Company Presentation Q3 2016

Cautionary Language

2

This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities

Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of

coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production,

revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially

from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a

prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements are included in our

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

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

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

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

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

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

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

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

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

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

to the proposed termination of the joint venture with Noble, risks that the conditions to closing may not be satisfied and the transaction may not occur,

including our ability to obtain regulatory approvals on the proposed terms and schedule, disruption to our business, including customer and supplier

relationships resulting from this transaction, and the impact of the transaction on our future operating and financial results and liquidity and other factors,

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Coal-E&P Revenue Split, 2012

E&P Revenues

Coal Revenues

3

CONSOL Energy: Company Overview

December 5, 2013 – Transaction with Murray Energy Corp. in which we sold half of coal

assets and related assets

April 19, 2014 – CONSOL Energy 150th Anniversary

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 result in Westmoreland County

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

August 2, 2016 – Divested Miller Creek and Fola Complexes in Central Appalachia

September 30, 2016 – Dropped down an additional 5% interest in PA Mining

Complex to CNXC for total consideration of $88.8 million

October 31, 2016 – Announced agreement to separate Marcellus Shale joint venture with

Noble Energy

Coal-E&P Revenue Split, 2014

E&P Revenues

Coal Revenues

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

E&P Revenues

Coal Revenues

CONSOL Energy is now a pure-play E&P company

Journey Towards Becoming a Top Tier Appalachian E&P Company Complete

4

Marcellus Joint Venture (JV) Exchange Agreement 1. Exchange agreement of jointly owned Oil & Gas properties,

consisting of:

Developed properties with associated current production of

1,070 MMcfe/d, net to the JV. CNX and NBL to receive net

production of ~620 and ~450 MMcfe/d, respectively

Undeveloped properties, including 75 drilled but uncompleted

locations (DUCs), and ~669,000 Marcellus Shale acres, net to

the JV - CNX to receive 53 DUCs and ~306,000 net Marcellus Shale acres

- NBL to receive 22 DUCs and ~363,000 net Marcellus Shale acres

CONSOL will receive a disproportionately greater value in the

property exchange, with the difference equal to ~$275 million

2. Cash payment from NBL to CNX equal to ~$205 million

3. Cancellation of remaining drilling “carry” obligation due from NBL

to CNX equal to $1.6 billion; “carry” was only to be paid when

Henry Hub natural gas price was equal to or greater than $4/MMBtu

for 3 consecutive months, with an annual limit of $400 million

4. Anticipate closing in Q4 2016; effective as of October 1, 2016

Firm Transportation (FT) and Processing Commitments:

NBL and CNX have agreed to work with the pipelines to reallocate

firm transportation to better align with the upstream assets

The targeted reallocation between CNX and NBL attempts to be

value neutral to both parties, while optimizing firm capacity to post-

alignment production expectations

No material changes to previous financial FT and processing

commitments - No NGL sales commitments were impacted by the NBL transaction

Post-Exchange Acreage Map

The transaction is designed to deliver approximately $480 million of value to CNX

in exchange for the cancellation of the drilling “carry” obligation

5

Post-Exchange Agreement: Pro Forma Analysis

(1) The 2016E production increase is a result of 85 MMcfe/d of additional production associated with the exchange agreement, as well as continued productivity improvements.

(2) 7,000' laterals x 750' spacing.

Impact on Marcellus Shale Operations

CONSOL Energy Before

JV Exchange Agreement

After

JV Exchange Agreement

2016E Production(1) (Bcfe) 380-385 390-395

2016E Average per Unit Operating Expenses ($/Mcfe) $2.27 - $2.49 $2.27 - $2.49

Net Marcellus DUC Inventory (Wells) 37.5 53.0

Marcellus Joint Venture Assets

CONSOL Interest in

Total JV Assets

Before Exchange Agreement

JV Assets Held by CONSOL

After Exchange Agreement

Working Interest 50% 100%

Net Undeveloped Acres 335,000 306,000

Net Future Locations(2) 2,790 2,550

Net PDPs (Wells) 258 280

Net PDP Flowing Production (MMcfe/D) 535 620

6

Strategic Overview Agreement to Separate Marcellus Shale Joint Venture

Full autonomy to develop, operate, or divest assets

- Flexibility to operate these assets as we choose

- Facilitates stacked pay development opportunities

- Unlocks development of assets

- Increases ability to execute asset sales

- Increases production

Increases interest in the highest return acreage

- Increase proved undeveloped reserves (PUDs) in the core areas of the Marcellus Shale

