase return on capital employed and

NAV/share

Plans and Goals Aligned to Drive Increased Valuation

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

our core values of safety, compliance, and continuous improvement

Key Takeaways

43

Appendix

44

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

Appendix


Three Months Ended Twelve Months Ended

March 31

2016 2016 2016 2016 2015

($ in thousands)E&P

Division

Coal

DivisionOther

Total

Company

Total

Company

Net (Loss)/Income ($23,541) ($49,015) ($23,902) ($96,458) $79,030

Less: Net Loss/(Income) Attributable to Discontinued Operations, net of tax - 46,172 - 46,172 (244,317)

Add: Interest Expense 653 1,733 47,480 49,866 55,122

Less: Interest Income - - (214) (214) (1,143)

Add: Income Taxes (Benefit)/Expense - - (26,847) (26,847) 195,898

Earnings Before Interest & Taxes (EBIT) from Continuing Operations (22,888) (1,110) (3,483) (27,481) 84,590

Add: Depreciation, Depletion & Amortization 105,715 54,352 - 160,067 149,709

Earnings Before Interest, Taxes and DD&A (EBITDA) $82,827 $53,242 ($3,483) $132,586 $234,299

Adjustments:

Unrealized Loss/(Gain) on Commodity Derivative Instruments 29,271 - - 29,271 (60,004)

Loss on sale of sale of gathering pipeline 12,636 - - 12,636 -

Severance Expense - 2,251 667 2,918 -

Loss on Debt Extinguishment - - - - 67,734

Total Pre-tax Adjustments $41,907 $2,251 $667 $44,825 $7,730

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $124,734 $55,493 ($2,816) $177,411 $242,029

Less: Noncontrolling Interest* - (1,114) - (1,114) -

Adjusted EBITDA Attributable to CONSOL Energy Shareholders $124,734 $54,379 ($2,816) $176,297 $242,029

45

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

June 30 September 30 December 31 March 31 March 31

($ in thousands) 2015 2015 2015 2016 2016

Net (Loss)/Income ($603,301) $125,470 $34,325 ($96,458) ($539,964)

Less: Net Loss Attributable to Discontinued Operations, net of tax $229,466 2,044 2,139 46,172 279,821

Add: Interest Expense $46,507 48,558 49,082 49,866 194,013

Less: Interest Income (364) (361) (431) (214) (1,370)

Add: Income Taxes (520,666) 64,758 125,806 (26,847) (356,949)

Earnings Before Interest & Taxes (EBIT) from Continuing Operations (848,358) 240,469 210,921 (27,481) (424,449)

Add: Depreciation, Depletion & Amortization $154,764 $149,790 145,783 160,067 $610,404

Earnings Before Interest, Taxes and DD&A (EBITDA) ($693,594) $390,259 $356,704 $132,586 $185,955

Adjustments:

OPEB Plan Changes (33,649) (100,947) (109,879) - (244,475)

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

Unrealized Gain on Commodity Derivative Instruments 24,936 (99,138) (62,388) 29,271 (107,319)

Pension Settlement - 3,132 15,921 - 19,053

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

Gain on Sale of Non-core Assets - (48,468) (7,551) 12,636 (43,383)

Severance Payments - 7,683 - 2,918 10,601

Loss on Debt Extinguishment 17 - - - 17

Backstop Loan Fees 7,334 - - - 7,334

Other Transaction Fees 4,968 - - - 4,968

Total Pre-tax Adjustments $832,511 (237,738) ($157,639) $44,825 $481,959

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $138,917 $152,521 $199,065 $177,411 $667,914

Less: Noncontrolling Interest* - (6,490) ($3,920) ($1,114) ($11,524)

Adjusted EBITDA Attributable to CONSOL Energy Shareholders $138,917 $146,031 $195,145 $176,297 $656,390

46

Free Cash Flow Reconciliation

Appendix


Three Months Ended

March 31

2016

Organic Free Cash Flow From Continuing Operations:

Net Cash provided by Continuing Operations 119,806$

Capital Expenditures (78,968)

Net Investment in Equity Affiliates (5,578)

Organic Free Cash Flow From Continuing Operations 35,260$

Free Cash Flow:

Net Cash Provided By Operating Activities 128,442$

Capital Expenditures (78,968)

Capital Expenditures of Discontinued Operations (5,737)

Net Investment in Equity Affiliates (5,578)

Proceeds From Sales of Assets 8,453

Proceeds From Sale of Buchanan Mine 402,806

Total Free Cash Flow 449,418$

47

Joint Ventures

(1) CONSOL holds ~86,387 net acres outside of the Marcellus JV. As of 12/31/2015.

