analyst and investor day - cnx resources...

ANALYST AND INVESTOR DAY

December 13, 2016

Cautionary Language

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, natural gas liquids, and coal, including due to oversupply relative to the demand available for our products; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate the volume of hydrocarbons that are recoverable from our oil and natural gas assets; we may encounter unexpected operational issues or disruptions when we drill and mine, including equipment failures, geological conditions, and higher than expected costs for equipment, supplies, services and labor, including with respect to third-party contractors; 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 partner, who operate assets in which we have a significant interest, may not perform as we expect and these and other circumstances could cause us not to realize the benefits we anticipate from our joint venture; we may not be able to sell non-core assets on acceptable terms; divestitures that we anticipate making or have made may not occur or produce anticipated benefits, or may cause disruptions to our business operations; we may be subject to environmental and other government regulations that adversely impact our operating costs and the market for our natural gas and coal; 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; we may be unable to incur indebtedness on reasonable terms; provisions in our multi-year sales contracts may provide limited protection and may result in economic penalties to us or permit the customer to terminate the contract; our common units in CNX Coal Resources LP are subordinated, and we may not receive related distributions; 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. Currently, 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 natural 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 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.

2

3

Agenda

Company Overview

Nick DeIuliis, President and CEO

Exploration & Production Tim Dugan, COO Andrea Passman, VP-E&P Development

Don Rush, VP-E&P Marketing

Diversified Business Units Steve Johnson, EVP-DBU Rodney Wilson, Director-Business Development

Marshall Roberts, Director-CONVEY Water Systems Katharine Fredriksen, SVP-DBU & Environmental Affairs

Financial Overview Dave Khani, CFO Chuck Hardoby, VP-Finance

Regulatory Update

Tommy Johnson, VP-Government & Public Relations

Closing Remarks

Nick DeIuliis

Q&A

Lunch / CNX Coal Resources LP Breakout Session

CONE Midstream Partners LP Breakout Session

Acquisition of Dominion Resources E&P assets tripling Marcellus Shale acreage position

4

CONSOL Energy’s Evolution

2014-2015 CONE Midstream Partners LP (NYSE: CNNX) formed with Noble Energy to provide gathering services in the Marcellus Shale and CNX Coal Resources LP (NYSE: CNXC) formed to house and manage CONSOL’s PA coal assets

2010 2013 2016 2016

Announces sale of five thermal coal mines in West Virginia to Murray Energy

With the sale of the Buchanan mine and other remaining legacy coal assets, CONSOL’s transformation into a premier natural gas Company is completed

2017+ CONSOL and Noble Energy announce separation of Marcellus JV, providing CONSOL with additional operational flexibility and the ability to reach leverage targets more rapidly

Looking to the future – working towards complete separation from coal; monetizing assets where possible; continuous operational improvement

+179% YTD

CONSOL Energy Has Continued to Transform Itself in 2016

RBL

Reaffirmation

Restarted Drilling

(Accelerated

Schedule)

NBL JV

Resolution Buchanan Sale

Jan 2016 Today

P2AA Asset Optimization

(Phase 2)

Zero-Based Budgeting

P2AA Asset Optimization

(Phase 1)

Integrated

Model

Miller Creek & Fola Sale

Re-org (Streamlined Operations &

Planning)

Turned DUC Inventory

Online

Restructured Agreement

with

Penguins

CNX Share Price YTD 2016(1)

Capital Allocation

Driven

Cash

Stabilization CNXC/

CNNX Drops

5

(1) As of 12/7/2016

$0

$5

$10

$15

$20

$25

Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16

Who We Are: Differentiating Ourselves Through Three Pillars

Values:

• Never compromised regardless of circumstance

• Operate daily free of injuries and environmental incidents

• Pursuit of perfection driving towards best-in-class performance

• Mitigates business risk profile and supports license to operate in an industry that is subject to intense public scrutiny

Business philosophy:

• NAV/share focused

• Production growth is a byproduct

• Capital allocation process drives decision-making

• Delivering responsible, long-term value

Asset base:

• Substantial drilling inventory equates to scalable advantages

• Considerable percentage of held by production (HBP) acreage provides unique flexibility in development plans

• Largest stacked pay opportunity set in the lowest cost basin in the U.S.

• Marcellus JV separation unlocks significant stacked pay opportunities

6

Business Philosophy: Zero-Based Budgeting in Action

Transformed balance sheet:

• Reduced legacy liabilities by $3 billion

Reduced expenses:

• Cash servicing costs reduced by more than $250 million since 2012

Transformed culture:

• Executive compensation less than half 2012 levels

- Compensation widely aligned with shareholders’ interests

• Executive perks and benefits eliminated; exited arena naming rights agreement, providing significant cost savings

-61%

(1) Includes corporate jets/hangar, membership fees, and arena naming fees (2) Annual legacy liability cash servicing costs

Overhead(1)

Executive Pay

Legacy Liabilities(2)

Selling G&A

2012 2016E

7

Reductions in Expenses 2012-2016E

The Path Forward: Realization of Value

How we plan to close the value gap:

Realization of Value...

Today $22.05 Closing price 12/7/2016 1 GROW EBITDA –

PRUDENT GROWTH OF E&P PRODUCTION EFFICIENT CAPITAL ALLOCATION TO HIGH IRR, NAV ACCRETIVE AOIs

PAY DOWN DEBT – ORGANIC FREE CASH FLOW AND ASSET MONETIZATIONS DRIVE LEVERAGE RATIO IMPROVEMENT BELOW TARGET OF 2.5x

REDUCE SHARE COUNT – OPPORTUNISTICALLY BUY BACK SHARES AS MARKET ALLOWS

2

3

8

$-

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

2015 YTD 2016

$ in

mill

ion

s

Weathered Downturn Without Issuing Equity

9

Since the beginning of 2014, total follow-on equity issued by Appalachian peers totaled $10.6 billion:

• All seven Appalachian peers have issued follow-on equity since the beginning of 2014

• CONSOL was able to de-lever the balance sheet and improve liquidity through organically growing free cash flow (FCF) and monetizing assets

• Avoiding issuing equity has resulted in not diluting shareholders and providing further upside potential

Source: Scotia Howard Weil Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN

Follow-On Equity Issued Across Energy Industry FY2015-YTD 2016

CONSOL Energy Represents a Unique Value Story

10

Focus on NAV/Share Growth

Driving NAV/share growth:

• Significant increases to estimated ultimate recoveries (EURs)

• Reducing drilling and completion (D&C) costs and capital intensity

• Proving up and de-risking reserves

• Accelerating activity

• Continued focus on de-levering the balance sheet

E&P Assets

Asset base is unique:

• Prolific stacked pay positions create significant competitive advantage

• Early efforts to delineate the Utica Shale are driving up net present value

(NPV) estimates

• Large inventory of acreage for potential monetization opportunities

Supplementary Value Drivers

Supplemental value drivers growing over time:

• Diversified Business Units (DBU), which includes:

- CONVEY Water Systems and the Baltimore Marine Terminal

• CNX Coal Resources LP

• CONE Midstream Partners LP

EXPLORATION & PRODUCTION

11

E&P Operations: NAV/Share Drivers

12

CONVERTING NON-CORE ACREAGE TO CORE

MAJOR OPERATIONAL IMPROVEMENTS SINCE 2014

STACKED PAY OPPORTUNITIES

Continuous Improvement

0%

20%

40%

60%

80%

100%

120%

140%

160%

0.4

60

.60

0.7

80

.83

0.9

71

.04

1.2

71

.43

1.6

41

.95

2.0

42

.20

1.0

31

.09

1.2

41

.47

1.6

31

.85

1.9

81

.99

2.0

32

.16

2.1

92

.41

2.4

92

.55

1.2

71

.52

1.8

82

.22

2.4

32

.45

2.5

62

.64

2.7

12

.96

3.0

13

.11

3.6

03

.74

3.8

84

.34

2014 2015 2016

BTA

X IR

R (

%)

EUR/Capex (Mcfe/$)

Capital Efficiency

1.24 Mcfe/$ 1.83 Mcfe/$ 2.78 Mcfe/$

13

Note: Bars represent well-level economics, which includes total capital employed

NAV growth being driven by improved capital efficiency

E&P Industry: F&D Costs

Source: Scotia Howard Weil: 2015 F&D Cost Study Note: Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN (1) (Land Acquisition Costs + Exploration + Development)/Drilling Reserve Additions

CONSOL has had some of the lowest F&D costs in the industry over the last five years

Drilling Finding and Development Cost 5-yr. Average 2011-2015(1)

14

$0.80

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

1 2C

NX 3 4 5 6 7

$/M

cfe

Technological Evolution Driving Growth

15

Tools and Procedures 2014 2016E

Earth model - ✔

Fracture simulation - ✔

Reservoir simulation - ✔

Rate transient analysis (RTA) - ✔

Risk analysis - ✔

Portfolio NAV optimization - ✔

NAV/Share Growth Drivers Since 2014:

• 100% increase in EUR/1,000'

• 38% improvement in capital deployment

• 54% reduction in lease operating expense (LOE) ($/Mcfe)

• 40% of dry Utica acreage converted from non-core to core

Operational Evolution

16

Key Performance Metrics(1) 2014 2016E

Average EUR (Bcfe/1,000’) 1.4 2.8

Total Marcellus capital ($/ft) 1,345 835

Lease operating expense (LOE) ($/Mcfe) 0.41 0.19

Average drilling days on well 27 18

Average completion days on well 32 15

Completion stage spacing (ft) 300 150-225

Completion proppant volume (lbs/ft) 1,300 2,500-3,000

Improved operational performance:

• Lean manufacturing

• Supply chain management

• Zero-based budgeting

Sustained growth at lower $/EUR

(1) Combined Marcellus and Utica key performance indicators (KPIs)

Cumulative Production vs. Incremental Wells TIL by Year

0

10

20

30

40

50

60

70

80

0

100

200

300

400

500

2014 2015 2016

Incr

emen

tal W

ells

On

line

Cu

mu

lati

ve G

as P

rod

uct

ion

, BC

F

Marcellus-Utica Cumulative Production New Wells Online

0

100

200

300

400

500

600

700

0 10 20 30 40 50

Cum

pro

d (

MM

cfe

/1,0

00')

Normalized months

CNX 1/2014 - 5/2015 CNX 6/2015+

0

500

1,000

1,500

2,000

CNX 1 2 3 4 5 CNX 2014 - 5/2015

Mcfe

/d

3 Mo (20:1) 6 Mo (20:1) Avg 3 Mo (20:1) Avg 6 Mo (20:1)

Well Performance Over Time

17

Horizontal well production per 1,000’ since June 2015 – CNX vs. Peers

142% Increase

Source: IHS Enerdeq via Credit Suisse Note: Peers include CVX, EQT, RICE, RRC, Vantage

CNX Well Performance Improved well performance:

• Enhanced completions design

• Optimized landing points

• Managed pressure drawdown

Large Acreage Position

CNX vs. Appalachian Peers – Acreage Position and Production

18

Only 4% of total Marcellus and Utica Shale inventory developed to date:

• 8% of the Marcellus acreage developed

- Marcellus 90% HBP

• 1% of the Utica acreage developed

- Utica 91% HBP

• 60+ years(1) of production runway in inventory

• 89% net revenue interest (NRI)

• 22 years of inventory in stacked pay in core areas(2)

(1) Inventory calculated assuming 100 wells drilled per year (2) Stacked pay core areas include Marcellus and Utica

720,000 615,000

406,000

640,000

480,000

175,000 200,000

490,000

400,000

608,000

370,000

375,000

160,000

210,000

0

500

1,000

1,500

2,000

2,500

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1 2 CNX 3 4 5 6 7

Dai

ly P

rod

uct

ion

(M

Mcf

e/d

)

Net

Acr

es

Marcellus Utica Q3 Daily Production

19

New World View: Assets Before and After JV Separation

SWPA WV CPA OH Total Total Change

Upper Devonian Net Acres 102,000 112,000 21,000 - 235,000 280,000 (45,000)

Net Acres 98,000 61,000 232,000 15,000 406,000 436,000 (30,000)

Fee Acres 32,000 1,000 20,000 3,000 56,000 41,000 15,000

Approx. Net Locations (1)

533 370 1,465 116 2,484

Net Producing Wells (PDPs) 188 34 60 1 283 258 25

Net Acres 119,000 162,000 208,000 119,000 608,000 623,000 (15,000)

Fee Acres 42,000 8,000 12,500 36,000 98,500 100,000 (1,500)

Approx. Net Locations(1)

673 987 1,177 517 3,354

Gross Producing Wells (PDPs) 1 - 1 94 96 97 (1)

Marcellus

Utica

Post-JV Dissolution Pre-JV Dissolution

(1) Total net locations calculated from modeling inputs expected lateral lengths and spacing for each respective asset region and formation

64% increase in Marcellus core acreage:

• Full control of stacked pay opportunity set

• Incremental 85 MMcfe/d of production

• Further strengthens balance sheet

• Higher weighted average EUR, compared to pre-dissolution

Post-Exchange Marcellus Acreage Map

20

Dissolution of the Marcellus Shale Joint Venture

Marcellus Impact

Pre- JV Dissolution

Post- JV Dissolution

Change

Flowing PDP (MMcfe/d)

535 620 +16%

DUCs 37.5 53 +41%

Net acres (1) 336,000 306,000 (30,000)

Core(2) 99,000 162,000 +64%

Non-core(3) 237,000 144,000 (39%)

(1) Net acres include undeveloped only (2) Core: Prospective reservoir at current gas price forecast, de-risked by drilling, midstream, and market availability, with capacity for development and non-op potential (3) Non-Core: Non-prospective reservoir at current gas price forecast, acreage not a main driver, minor to no delineation, and minor to no non-op potential

Development Optimization

Production Modeling

Engineering Workflow Drives Decisions

21

Earth Modeling

NPV/Well

Portfolio Risk Analysis

Rate Transient Analysis

Forecasting

ITERATIVE CYCLE

3D Frac Modeling

Asset Region 1: Southwest Pennsylvania Overview

22

Marcellus Shale average EUR/1,000’ of lateral increased 29% to 2.7 Bcfe(1)

• Total net acres: 98,000

• Total NRI: 89%

• Sizable capital expenditure in the next 2 years

• 2 rigs in 2017 and 3 rigs in 2018

Utica Shale

• Average EUR/1,000’ of 3.1 Bcf(1)


• Total NRI: 89%

• Continue to delineate through participation and drilling

Upper Devonian Shale


• 3 wells expected to be turned in line (TIL) in 2017

(1) Average EUR represents the type curve guidance area depicted on the map Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

64% Utica/Marcellus core over core acreage overlap

http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx




0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

0 12 24 36 48

Gas

Pro

du

ctio

n (

Mcf

/mo

nth

)

Months After TIL

7000' LL

0

100,000

200,000

300,000

400,000

500,000

600,000

0 12 24 36 48

Gas

Pro

du

ctio

n (

Mcf

/mo

nth

)

Months After TIL

8500' LL

Southwest Pennsylvania Modeling Inputs and Economics

23

SWPA Marcellus Type Curve (2.7 Bcfe/1000')

SWPA Utica Type Curve (3.1 Bcf/1000')

BTAX ROR % (3)

Realized Price 8,500'

$2.00 39%

$2.50 71%

$3.00 109%

BTAX ROR % (3)


$2.00 19%

$2.50 34%

$3.00 52%

(1) Assuming 8,500 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

Assumptions

IP (MMcfe/d) 19.0

Decline 69%

B-factor 1.65

EUR/1000’ (Bcfe) 2.7

Lateral Length 8,500’

Wells Per Pad 6

Capital ($ millions) $7.1

Fixed Cost ($/mo./well) $730

LOE ($/Mcfe) $0.12

Gathering ($/Mcfe) $0.48

Reserves Detail

Gross EUR (Bcfe) 22.6

BTU 1,130

Assumptions

IP (MMcf/d) 23.1

Decline 67%

B-factor 1.20

EUR/1000’ (Bcf) 3.1


Wells Per Pad 5



LOE ($/Mcf) $0.05

Gathering ($/Mcf) $0.23

Interest / Net Locations

WI / NRI (%) 100% / 89%

Net Locations(1) ~533

Wells Online (9/30/16) 188

Reserves Detail

Gross EUR (Bcf) 21.4

BTU 1,010


WI / NRI (%) 100% / 89%



Asset Region 2: West Virginia Overview

24

Marcellus Shale average EUR/1,000’ of lateral increased 61% to 2.9 Bcfe(1)


• Total NRI: 86%

• Focus on completing DUC inventory: sunk capital results in improved IRR

Utica Shale

• Average EUR/1,000’ of 2.8 Bcf


• Total NRI: 88%

• Delineation through participation

(1) Average EUR represents the type curve guidance area depicted on the map Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 220,000 acres of Utica resource potential in WV not included in company totals Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

14% Utica/Marcellus acreage overlap





0

10,000

20,000

30,000

40,000

50,000

0

100,000

200,000

300,000

400,000

0 12 24 36 48

NG

L/C

ND

Pro

du

ctio

n (

BB

L/m

on

th)

Gro

ss G

as P

rod

uct

ion

(M

cf/m

on

th)

Months After TIL

Gas

NGL

CND

0

100,000

200,000

300,000

400,000

500,000

600,000

0 12 24 36 48

Gas

Pro

du

ctio

n (

Mcf

/mo

nth

)