- Retain high return acreage

Further strengthens the balance sheet

- Expected to increase EBITDA and free cash flow

- Reduces debt and leverage ratio

- Increases DUCs providing additional production opportunity with little additional required capital

- Improves liquidity

Top-tier Appalachian E&P company

- The Marcellus assets retained provide growth opportunities in best-in-class areas, with low cost potential

- Completes the transformation of CONSOL to a pure-play E&P

The exchange agreement provides CONSOL more control in capital allocation

decisions and creates greater opportunities to grow shareholder value

7

The exchange agreement provides CONSOL Energy the ability to drive NAV per share higher

through:

Greater flexibility in our capital allocation strategy and long-term development plan

- Optimize the development plan between the Marcellus and Utica horizons

- Should increase value in CONE Midstream Partners LP

Better control and flexibility to monetize E&P assets that were previously part of the JV

Pulls forward value for the JV “carry”

Quicker balance sheet de-levering and improves liquidity without issuing equity

Joint Venture Separation Drives Long-Term Value Growth

Key Takeaways of the Exchange Agreement

Completes the transformation of the company to a pure-play E&P

8

E&P Operations

9

Marcellus Shale Footprint Before and After the Joint Venture Exchange Agreement with Noble Energy

(1) 7,000' laterals x 750' spacing.

JV Marcellus Footprint:

Before-Exchange

CNX Marcellus Footprint:

Post-Exchange 9

WI (%) 50

Net

Undeveloped

Acres

335,000

Net Future

Locations(1)

(Count)

2,790

Net PDP (Wells) 258

PDP Flowing

Production

(MMcfe/D)

535

Marcellus Shale

Before Exchange Agreement

WI (%) 100

Net

Undeveloped

Acres

306,000

Net Future

Locations(1)

(Count)

2,550

Net PDP (Wells) 280

PDP Flowing

Production

(MMcfe/D)

620

Marcellus Shale

After Exchange Agreement

10

E&P Division: Q3 2016 Operations Summary

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length

(ft)

Counties

Southwest

PA ---- ---- 6 1 7,206

Greene,

Washington,

Allegheny, PA

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

Indiana,

Westmoreland,

PA

Northern

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

Barbour,

Doddridge,

Lewis, WV

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

North Wet

Gas ---- ---- ---- 6 10,571

Greene,

Washington,

PA; Marshall,

WV

South Wet

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

Doddridge,

Tyler, Ritchie,

WV

Total 0 0 6 7 10,090

Sub-

Regions

Horizontal

Rigs Drilled Completed

Turned

In Line

(TIL)

Avg. TIL

Lateral

Length (ft)

Counties

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

Surrounding

Core Wet ---- ---- ---- ---- ----

Harrison,

Belmont, OH

Dry Utica 2 2 ---- ---- ----

Monroe, OH;

Marshall, WV

Westmoreland,

Greene, PA

Total 2 2 ---- ---- ----

Marcellus Shale Quarterly Summary Utica Shale Quarterly Summary

E&P Operations

Drilling & Completions update

─ Dual Fuel: D&C set up for Monroe County Utica – realized

$122k in savings on GH58 completion

─ Drilling Capital Efficiencies: Reduced drilling capital by 70%

over 8 Monroe County Utica wells

─ Plugless Completions: Currently flowing back the second

plugless completion test on GH58 pad

Production update

─ Lifting Efficiencies: Lifting costs further declined to $0.234/mcfe

for 3Q16, which yielded an ~$1.05 million reduction from 2Q16

─ Utica Production Capital Efficiencies: Monroe County facility

design and installation costs reduced from ~$900k/well on the 1st

pad to ~$535k/well on the 2nd pad (~41% reduction)