(2) CONSOL holds ~40,052 net acres outside of the Utica JV, which includes ~13,000 net acres in Monroe County, OH. As of 12/31/2015.

(3) The remaining carry balance on a cash basis is $1.62 billion for Marcellus and $15 million for Utica, respectively. Utica carry has an accrued cash balance of

$7.5 million as of end of 1Q 2016.

(1) (2)

(3) (3)

Description Marcellus / Noble Energy Inc. Utica / Hess Corporation

Ownership 50/50 50/50

Acreage 349,541 79,266

Zones PA and WV Marcellus, Burkett to Onondaga OH Utica

Carry

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

charges

Maximum annual payment of $400 million per year

Henry Hub spot price averages over $4.00 per

month for three consecutive months

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

charges (i.e. CNX pays 25%)

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

end of 4Q15

$335 million, of which ~$7.5 million remains as of end

of 1Q16

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

Non-carry eligible

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

Summary of JV Carry Eligible Capital

Appendix

48

~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.

Marcellus Shale: Overview

Appendix

49

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%

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

~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

50

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

51

Appendix Marcellus Shale: Southwest PA Overview



~44,000 CONSOL net

acres

Over 900 gross locations(1)


3/31/2016



average in 2016

2.1 Bcfe EUR/1,000 ft of

lateral

750 ft inter-lateral spacing

Producing Pads

Competitor Pads

52

Appendix Marcellus Shale: North Wet Gas Overview



~52,000 CONSOL net

acres

Over 1,000 gross

locations(1)

─ 144 wells online as of

3/31/2016



average


lateral

Increasing use of

RCS/SSL


Condensate yield: 5

Bbls/MMcf

NGLs yield: 49 Bbls/MMcf

Producing Pads

Competitor Pads

53

Appendix



~107,000 CONSOL net

acres

Over 2,200 gross

locations(1)


3/31/2016


average


lateral


Condensate yield: 10

Bbls/MMcf

NGLs yield: 51 Bbls/MMcf

Marcellus Shale: South Wet Gas Overview

Producing Pads

Competitor Pads

DTI Storage Fields

54

Marcellus Shale: Northern WV Dry Overview

~111,000 CONSOL net

acres

Over 2,250 gross

locations(1)


3/31/2016



lateral




Producing Pads

Competitor Pads

DTI Storage Fields

Appendix

55

Marcellus Shale: Central PA Overview

~108,000 CONSOL net

acres

Over 2,200 gross

locations(1)


3/31/2016



average


lateral




Producing Pads

Competitor Pads

Appendix

56 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

57

Potential resource of ~30 Tcfe


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

58

~622,000 CONSOL net

acres in Utica

─ ~306,000 net acres in

PA

─ ~197,000 net acres in

WV

─ 30,000 net acres in OH

Dry

~14,000 net acres in

Monroe County, OH

─ 89,000 net acres in OH

Wet

Majority of acreage

offset to peers with

strong results

─ The main area without

offset results was

Westmoreland County

where CNX drilled the

Gaut 4IH which had the

2nd highest IP in the

Utica to date

Utica Shale: Offset Peer Acreage

Appendix

Notes: CNX acreage position as of 12/31/2015. CNX acreage shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres.

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

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

3,000 or more acres (as of 12/31/2015).