Months After TIL

6500' LL

BTAX ROR % (4)


$2.00 10%

$2.50 20%

$3.00 31%

25

West Virginia Modeling Inputs and Economics

WV Marcellus Type Curve (2.9 Bcfe/1000')

BTAX ROR % (4)


$2.00 37%

$2.50 56%

$3.00 76%

(1) Assuming 8,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 6,500 ft lateral @ 1,100 ft inter-lateral spacing (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

WV Utica Type Curve (2.8 Bcf/1000')

Assumptions

IP (MMcf/d) 14.0

Decline 69%

B-factor 1.65

EUR/1000’ (Bcfe) 2.9

Lateral Length 8,000'

Wells Per Pad 6

NGL Yield (Bbl/MMcf)(3) 74.1

CND Yield (Bbl/MMcf)(3) 12.8



LOE ($/Mcf) $0.12

Gathering/Processing

($/Mcf) $0.93

NGL OpEx ($/Bbl) $5.00

CND OpEx ($/Bbl) $5.00

Reserves Detail


BTU 1,260


WI / NRI (%) 100% / 86%



Assumptions

IP (MMcf/d) 15.3

Decline 58%

B-factor 1.10

EUR/1000’ (Bcf) 2.8


Wells Per Pad 3



LOE ($/Mcf) $0.05


Reserves Detail


BTU 1,015


WI / NRI (%) 100% / 88%


Wells Online (9/30/16) -

Asset Region 3: Central Pennsylvania Overview

26

Marcellus Shale

• Average EUR/1,000’ of 1.8 Bcf(1)


• Total NRI: 88%

• Weighted average EUR/1000’ for the entire region is 1.5 Bcf

• Evaluate Marcellus development in conjunction with Utica

Utica Shale average EUR/1,000’ of lateral up 17% to 3.5 Bcf


• Total NRI: 89%

• Continued drilling expected in 2017 and 2018

• 2 wells planned in 2017 and 1 well in 2018

• Non-operated participation opportunities

(1) Average EUR represents the type curve guidance area depicted on the map, which is approximately 111,000 acres in CPA Note: “CNX Utica Resource Potential” as depicted on the map represents an additional 22,000 Utica resource potential in CPA not included in company totals Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

96% Utica/Marcellus acreage overlap





0

100,000

200,000

300,000

400,000

0 12 24 36 48

Gas

Pro

du

ctio

n (

Mcf

/mo

nth

)

Months After TIL

9000' LL

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

0 12 24 36 48

Gas

Pro

du

ctio

n (

Mcf

/mo

nth

)

Months After TIL

7000' LL

27

Central Pennsylvania Modeling Inputs and Economics

CPA Marcellus Type Curve (1.8 Bcf/1000')

BTAX ROR % (3)


$2.00 23%

$2.50 39%

$3.00 62%

CPA Utica Type Curve (3.5 Bcf/1000')

(1) Assuming 9,000 ft lateral @ 750 ft inter-lateral spacing (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing (3) Escalation not applied to gas pricing, capex, and opex (4) IP held flat for 14 months at 21.6 MMcf/d Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

BTAX ROR % (3)


$2.00 63%

$2.50 107%

$3.00 152%

Assumptions

IP (MMcf/d) 13.3

Decline 69%

B-factor 1.65

EUR/1000’ (Bcf) 1.8


Wells Per Pad 6



LOE ($/Mcf) $0.12


Reserves Detail


BTU 1,000


WI / NRI (%) 100% / 88%

Net Locations(1) ~1,465


Assumptions

IP (MMcf/d)(4) 21.6

Decline 74%

B-factor 1.20

EUR/1000’ (Bcf) 3.5


Wells Per Pad 6



LOE ($/Mcf) $0.05


Reserves Detail


BTU 1,010


WI / NRI (%) 100% / 89%

Net Locations(2) ~1,177


28

Asset Region 4: Ohio Overview

Total Ohio Utica:


• Total NRI: 89%

Utica Dry:

• Average EUR/1,000’ of 2.8 Bcfe(1)

• 23,000 net undeveloped acres

• Continued development of Monroe County

• 101 net locations

Utica Wet:

• Average EUR/1,000’ of 2.1 Bcfe(2)

• 42,000 net undeveloped acres

• Continue to monitor pricing for continued development

• 305 net locations

(1) Average EUR represents the type curve guidance area depicted on the map by a solid blue line (Utica Dry) (2) Average EUR represents the type curve guidance area depicted on the map by a dotted blue line (Utica Wet) Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx





0

5,000

10,000

15,000

20,000

25,000

30,000

0

100,000

200,000

300,000

400,000

500,000

0 12 24 36 48

NG

L/C

ND

Pro

du

ctio

n (

BB

L/m

on

th)

Gro

ss G

as P

rod

uct

ion

(M

cf/m

on

th)

Months After TIL

Gas

NGL

CND

0

100,000

200,000

300,000

400,000

500,000

600,000

0 12 24 36 48

Gas

Pro

du

ctio

n (

Mcf

/mo

nth

)

Months After TIL

9000' LL

29

Ohio Modeling Inputs and Economics

OH Wet Utica Type Curve (2.1 Bcfe/1000')

OH Dry Utica Type Curve (2.8 Bcf/1000')

BTAX ROR % (4)


$2.00 13%

$2.50 27%

$3.00 47%

BTAX ROR % (4)


$2.00 55%

$2.50 90%

$3.00 127%

Assumptions

IP (MMcf/d) 16.3

Decline 71%

B-factor 1.40

EUR/1000’ (Bcfe) 2.1


Wells Per Pad 5

NGL Yield (Bbl/MMcf)(3) 32.6

CND Yield (Bbl/MMcf)(3) 4.0


Fixed Cost ($/mo./well) $1,371

LOE ($/Mcf) $0.29

Gathering/Processing

($/Mcf) $0.78

NGL OpEx ($/Bbl) $6.78

CND OpEx ($/Bbl) $6.25

Assumptions

IP (MMcf/d) 20.4

Decline 56%

B-factor 1.10

EUR/1000’ (Bcf) 2.8


Wells Per Pad 4



LOE ($/Mcf) $0.05


Ohio Wet - Reserves Detail


BTU 1,150

Ohio Wet - Interest / Net Locations

WI / NRI (%) 50% / 45%


Ohio Dry - Reserves Detail


BTU 1,060

Ohio Dry - Interest / Net Locations

WI / NRI (%) 100% / 89%


OH Utica Total



(1) Assuming average 8,500 ft lateral @1,100’ spacing (2) Assuming 8,000 ft and 9,000 ft lateral @ 1,100’ spacing for Ohio Wet and Ohio Dry, respectively (3) See NGL and CND assumptions on type curve data file located at www.consolenergy.com (4) Escalation not applied to gas pricing, capex, and opex Note: NRI excludes potential partial amendments to existing leases and adverse or third party acreage within drilling units.

Virginia Coalbed Methane

Virginia coalbed methane (CBM): • 267,000 net acres

- 88,000+ undeveloped acres - WI / NRI: 100% / 87.5%

• 4,000+ wells online - 3,690 future locations - 0.5 Bcf/well average EUR - 2,000+ refrac opportunities

• Net production: 182 MMcf/d - Annual decline rate of approximately 5-7% - Access to multiple markets: TCO, ETNG Mainline,

Transco Zone 5

30

Capex(1) Opex(2) D&C Cycle Time(3)

2015 $300,000 $1.63 93 2016E $223,000 $1.42 29 2017E $215,000 $1.20 19

(1) Average combined capital per well (2) Cash costs ($/Mcf) (3) Days spud to TIL Note: Asset region type curve data and modeling inputs available at http://media.corporate-ir.net/media_files/IROL/66/66439/2016_Investor_Day/CNX_Asset_Region_Type_Curves.xlsx

0%

10%

20%

30%

40%

50%

60%

$2.50 $2.75 $3.00 $3.25 $3.50

Future Locations Refracs

38%

28%

CBM IRR





Development Methodology

31

CONSOL utilizes a portfolio

optimization development methodology to: • Assess the value of the assets

within the portfolio to drive decision making targeted towards maximizing NAV/share

• Assess the risk associated with developing the assets within the portfolio

• Determine investment, acquisition and divesture opportunities to optimize E&P portfolio

Asset

Assessment

GIS Mapping

Geology/ Reservoir

Engineering

Land, Title, JAD

Marketing Water Midstream Drilling,

Completion, Production

Purchase Additional FT

Land Swap Potential

Build Pipeline/ infrastructure

Water Optimization Opportunities

Pick up/ Lay Down

Rigs

Complete DUCs

1722

(200)

(100)