─ Marcellus Production Optimization: Tubing installs, plunger lift

systems, and soap injection - Implementation yielded a total uplift

of ~11.2 mmcf/d and 16 bcpd with payback periods less than 120

days

─ Production Control Room Efficiency: Average downtime per

incident was reduced in our SWPA District by ~20% which

resulted in an increased production of ~2.1mmcf/d

─ Operational Efficiency: Electric Demand Response Audit –

completed the 1 hour test which generated ~$812k in annual

savings

11

2016 Activity Overview and 2017 Drilled and Uncompleted Opportunity Set

E&P Activity Summary – 2016 Plan

E&P Operations: Pro Forma DUC Inventory

Note: Plan as of 9/30/2016.

Implied inventory exiting 2016 anticipated to consist of 70 Marcellus and Utica

Shale wells, of which CONSOL will have 100% WI in 65 wells

Expected New

Wells Drilled in

H2 2016

Drilled

Uncompleted

Inventory

Drilled

Completed

Inventory

2016 TIL's

Remaining

Implied

2017

Inventory

2016

Completions

Remaining

Marcellus

SW PA Operated - 12 8 6 14 -

SW PA Non-Op - - - - - -

WV Operated - 41 - - 41 -

WV Non-Op - - - - - -

Total Marcellus - 53 8 6 55 -

Utica

SW PA Operated - - - - - -

OH Operated 9 1 - - 10 -

OH Non-Op - 5 - - 5 -

Total Utica 9 6 - - 15 -

Total Gross Marcellus/Utica

Wells 9 59 8 6 70 -

12

Efficiencies Driving Reduced E&P Capital Expenditures Without Sacrificing Growth

E&P Operations: Capital Expenditures

Deferring activity, increasing capital efficiency

improvements and identification of additional

de-bottlenecking activities

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

- Drilling and Completion: $140-$145 million

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

activity

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

$22 million associated with CONE Midstream capital

contributions)

- Other activities (land, permitting, and business

development): $17-$22 million

2016 E&P Capital Budget:

$190-$205 Million

Base case assumes drilling nine new wells in Monroe County, Ohio in H2 2016

D&C72%

Midstream18%

Other10%

$0.23 $0.38 $0.24 $0.16

$1.10$1.02

$1.04$0.93

$0.17 $0.17$0.09

$0.09

$0.84 $0.59

$0.37

$0.26

$1.17

$1.11

$0.82

$0.48

$3.51

$3.27

$2.56

$1.92

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

2013 2014 2015 2016E²

SG&A¹ Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE

13

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

E&P Operations: Benchmarking vs Peers

Cash OpEx

(plus SG&A) of

$1.28/Mcfe,

plus PUD-to-

PDP CapEx of

$0.48/Mcfe,

equals total full

cycle cash

costs of

$1.92/Mcfe

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

(1) SG&A does not include short-term or long-term incentive compensation

(2) 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.

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

and projecting an additional 25% reduction from 2015

14

E&P Operations: Drilling Improvements

Realized ~60+% Reduction in Days to Drill Expect Additional

~16% Reduction

Met previously stated goal of drilling a Monroe County Dry Utica well in 26 days

- Exceeded goal by three days on third well

Improvement of 76% over the first well drilled and a 38% improvement over last well drilled in

2015

New goal of 20 days to drill Monroe County Dry Utica wells

0.0

5,000.0

10,000.0

15,000.0

20,000.0

25,000.0

0.00 20.00 40.00 60.00 80.00 100.00 120.00

De

pth

(ft

.)