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

Appendix

CNX - NBL 18

IP GAS: 8,213 Mcf/d per well

IP OIL: 834 Bbl/d per well

CNX - NBL 30



GPOR - Boy Scout 33H

IP GAS: 5,300 Mcf/d

IP OIL: 1,560 Bbl/d

CHK - Buell 8H

IP GAS: 9,500 Mcf/d

IP OIL: 1,425 Bbl/d

GPOR - Wagner 1-28H

IP GAS: 14,000 Mcf/d

IP OIL: 432 Bbl/d

AR - Miley 5HA

IP GAS: 7,700 Mcf/d

IP OIL: 1,285 Bbl/d

GPOR - Shugert 1-12H


IP OIL: 300 Bbl/d

HES – Cadiz A

IP GAS: 8,006 Mcf/d

IP OIL: 399 Bbl/d

REXX - Guernsey 2H

IP GAS: 8,082 Mcf/d

IP OIL: 564 Bbl/d

GPOR - Irons 1-4H


IP OIL: 0 Bbl/d

CNX - NBL 16A


IP OIL: 750 Bbl/d

CNX - NBL 19



CNX - NBL 16B

IP GAS: 5,630 Mcf/d

IP OIL: 522 Bbl/d

HES – Cadiz B


IP OIL: 191 Bbl/d

HES – Athens A

IP GAS: 7,745 Mcf/d

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

17% of liquid hydrocarbon sweet spot controlled by CONSOL JV

~85,000 CONSOL net acres

~34,000 CONSOL net acres

in core

Type curve reflects core

area

Over 1,050 gross core area

locations(1)


3/31/2016

─ 9 wells online in Q1 2016

─ 8,082 ft average laterals in

Q4 2015

─ 4-5 wells per pad on

average


lateral

RCS/SSL standard for new

drills


60

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

61

CONSOL Energy: Corporate Structure

CONSOL Energy

E&P Other Operations CONE MLP PA Complex

Marcellus

Utica

CBM

SOG and Other*

CNXC (MLP)

CONSOL structure moving toward a pure play E&P

* Includes Other Midstream

62

Appendix

Source: CONE Midstream Partners LP.

CONE Corporate Structure

(1) For the period ending and as of 12/31/2014.

(2) Source: EIA. Represents average power plant deliveries for the twelve months ended 12/31/2014.

(3) Source: Company filings from FELP, ARLP, WMLP and RNO.

Pennsylvania Mining Complex

Coal Division

63

Pennsylvania mining complex consists of three like-new

underground mines and related infrastructure with high-Btu

bituminous coal (785.6 million tons proven and probable(1))

Train loadout facility (up to 9,000 tons per hour) with dual rail

access with Norfolk Southern and CSX

High-Btu bituminous thermal coal is primarily sold to utility

companies in the eastern United States - 13,000 Btus per pound

average gross heat content and 2.37% average sulfur content

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

the Northern Appalachian Basin

Five longwalls and 18 continuous mining sections

Access to seaborne markets through CONSOL-owned Baltimore

Marine Terminal for exporting thermal and metallurgical coal

Mine

Total

Recoverable

Reserves

(tons) (1)

Average

Gross Heat

Content

(Btu/lb) (1)

Average

Sulfur

Content (1)

Annual

Production

Capacity

(tons) (1)

2015

Production

(tons) (1)

Bailey 254.5 12,929 2.68% 11.5 10.2

Enlow Fork 322.8 12,942 2.21% 11.5 9.0

Harvey 208.3 13,080 2.25% 5.5 3.6

Total 785.6 12,974 2.37% 28.5 22.8

Illinois Basin 11,396 2.94%

Other NAPP 12,134 3.19%

Other Coal

MLPs 11,619 2.74%

(2)

(3)

654925_1.w or (NY0086JT)

Baltimore

Terminal

PA Mining

Complex

Active Complex

Port/Dock

CNXC Customers

We couldn't fine the original

artwork 655159_Graphic.ai

NY0086JT so we had to

ungroup it and make the

edits.

(2)

64

Our Core Values Drive Corporate Responsibility

Core values of Safety & Compliance – our results are posted in our CRR Reports

Developed Absolute Zero Program in 2009

Measure and report all our key performance

indicators within our Corporate Responsibility

Report (CRR)

Spent $167 million during 2015 alone on

Health, Safety and Environmental initiatives

Achieved ZERO Occupational Safety and

Health Administration violations during 2015

Approximately 98% of CNX employees worked

2015 without a reportable accident

Recordable incident rate declined 17% in 2015

vs 2014

65

Environmental Management System (EMS)

We believe our core values drives operational outperformance while managing risk

Founding, certified member of the Center for

Sustainable Shale Development (CSSD)

Compliance at 99.9% with NPDES effluent limits

Recycled and repurposed over 500 million

gallons of water

Created a water business

In 2015, recycled over 12,500 tons of materials

Planted 570,000+ trees

Reduced 60% in indirect emissions

Documents

Company Presentation - CNX Resources