-

100

200

300

400

-

50

100

150

200

250

300

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

$M

M

Ne

t M

mcf/

d

Monroe Optimized CaseAvg Daily Production Net wells drilled

Cumulative PV (Secondary)

Performance Studies Portfolio Classification Asset Development and Optimization Monte Carlo Risk Analysis

New World View: Stacked Pay

Rhinestreet

Middlesex

Burkett

West River

Formation Name

Pay

Cashaqua

Tully

Hamilton

Marcellus

Onondaga

Utica

Point Pleasant

Trenton 0 GR 400 LITHOLOGY

32

• 40+ years of stacked pay inventory(1)

• The JV separation gives CONSOL complete operational control in stacked pay opportunities

• The Upper Devonian provides triple stacked pay potential, on top of Marcellus and Utica

• Stacked pays allow CONSOL to take advantage of a dry gathering system

• $0.10-$0.25/Mcfe Utica gathering

• Stacked pays take advantage of infrastructure sunk capital

(1) Stacked pay inventory includes core and non-core undeveloped acreage

Stacked Pay Value for SWPA: Pad Level Example

33

Stacked Pay Efficiencies

Unstacked Stacked Unstacked Stacked

LOE ($/Mcf) $0.12 $0.05 $0.15 $0.05

Gathering Rate ($/Mcf) $0.45 $0.39 $0.24 $0.18

Capital ($ in thousands) $5,900 $5,450 $13,200 $12,300

Dry Marcellus Dry Utica

Stacked pay development improves IRR by 10-20 percentage points

• Marginal horizons may be pulled into the development plan due to stacked pay economic improvement

• Stacked pay development concentrates large-scale operations in a small footprint

• Concurrently developing two horizons enables cost effective infrastructure build-out for both plays

• Significant reduction in both lifting and gathering operating costs due to higher volumes

(1) Assumes six Marcellus wells and four Utica wells per pad; 7,000’ laterals

Stacked Pay Pad Economics Example(1)

0%

20%

40%

60%

80%

100%

120%

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$2.00 $2.50 $3.00

BTA

X IR

R (

%)

BTA

X N

PV

($

in m

illio

ns)

Gas Price

Unstacked NPVStacked NPVUnstacked IRR %Stacked IRR %

Stacked Pay Value for SWPA Marcellus: Well Level

34

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

1.3

2

1.3

8

1.5

6

1.6

5

1.7

5

2.0

5

2.3

9

2.4

2

2.5

0

2.6

4

2.6

6

2.6

6

2.6

9

2.7

8

2.8

2

2.8

7

2.9

5

2.9

5

2.9

6

3.2

2

3.2

5

3.2

7

3.3

4

3.3

8

3.4

5

3.9

1

3.9

7

4.0

6

4.1

9

4.2

2

4.3

3

4.7

2

5.5

0

BTA

X IR

R (

%)

EUR/Capex (Mcfe/$)

Unstacked Stacked Pay

2016 Capital Efficiency

Stacked Pay Potential

Capital Efficiency Mcfe/$

Unstacked (actual) 2.78

Stacked (potential) 3.02

Change +9%

BTAX IRR +15 percentage points

Stacked Pay Optimization: Richhill Field

• 33% NPV uplift due to stacked pay development

• 17,000 Marcellus acres with Utica rights

• Marcellus damp gas on its own requires processing

• Blending Marcellus with dry Utica gas allows the avoidance of processing costs

• Concurrent development of Marcellus and Utica reduces capex and opex and increases combined NPV

• 100% WI provides CONSOL ability to maximize field NPV through stacked pay development flexibility

35

Richhill Optimization

Richhill Case Study

Marcellus Utica Stacked % Difference

Well Count 125 123 248 N/A

BTU 1,130 1,015 1,070 N/A

Opex ($/Mcfe) $1.16 $0.32 $0.41 -46%

Capex ($ in millions) $829 $2,007 $2,630 -7%

NPV ($ in millions) $317 $389 $939 +33%

Upper Devonian: Rhinestreet and Burkett

Provides triple stacked pay potential, on top of Marcellus and Utica

• 235,000 net acres

• 16 operated Upper Devonian wells

• Combination with Marcellus and Utica development driven by gas price trigger

0%

10%

20%

30%

40%

50%

60%

70%

$2.00 $2.50 $3.00 $3.50 $4.00

BTA

X IR

R (

%)

$/MMBtu

36

SWPA 7000’ Burkett

Delineation Schedule (Gross Wells)

2016 2017 2018 2019

2 3 4 4

37

Moving Utica Non-Core to Core

Delineating the Utica through operated

and non-operated wells, data trades, and data purchases:

• Provides geologic and reservoir data to

evaluate NAV impact and helps assess

development risk

• 170,000 dry Utica core acres

• Potential to increase core position by

250,000+ acres by expanding the core

Delineation Opportunities

Non-Operated TIL Forecast (Gross Wells)

2016 2017 2018

Utica 13 17 15

X X X

GH-9 Greene Co. PA

3rd Party Harrison Co. OH

3rd Party Guernsey Co. OH

3rd Party Washington Co. PA

X

Aikens-5 Westmoreland Co. PA

X X

3rd Party Indiana Co. PA

3rd Party Monongalia Co. WV

X

MAJ-6 Marshall Co. WV

X

SWPA Prospect Allegheny Co. PA

X

CPA Prospect Westmoreland Co. PA

X

SWPA Prospect Greene Co. PA

X

SWPA Prospect Greene Co. PA

X

WV Prospect Monongalia Co. WV

X Jan-16 Jan-17 Jan-18 Jan-19 Dec-19

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

Cas

ing

Pre

ssu

re (

psi

)

Flo

w R

ate

(Mcf

/d)

Flow Rate MCf/Day Casing Pressure

• Consistent reservoir and geologic conditions indicate additional wells in the Gaut area should have similar performance

Gaut 4IH 61.4 MMcf/d IP Initial SICP = 9,921 psig 5,808’ Lateral Length 7.8 Bcf by 01/2017

38

Why We Love the Utica: Gaut 4IH Westmoreland County, PA

Testing period Mcf/d

Stacked Pay with the Utica: The Size of the Prize

39

360,000+ Net Acres

20 Tcfe

Recoverable Resource in Place

5,000+ Triple Stacked Core Locations

40+ Years of Drilling

• 360,000 net acres of double stacked pay opportunity

in the core and non-core areas

• 180,000 core acres with double stacked pay opportunity

• Utica stacked pay delineation in the next 2 years drives

stacked pay development

• 30 Utica non-operated participation wells

• Concentrates the footprint of stacked pays: Upper Devonian

(Rhinestreet, Burkett), Marcellus and Utica

• Accelerates locations into the near-term plan by uplifting

lower value formations

• The Marcellus and Utica stacked pays supports a 4-rig

program for over 40 years

• Drilled 14 dry Utica wells and participated in 18 other wells

Two-Year Development Plan

• Consistently complete DUCs from December 2016 through 2018

- Total of 33 DUCs to be completed in two-year plan

• High value areas in Monroe County, OH and SWPA will be developed throughout 2017, 2018, and beyond

• Delineation prospects will continue to be drilled and evaluated

40

2017 2018TD FRAC TIL Capex TD FRAC TIL Capex

Marcellus 12 13 13 $80 54 42 40 $260

Utica 0 0 0 $0 3 3 3 $40

Upper Devonian - 2 3 $15 - - - -

Marcellus - 20 18 $95 - - 2 $10

3rd Party Marcellus 2 11 11 $5 4 - - $5

CPA Utica 2 2 2 $25 1 1 1 $15

Utica 17 22 22 $210 12 15 13 $140

3rd Party Utica 20 20 20 $15 16 16 16 $25

VA CBM 61 51 51 $20 28 33 33 $5

TOTAL(1) 31 59 58 $465 70 61 58 $500

SWPA

WV

OH

($ in millions)

(1) Total includes CONSOL-operated Marcellus, Utica, and Upper Devonian TD, Frac, and TIL for 2017E and 2018E

E&P Capital Expenditure Guidance

($ in millions) 2016E 2017E 2018E

Drilling and Completion $175 $465

Midstream $20 $40

Land, Permitting, and Other $10 $50

Total E&P and Midstream Capital $205 $555 $600

Total Production (Bcfe) 395 415 485

Expected Production Growth 20% 5% 17%

41

2017E E&P Capital Plans

• Capital expenditure projections based on current market conditions and forecast

- Flexibility exists to adjust spending as necessitated by commodity fluctuations

• Increase in Land, Permitting, and Other capital driven by return to activity and blocking up acreage

• Running three rigs by end of 2017

• To hold 2016E production flat in 2017, maintenance capital would be approximately $250-$300 million

Drilling & Completions

84%

Midstream 6%

Land, Permitting, and Other

10%

E&P Capital and Production Plans

E&P MARKETING

42

E&P Marketing: NAV/Share Drivers

43

MAXIMIZING CASH FLOW AT THE WELLHEAD

FLEXIBLE FT STRATEGY TO MINIMIZE COSTS AND ENSURE PRODUCTION GROWTH

SIGNIFICANT HEDGE BOOK PROTECTING DOWNSIDE, WHILE PRESERVING MEANINGFUL UPSIDE

E&P Marketing

44

Ability to deal with the increasing uncertainty in a volatile marketplace:

• A consistent, yet flexible strategy is necessary to help mitigate the uncertainty

• Strategic and tactical expertise

Contributing to NAV/share through a "barbell" strategy: • Previously focused primarily on providing operational support

• Focused now on providing strategic support that drives corporate decisions

• Planning, revenue management, and hedging are now one fluid process

• Ensuring near-term financial success while adding future value through additional hedging and new

approaches

Programmatic Hedging

• Create incremental free cash flow (FT cost & capacity optimization, ensure gas flow, diverse sales portfolio)

• Asset management agreements

• Dry / Wet optionality

• Arbitrage pipeline flexibility, create 3rd party opportunities

• Utilize flexibility

CURRENT & NEAR TERM

LONGER TERM

• Enhanced risk management

• Capital allocation protection

• Develop arbitrage opportunities and new diversified netbacks

• Maintain efficient flexibility

• Additional margin

& balance sheet protection

Increased Volatility

45

U.S. LNG Export Forecast Current infrastructure and systems are not built to handle new gas market:

• Storage capacity has remained the same, while supply has increased significantly

- 50 Bcf/d in 2005 vs. approximately 75 Bcf/d in 2017

• Existing supply quickly falls, over 20% per year, if drilling slows

• Demand sensitivity to price and weather is increasing significantly

- LNG and Mexican exports - Increased power and heating use

• A supply and demand imbalance of only 2 Bcf/d on average for a year, is the difference between an alarmingly high inventory level coming out of winter and an alarmingly low inventory level coming out of winter

The system is bigger and more volatile on both the supply and demand sides with the same amount of storage, leading to increased volatility

$0

$1

$2

$3

$4

$5

$6

$7

Henry Hub and Dominion South Pricing (Historical First of Month and Forward Strip)

Dominion South Henry Hub

Source: Morningstar

Source: Historical prices-SNL; Strips- Intercontinental Exchange and CME

Volatility Can Be Good

46

Take-away capacity is coming to the region:

• Over 18 Bcf/d of projects in process: question of when, not if

• Only need half to come online by 2018 to support the expected production growth

• It will all eventually come online to allow a visible growth path for the next 5+ years

A normal or colder-than-normal winter will have a large effect:

• Inventory levels are not excessively higher than they have been in the past

• The demand pull on the system is higher than it has ever been (power, heating, Mexico, LNG)

Working Gas Inventory (Bcf):

• Region proven it can handle approximately 7 Bcf/d of extra supply

• Supply relative to demand and storage can swing positive as quickly as they have swung negative, and CONSOL is positioned to succeed under either situation

Projected Basin Takeaway Capacity

Year Year Prior Max Year Min. Avg. NYMEX Price

2014 3,834 824 $4.42

2013 3,928 1,674 $3.65

2016E 4,009 2,468 $2.46

2017E 4,017 ? $3.25

Source: Historical Supply-Spring Rock; Demand + Takeaway and Supply Potential-various public sources, CONSOL interpretation

Source: EIA

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

Ave

rage

MM

cf/d

Demand + Takeaway Capable Excess

AVG Supply Supply Potential

The Benefits of Flexible Firm Transportation

47

FT strategy:

• Sufficient short- and long-term FT at a cost lower than peers going to markets that maximize netbacks without over-committing

- Use FT, IT, AMAs, customers’ capacity, varying terms, releases, etc.

• NYMEX differentials in-line with peer average, with 1/8 of the average “take-or-pay” FT obligation of peers

• Keep basis differentials lower than the cost of greenfield FT prices

• Proactively ensure CONSOL can grow production

Basis plan will utilize:

• A unique sales focus for each market

• Strategically selecting FT

• Diversified sales portfolio

• Programmatic basis hedges placed years in advance

• Opportunistic basis hedges when appropriate

(1) Company filings as of Q3 2016; gas price differentials based on first nine months of 2016 Note: Peers include AR, CHK, COG, EQT, GPOR, RICE, RRC, SWN

$(2.00)

$(1.50)

$(1.00)

$(0.50)

$-

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$16.0

$18.0

$20.0

CNX 1 2 3 4 5 6 7 8

Dif

f. t

o N

YMEX

($

/MM

Btu

)

Tota

l Ob

ligat

ion

s ($

in b

illio

ns)

Transportation, Gathering, & Processing Commitments and Differentials(1)

FT, Gathering, and Processing Obligations

Gas Price Diff. to NYMEX

Peer Average Gas Price Diff to NYMEX

The Benefits of Flexible Firm Transportation (Cont’d)

48

Avoiding long-term, burdensome FT on new projects that go underwater:

• Many greenfield project demand fees appear to exceed the forecasted price uplift at various basis locations

• Short-term gains will be minimal compared to long-term deterioration

• Avoiding significant, long-term exposure to out-of-the-money positions

$-

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

2018 2019 2020 2021 2022 2023

Esti

mat

ed

$/D

th

Future Spreads vs. Estimated Demand Fees(1)

Project A Spread Project B Spread Project A Calculated Fee Project B Calculated Fee

(1) Project costs were obtained from FERC filings; demand fees conservatively estimated using only expected project costs and an assumed 15% rate of return

Firm Transportation Management

49

Diversified sales and FT portfolios:

• Result in competitive basis differentials and

balanced basket of prices

• Strategically aligned with the best AMA partners in

our markets to optimize asset value and realize

other tangible benefits

• In-basin exposure mitigated through basis hedge

program and diversified sales mix

Positioned significantly ahead of peers as

in-basin market stays volatile: • Peers’ expensive long-haul FT cost will fluctuate

with netbacks being in and out of the money

• Will limit their flexibility and tend to worsen with

time as more costs hit their income statements

and they face minimum volume commitments in

more recent contracts

0

200

400

600

2016 2017 2018

Bcf

Sales Portfolio Market Mix

In Basin Open In Basin Hedged East Coast Total

Far Midwest Total Gulf Total

In-Basin Prices and Basis 2017E-2022E

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

2017 2018 2019 2020 2021 2022

An

nu

al P

rice

($

/MM

Btu

)

TETCO M2 NYMEX

Source: Intercontinental Exchange and CME

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

MM

Btu

/d

Cumulative NYMEX Hedges Cumulative Basis Hedges

Hedging Strategy

50

Newly instituted programmatic hedge program:

• Systematically layering in hedges to protect margins on up to 90% of proved developed production

• Protecting from in-basin blowout through regional basis hedges

• Lock in revenue: Match NYMEX and basis hedge volumes

We are hedging PDP volumes out to 2020:

• Systematic approach protects from market downturns

• Increased drilling activity and opportunistic hedge program capture market upswings, de-risking capital decisions

Hedge Position (Outer ring = NYMEX; Inner ring = Basis)

Hedge Volumes and Pricing FY 2017 FY 2018 FY 2019 FY 2020

NYMEX Only Hedges Volumes (Bcf)

233.8

187.3

124.3

62.1

Average Prices ($/Mcf) $ 3.08 $ 3.13 $ 3.07 $ 3.19

Index Hedges and Contracts

Volumes (Bcf) 32.4 - 6.8 3.4 Average Prices ($/Mcf) $ 3.19 - $ 2.54 $ 2.35

NYMEX + Basis (fully-covered volumes) Volumes (Bcf)

263.8

177.3

103.5

53.7

Average Prices ($/Mcf) $ 2.52 $ 2.66 $ 2.61 $ 2.79

NYMEX Only Hedges Exposed to Basis Volumes (Bcf)

2.4

10.0

27.6

11.8

Average Prices ($/Mcf) $3.08 $ 3.13 $ 3.07 $ 3.19

Total Volumes Hedged (Bcf)(1) 266.2 187.3 131.1 65.5

(1) Hedge position as of 12/7/16. Includes financial and physical hedges.

Hedged Open Hedged Open

2017 2018

Hedges made across different years and different

sales points for basis throughout the year

NGL Strategy

51

Processing flexibility on a third of wet volumes:

• Avoid processing fees when NGL pricing is low

• Capture NGL uplift during peak pricing

• Leverage dry Utica blend-stock

Plant optionality on nearly half of wet volumes:

• Optimize on residue gas takeaway

• Enhance NGL marketability

• Drive down costs through competition

Direct ethane sales netbacks tracking Mt. Belvieu pricing:

• Achieved without burdensome FT commitment

• Equivalent of selling gas with a +$0.68/MMBtu basis

40% of C3+ in 2017-2018 expected to be sold internationally:

• Exposure to multiple price points

• Over half of production will stay domestic to feed increasingly attractive markets

2017 Direct Ethane Sales Netback Estimate(1)

Gas $ High

Gas $ Low

NGL $ Low NGL $ High

Avoid Processing

Optimize Send to Processing

Optimize

22 Bcf

Wet Gas Flexibility

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

2017

Eth

ane

($/g

al)

Mt. Belvieu Ethane CNX Netback Appalachian Gas Alternative

(1) As of 11/28/16 forward strip (2) Avoiding approximately $0.16/gal cost and long-term commitment to obtain Mt. Belvieu pricing

(2)

Key Marketing Financial Parameters

52

(1) Based on 12/6/2016 strip prices

Expected Market Mix 2017E 2018E

Columbia (TCO) 14% 16%

TETCO (M2) 38% 41%

TETCO (M3) 12% 7%

Dominion (DTI) 15% 13%

East Tennessee 9% 7%

TETCO ELA & WLA 6% 5%

Midwest (Michcon) 6% 11%

100% 100%

Estimated utilized firm transportation demand expense ($ in millions) $77.2 $108.4

Estimated firm transportation demand expense per unit of production ($/Mcf) $0.21 $0.24

Expected average basis w/o regard to hedging (based on market mix) ($/Mcf) (1) ($0.63) ($0.50)

Expected average basis, including hedges currently in place ($/Mcf) (1) ($0.58) ($0.47)

Volumes with basis currently hedged (Bcf) 263.8 177.3

Average price of basis hedges currently in place ($/Mcf) ($0.62) ($0.47)

% of production 70% 40%

DIVERSIFIED BUSINESS UNITS

53

Diversified Business Units: NAV/Share Drivers

54

$400-$600 MILLION IN 2017 ASSET SALES

GROWING MISCELLANEOUS OTHER EBITDA

SIGNIFICANTLY REDUCING LEGACY LIABILITIES

CONSOL has a strong track record of successful divestitures:

• 20 NAV-enhancing divestitures since 2012

• Over $5 billion of combined value

Team is now focused on divesting E&P assets:

• Recent Marcellus JV separation provides more control and flexibility with asset base

• Continually evaluating NAV-accretive opportunities

CONSOL has a significant asset base:

• 60+ years of drilling inventory

• Acres all throughout the Appalachian basin in all horizons

Flexible approach:

• Outright sales

• Swaps and trades

• AMI / participations

• Acquisitions

2017 total asset sales target between $400-$600 million

55

Business Development: Strategy

Other Miscellaneous: Income and Expense Sources

Miscellaneous Other Income 2016E 2017E 2018E

Baltimore Terminal

Royalty Income

Right of Way Sales

CONVEY Water Systems

Rental Income & Other

Miscellaneous Other Costs 2016E 2017E 2018E

Baltimore Terminal

Lease Rental Expense

Coal Reserve Holding Cost


Long-Term Liabilities

Bank Fees and Other

Net of Income and Cost ($MM) -$60 to -$65 -$15 to -$20 -$10 to -$15

56

Increasing value from a range of often overlooked sources:


57

Provides water related services for CNX and third party upstream E&P companies:

• Fresh water delivery for well completion operations

• Recycle and disposal of produced fluids

• One of the largest water pipeline network in Appalachia

• 2017E water life cycle management of approximately 2.8 million gal/day

• Rapid expansion of 3rd party customer base

• Leverage expansive pipeline system and surface acreage position to achieve best in class operating cost

• Volumetric service fee structure provides revenue and operating cash flow

Organic value creation through spin-off or drop-down opportunity

• Highly attractive midstream EBITDA valuation multiple (9.0x – 12.0x)

Projected 2017 EBITDA of approximately $50 million

Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. 2017 EBITDA projection is based on rates charged to CNX Gas, which are subject to change

CONVEY Water System Assets Marcellus Utica Other Total

Water Pipelines (Miles) 291 18 216 525

Storage Impoundments 8 1 9

Water Sourcing Dams 2 2

UIC Well 1 1

2017 CONVEY Capex ($MM) 15 10 25

2017 Water Pipelines (Miles) 10 15 25

2017 Storage Impoundments - - -

Total 2017 Infrastructure

Water Pipelines (Miles) 301 33 216 550

Storage Impoundments 8 1 - 9

Water Source 2 2

UIC well 1 1

Baltimore Marine Terminal

58

Overview: • Coal export terminal

• 15 million tons per year capacity throughput; 1.1 million tons coal storage yard capacity

• Strategically located: able to access the attractive seaborne markets supplying both Europe and Asia

• The only coal export terminal on the East Coast served by two railroads: Norfolk Southern and CSX Corporation

Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

2016 achievements: • Baltimore Terminal expected to generate approximately $15 million in EBITDA for a projected 8.5 million ton

throughput, despite challenging coal export market conditions in 2016

• Opened the terminal up for throughput capacity from third party shippers: Signed 3 million tons in 2017 (with take or pay provisions) from third party shipping contracts in addition to legacy contracts of 12 million tons reserve (not take or pay)

• Achieved significant service and operating cost efficiencies in 2016

2017 outlook: • Strong met and stronger thermal export market indications provide reasonable expectation of 9-10 million

ton throughput providing $19-$22 million of EBITDA

• Cost savings of at least $1 million from scheduling and supply chain optimization

Recent Transactions: Legacy Assets

59

Buchanan Mine transaction:

• Includes potential royalty payment based on rising met coal prices

- 20% royalty on export sales of any excess of the gross FOB mine sales price over certain minimums that increase each year and end after five years

• Solid met coal pricing in recent quarters has positioned CNX to receive a royalty in Q4 2016

• 2017 forecasted EBITDA associated with the Buchanan royalty is forecasted to be between $10-$20 million

Miller Creek / Fola transaction:

• Eliminated small non-core coal operation

• Removed $100 million of long-term liabilities from CONSOL’s balance sheet

• Sold approximately 230 million and 185 million tons of reserves or resources, respectively, in the two complexes

Example Average Buchanan Mine Monthly Export Price(1) $ 150.00

Royalty Threshold Price (Year 2) $ 78.75

Average Export Sales Price Over Threshold $ 71.25

Royalty 20%

Royalty Revenue Per Ton at 20% $ 14.25

Example Annual Export Tons(1) 2,500

Example Annual Royalty Revenue ($ millions)(2) $ 35.6

(1) Average monthly export price and export ton quantity for example purposes only (2) Due to uncertainty in metallurgical coal markets, CONSOL uses a risked view for planning purposes Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

Example 2017 Royalty Calculation

Financial: Legacy Liabilities

Significant legacy liability reductions over

past three years: • Miller Creek/Fola transaction drove

substantial reduction in legacy liabilities

in 2016

• Continue to actively manage the reduction

of legacy liabilities

60

Balance Sheet Liability Long-Term Liability Guidance

12/31/2016E FY 2017 FY 2018

LTD $17

WC 82 CWP 125

OPEB 655

Salary Retirement/Pension 89

Asset Retirement Obligations 227

Total Legacy Liabilities $1,194

Total Cash Servicing Cost $95 $74 - $79 $70 - $75

EBITDA Impact ($60 - $65) ($18 - $23) ($21 - $26)

Note: 12/31/16 liability balance includes approximately $33.5 million and $34.1 million in employee-related and environmental liabilities associated with Pennsylvania Mining Operation (PAMC), respectively. Future EBITDA loss and cash servicing costs related to these liabilities will run through the PAMC segment financial detail and therefore the cash servicing costs and EBITDA loss related to these liabilities are excluded from the 2017 & 2018 forecast presented above. For FY 2017, the cash servicing costs associated with PAMC LTL are forecasted to approximate $8.1 million, while the EBITDA loss associated thereto is forecasted to approximate $11.9 million. Excludes gas well closing.

$4,187

$1,703 $1,497 $1,362

$1,194

$365

$144 $139 $133

$95

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

2012 2013 2014 2015 2016E

An

nu

al C

ash

Ser

vici

ng

Co

sts

($ in

mill

ion

s)

Lega

cy L

iab

iliti

es (

$ in

mill

ion

s)

Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost

FINANCE

61

Finance: NAV/Share Drivers

62

REDUCING COST OF CAPITAL

CAPITAL ALLOCATION

IMPROVING FORECASTING CAPABILITY AND TRANSPARENCY

Financial Accomplishments Since 2014

Reduced Debt

By attacking all parts of our business, we have reduced the nominal and per unit spend by 45% and 55%, respectively.

Paid down approximately $1 billion in debt

Managed Legacy Liabilities

Reduced legacy liabilities by approximately $300 million and annual cash service costs by approximately $50 million

Launched Two MLP IPOs

Created CNXC and CONE Midstream MLPs to provide clarity for investors and followed each IPO with an additional drop

Drove Down Operating Costs

Dramatically reduced operating costs to be competitive with top-tier Appalachian E&Ps

Lowered SG&A Incorporated zero-based budgeting and substantially reduced SG&A with a range of initiatives

63

Tools to Grow NAV/Share

64

Safety

Compliance

Operating Efficiencies

Liability Management

Capital Allocation

Revenue Management

NAV/Share Growth

Prudent capital allocation is one of the most important tools to grow NAV/share; a clear and consistent methodology to assess capital allocation options and make decisions is essential.

Zero-Based

Budgeting

Capital Allocation Decision Making

Production

KEY PERFORMANCE METRICS

Proved Reserves

Borrowing Base PV9

Discount Rate

Free Cash Flow

Liquidity

NAV/Share

Managing Risk Appropriately Throughout the Commodity Cycle

Leverage Ratio

CAPITAL SOURCES CAPITAL USES

• Pulling back capital spend/activity level

• Selling assets/drop downs

• Issuing debt

• Issuing equity

• Reducing dividends/distributions

• Developing high rate of return Marcellus and Utica opportunities

• Paying down/buying back debt

• Buying back equity to reduce share count

• Paying dividends/distributions

• Acquiring assets (M&A)

65

2017E-2018E E&P Capital Allocation

66

Note: Based on D&C capital

Ranking projects and capital allocation priorities 2017E-2018E

Full Well IRR

Sunk Cost IRR

DUCs

CPA Utica

OH Dry Utica

SWPA Marcellus

VA CBM SWPA Utica

0%

10%

20%

30%

40%

50%

60%

70%

IRR

Benchmarking: Capital Yield Has Been Improving

67

Note: Methodology and 2014-2016E peer estimates from KLR Group. CNX 2016E-2018E based on internal plan. Capital Yield = E&P Operating Cash Margin / (CapEx/Change in Production) * Initial Recovery Percentage. Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN.

• Focused on improving capital yield through reducing capital intensity and operating costs

• Disciplined capital spending through the downturn positioned the company to dramatically improve its 2016 and 2017 capital yield

• Driving down operational expenses have improved cash margins in a depressed pricing environment

• As operational initiatives continue to take root, CONSOL is expected to maintain capital efficiency levels well above historical averages

-20%

30%

80%

130%

180%

1 2 3 4 5 6 7 CNX -20%

30%

80%

130%

180%

1 2 3 4 5 6 7 CNX -20%

30%

80%

130%

180%

CNX 1 2 3 4 5 6 7

2014: Capital Yield 2015: Capital Yield 2016E: Capital Yield

CONSOL Capital Yield 2014-2018E

-20%

30%

80%

130%

180%

2014 2015 2016E 2017E 2018E

-

50

100

150

200

250

300

2012 2013 2014 2015 2016E 2017E 2018E

$ in

mill

ion

s

Cash SG&A Expense Stock Compensation

SG&A Nominal and Unit Reductions

$0.55

$0.31

$0.20

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

2014 2015 YTD 2016

SG&

A S

pen

d (

$/M

cfe(2

) )

CNX E&P E&P Peers Average

Total Company SG&A(1) 2012-2018E

(1) Historical years recast to align with current reporting. Total includes stock compensation and short-term incentive compensation in all periods. (2) Cost per Mcfe excludes stock-based compensation. Peers include AR, COG, EQT, GPOR, RICE, RRC, SWN.

• Initial declines tied to asset divestitures

• Implemented zero-based budgeting in 2015

• Reduction of top five executive pay by combined approximately 50%

• Termination of various corporate perks and arena naming rights

• Reorganized to be able to fully separate E&P and coal in 2017

Since 2014, CONSOL Energy has reduced its SG&A $/Mcfe faster than its peers

68

SG&A $/Mcfe 2014-YTD 2016

Improving Transparency: E&P Guidance

Note: Forecast based on strip pricing as of 11/3/2016 close (1) Excludes stock-based compensation (2) Includes Idle Rig Charges, Unutilized Firm Transportation Expense (Net Of 3rd Party Revenue), Land Rentals, Lease Expiration Costs, Misc. Gas, and Exploration Expense

69

E&P Segment Guidance 2016E 2017E 2018E

Production Volumes:

Natural Gas (Bcf) 348 375 445 NGLs (MBbls) 6,740 5,800 5,950 Oil (MBbls) 70 45 40 Condensate (MBbls) 860 740 730

Total Production (Bcfe) 395 415 485 % Liquids 12% 10% 8%

Open Natural Gas Basis Differential to NYMEX ($/Mcf), as of 11/03/16 ($0.60) ($0.63) ($0.50) NGL Realized Price ($/Bbl) 14.00 16.00 16.50 Condensate Realized Price % of WTI 70% 70% 70% Oil Realized Price % of WTI 90% 90% 90%

Capital Expenditures ($ in millions):

Drilling and Completions $175 $465 Midstream $20 $40 Land, Permitting and Other $10 $50

Total E&P and Midstream CapEx $205 $555 $600 Average per unit operating expenses ($/Mcfe):

Lease Operating Expense 0.26 0.23 Production, Ad Valorem, and Other Fees 0.08 0.07 Transportation, Gathering and Compression 0.93 0.77

Total Cash Production and Gathering Costs 1.27 1.06 1.05

Other Expenses ($ in millions):

Selling, General, and Administrative Costs(1) $70 $70 $70

Other Corporate Expenses(2) $70 $80 $60

PA Mining Operations Guidance

70

• Due to mines being well capitalized, CNXC was able to reduce capital spending on discretionary projects to offset the challenging coal market conditions, heading into 2016

• Capital expenditures expected to revert to the approximately $5 per ton starting in 2017 and beyond

PA Mining Operations 2016E 2017E 2018E

Estimated Total Coal Sales Volumes (in millions of tons) 24.0 26.5 26.5

Total Committed Volumes (Contracted & Priced) 23.3 23.1

% Committed 97% 87%

Capital Expenditures ($ in millions):

Production $70 $120

Other (Land/Water/Safety) $20 $15

Total Coal Capital Expenditures ($ in millions) $90 $135 $140

EBITDA Guidance

(1) Includes forecasted Earnings of Equity Affiliates of $36 million in 2017 associated with CNX's proportionate share of ownership in CONE Midstream. This income is reflected within Miscellaneous Other Income in the CNX Income Statement.

(2) Base plan assumes NYMEX as of 11/3/2016 $2.99 + basis of ($0.70). Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

EBITDA Guidance by Segment – 2017E

EBTIDA Sensitivity to E&P Price Fluctuations vs. Plan

71

($ in millions) E&P(1) Coal Other Total

EBITDA $465 $390 ($15) $840

Adjustments:

Unrealized Gain Loss on Hedging ($5) - - ($5)

Stock-Based Compensation $20 $10 $0 $30

Adjusted EBITDA $480 $400 ($15) $865

Less: Noncontrolling Interest - ($45) - ($45)

Adj. EBITDA Attributable to CNX $480 $355 ($15) $820

2017E E&P

Base Plan(2)

(strip pricing as of 11/3/16)

Open Price (NYMEX + Basis) $1.30 $1.80 $2.30 $2.80 $3.30

EBITDA ($ in millions 690 760 820 890 960

Leverage Ratio 3.0x 2.7x 2.4x 2.1x 1.9x

E&P Reserves Guidance

72

Note: Reserve estimates follow the same approach used for calculating year-end SEC Proved Reserves. Pricing based on forward curve as of 11/03/16.

Reserves Growth Estimates 2014-2018E (Net)

2014 2015 2016E 2017E 2018E

Assumed 12 mo. average price $/MMBtu $4.35 $2.59 $2.48 $2.99 $2.94

Marcellus/Utica PUD well count (net) 458 126 201 373 485

6,200

8,000

11,000

6,827

5,643 5,800 6,500

9,000

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

0

2,000

4,000

6,000

8,000

10,000

12,000

2014 2015 2016E 2017E 2018E

Ass

um

ed 1

2 M

o. A

vera

ge P

rice

$/M

MB

tu

Bcf

e

Reserves Estimated Range Assumed 12 Mo, Average Price $/MMBTUAssumed 12 Mo. Average Price ($/MMBtu)

0.7x

1.8x 1.7x

1.3x

2.4x

2.8x

3.5x 3.4x

0.6x

1.3x 1.4x 1.5x 1.7x

2.3x 2.4x 2.7x

-

1.0x

2.0x

3.0x

4.0x

1 2 3 4 CNX 5 6 72017 Net Debt/EBITDA 2018 Net Debt/EBITDA

• Enables the company to weather volatility in commodity prices and limits the risk that leverage ratio moves into the commercial banks perceived danger zone of 3.5x or higher

• Protects liquidity; can avoid selling assets, tapping capital markets, or hedging at the bottom of cycle

• Provides additional protection in the event of a split; as E&P loses the coal cash flow and diversification benefits, the company will be smaller and have more concentration risk (as will CNXC)

• Low leveraged names in a weak market avoid a discount to share price.

2017 peer average: 2.2x(1)

2018 peer average: 1.7x

Cost of Capital: Leverage Ratio Target Between 2.0x to 2.5x

• Provides the financial flexibility to grow NAV per share through several means: drilling pace, buybacks, delineation drilling of our non-core assets, and M&A

• Maintains optimal cost of capital, enabling access to the capital markets throughout the cycle if the opportunities arise

• Increases ability to sell assets from a position of strength and maximize NAV per share

• Low leveraged names in a normal market receive a premium attached to share price

(1) Peer leverage ratios based on consensus EBITDA and consensus net debt (Capital IQ). (2) Forecasts based on strip pricing for open volumes as of 11/3/2016; assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018. Note: CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

CNX AR

EQT

RICE RRC

CHK

ECR

COG

SWN DVN

WPX

NBL

GPOR XEC

CRK

XCO

APA QEP

BBG

SD

R² = 0.8945

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

(80%) (60%) (40%) (20%) - 20%

20

15

YE

Net

Deb

t/EB

ITD

A

Esti

mat

e

Stock Performance, 12/1/14 to 7/7/15

73

Leverage vs. Stock Performance Industry Leverage Ratios 2017E-2018E

Importance of the Target: Offense Importance of the Target: Defense

(2)

Leverage Ratio and Liquidity Projection

(1) Leverage ratio equals expected year-end net debt divided by expected EBITDA. CONSOL Energy is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items.

Note: Assumes $400-$600 million in asset sales in 2017 and a 20% CNXC drop in 2018 Forecasts based on strip pricing for open volumes as of 11/3/2016

• Path to reaching and maintaining a sub-2.5x leverage ratio

• Liquidity rises by estimated $1 billion in free cash flow by 2018

• Bank revolver reaffirmed at $2 billion for fall 2016

• Plan Upside: - Increased efficiencies - Rising commodity prices - Accelerated drops - Additional asset sales

74

Leverage Ratio 2016E-2018E(1)

Liquidity 2016E-2018E

Asset Sales Organic

FCF Sources 2017E-2018E

4.7

2.4

1.7

0.0

1.0

2.0

3.0

4.0

5.0

2016E 2017E 2018E

1.7

2.3

2.7

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2016E 2017E 2018E

$ in

bill

ion

s

E&P WACC History

(1) Risk free rate is 30 year TTM risk free rate (2) Peer beta is average 2 year beta. Peers include APC, RICE, COG, PDCE, GPOR, CHK, AR, SWN, EQT Note: Forecasts based on strip pricing for open volumes as of 11/3/2016

8%

9%

10%

11%

Jan2016

Feb2016

Mar2016

Apr2016

May2016

Jun2016

Jul 2016 Aug2016

Sep2016

Oct2016

Nov2016

CNX E&P WACC Over Time

Measures taken to manage WACC:

• Created strong modeling predictability

• Reduced SG&A

• Reduced leverage ratio

• Improved liquidity

• Increased production

• Reduced unit costs

• Reduced interest expense

• Continued NYMEX and basis hedging

Goals:

• Further reduce debt

• Repurchase high cost equity

• Improve outlook and E&P team coverage from ratings agencies

Sample WACC Calculation

CNX E&P Cost of Capital Nov-16

Equity

Risk Free Rate(1) 2.6%

Beta (Peer Beta)(2) 1.4

Equity Market Risk Premium 6.5%

Cost of Equity 11.7%

Debt

Risk Free Rate (TTM) 2.6%

Spread To Treasury 5.5%

Pre-Tax Cost of Debt 8.1%

Marginal Tax Rate 38.0%

After Tax Cost of Debt 5.0%

Enterprise ($ in millions)

Market Capitalization 4,045

Market Value Net Debt 3,042

Enterprise Value 7,087

WACC 8.8%

75

Annual E&P WACC 2014 2015 2016

11.2% 10.1% 8.8%

CONE Midstream Drives Value to CONSOL Energy

CONE Midstream Partners LP value to CNX is comprised of four main drivers:

How CNX views the total value of CONE Midstream Partners LP:

Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR

76

CONE Value Streams to CNX($ in millions, except per share data) 2016E 2018E

IDRs

Cash Flow 1.87$

Multiple 30.0x

Ownership 50.0%

Value 28$

LP Units

Unit Price 21.00$

Current Yield 4.9%

Units Held 21.69

Distributions through 2018 -

Value 456$

CONE Gathering

Pro Rata EBITDA Contribution to CNX

Adjusted EBITDA 29.6

Market Multiple 9.0x

Value 267$

Total Potential Value 750$ 1,100$

Value per CNX Share 3.27$ 4.80$

Note: 2018 valuation is based on preliminary estimates

$267

$456

$28

$750

2016E

Retained EBITDA LP Units IDRs

CONE Value to CNX 2016E

CONE Distributions Expected to Grow Meaningfully

(1) CAGR based on potential LP distribution growth cases

77

Net to CNX GP & IDR Distribution Cases

Net to CNX LP Distribution Cases

$0

$10

$20

$30

$40

$50

2015 2016 2017 2018 2019 2020 2021

$ in

mill

ion

s

10% CAGR 15% CAGR 20% CAGR

$0

$10

$20

$30

$40

$50

$60

2015 2016 2017 2018 2019 2020 2021

$ in

mill

ion

s

10% CAGR 15% CAGR 20% CAGR

2017E

Retained EBITDA LP Units Cash Distributions

CNXC: Value of CNX Passive Ownership in PA Operations

75% ownership of PA Mining Complex

16.6 million total LP units held by CNX(2)

CNX % LP Units' share 60.1%

CNX % GP Units' share 1.7%

CNX Total % Interest in

CNXC 61.8%

Base plan to drop remaining ownership over multiple years

CNXC Value Representation(1)

(1) Graph not indicative of actual CNXC valuation to CNX (2) LP units of various classes, on an as-converted basis (3) Unit price as of market close 12/1/2016

78

CNX Coal Resources LP value to CNX is comprised of four main drivers:

Retained EBITDA Cash Distributions Drop Downs Ownership of LP and GP/IDR

CNXC Value Streams to CNX(units and $ in millions, except per share data)

2017E Cash Distributions (LP&GP)

Common Units 9.7$

Subordinated Units 23.8$

GP Units 1.2$

Total 2017E Cash Distributions 34.7$

LP Units

Unit Price(3) 18.40$

Units Held 16.6

LP Unit Value 305.8$

CNXC EBITDA Contribution to CNX

2017E Retained EBITDA 400.0$

Total combined interest in PA Mining Ops: 90%

Conditions Improving for Complete Separation from CNXC

79

Path to Completing Separation from CNXC

Financial Conditions

Improving CNXC Performance

Capital Market Strength Reduction in financing costs

Growing revenue and margins

Growing CNX Free Cash Flow Greater sponsor flexibility

Base plan: Multi-Year Drops

- Forecast assumes 20% drop in 2018

Financial Outlook: NAV/Share Value Drivers Accelerating

We expect growth while generating free cash flow:

• Stringent focus on capital allocation to drive the highest NAV per share decisions

• Become a leader in capital allocation, when compared to the best global companies

• Invest when rates of return are meaningfully higher than the cost of capital

• Reduce capital intensity across the whole enterprise

We have improved transparency and predictability:

• Extending out public forecasts across all business units

• Providing the tools to build out the NAV of the company

- Asset development provides 22 years of core development with large upside – JV dissolution reset

- Fast delineation of our acreage position to capture large NAV optionality

Our plan forecasts strengthening financial metrics:

• Maintain strong liquidity above $1.5 billion

• Improving credit metrics and leverage ratio below 2.5x

• Provide flexibility to finish separating the E&P and coal businesses

• Use the approximately $1 billion of free cash flow through 2018 to reduce debt and equity

• Drive down E&P cost of capital to 8% by year-end 2018

80

REGULATORY UPDATE

81

Core Themes Driving the CONSOL Value Story

82

OPERATIONAL IMPROVEMENT

Increasing EURs

Decreasing Costs

Disciplined Capital Spending

UNIQUE ASSET BASE

Robust Stacked Pay Opportunities

Turning Non-Core Acreage to Core

Supplemental Value Streams

CAPITAL ALLOCATION

Growing Free Cash Flow

Improving Balance Sheet

Path to Share Repurchases

GROWING NAV/Share

Q&A

83

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