Days

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

SWITZ6B

SWITZ6D

SWITZ6F

SWITZ6H

SWITZ16J

SWITZ16D

SWITZ5J

SWITZ16B

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

Great improvements in drilling efficiency

$1,740 $1,810

$1,380 $1,340

$1,150 $1,060 $1,040 $1,040

$950

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

Switz 6B Switz 6D Switz 6H Switz 6F Switz 16J Switz 16D Q2 Switz 16D Act Switz 5J Switz 16B

Drilli

ng C

ost

($/late

ral ft

)

Switz Drilling Cost ($/lateral ft) (Wells in order of Tophole TD)

15

Utica Shale: Drilling Cost Improvements

Expected cost from Q2 Actual costs

Improvement of 26% in drilling costs over first 3 wells drilled and a 39% improvement over last

well drilled in 2015

Exceeded previous goal of $1,060/lateral ft drilling costs stated in Q2 2016

16

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.

Directly-marketed ethane volumes were

612,000 barrels in Q3 -- an increase of

132% from Q2 and, on an equivalent

basis, yielded a premium price over the

Texas Eastern M2 gas market.

─ An additional ethane contract with

favorable terms commenced October 1,

2016.

17

Gas Marketing Q3 2016 Gas Realization and Marketing Highlights

2016 2015

Q3 Q2 Q1 Q3

NYMEX Natural Gas ($/MMBtu) 2.81$ 1.95$ 2.09$ 2.77$

Average Differential (0.86) (0.46) (0.36) (1.00)

BTU Conversion (MMBtu/Mcf)* 0.11 0.09 0.10 0.09

Gain on Commodity Derivative

Instruments-Cash Settlements 0.47 0.91 0.98 0.60

Realized Gas Price per Mcf 2.53$ 2.49$ 2.81$ 2.46$

*Conversion Factor 1.06 1.06 1.06 1.05

Q3 2016 Natural Gas Price Reconciliation

Ethane volume growth and improving NGL pricing seen in Q3

continued into early Q4 2016

In addition to the upstream

deal, CNX and NBL have

agreed to work with the

pipelines to reallocate firm

transportation to better

align with the upstream

assets

The targeted reallocation

attempts to be value neutral

to both parties, while

optimizing firm capacity to

post-alignment production

expectations

Remains subject to FERC

and pipeline approvals

18

Gas Marketing Firm Transportation

FT reallocation retains low average cost and market exposure and improves

alignment of FT with current production and growth areas

$0.24 $0.25

$0.29 $0.30

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

2016 2017 2018 2019

Expected Avg. Demand per MMBtu:

2016E-2019E After Reallocation

Expected Firm Capacity by Pipeline After FT Reallocation

Charts also include transportation under precedent agreements

Pipeline YE 2016 YE 2018

ANR Pipeline 47 47

Columbia (TCO) 212 562

Dominion (DTI) 345 317

East Tennessee 282 202

Nexus - 115

TETCO 174 174

TETCO (via firm sales) 285 125

(1000s MMBtu/day) 1,345 1,542

Expected FT Capacities After Reallocation

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

19

Gas Marketing Natural Gas Sales: Expected Market Mix

Sales mix remains mostly unchanged after the transaction

MIDWEST TETCO M3

TETCO M2

EAST TENNESEE

TETCO ELA

TETCO WLA

TCO POOL

DOMINION SOUTH

Gas Sales 2016E 2017E

Columbia (TCO) 17% 17%

TETCO (M2) 29% 28%

TETCO (M3) 16% 15%

Dominion (DTI) 15% 15%

East Tennessee 10% 10%

TETCO ELA & WLA 8% 8%

Midwest (Chicago) 5% 7%

100% 100%

0

100

200

300

400

500

600

Jan 16 Jan 17 Jan 18 Jan 19

MM

cf/

da

y

MVC

CNX and NBL have also agreed to

work with processing

counterparties to realign processing

capacity with the upstream assets

After the swap of capacity, CNX’s

volume of firm processing capacity

and minimum volume commitment

will be roughly unchanged

CNX will retain the flexibility to

bypass processing with certain

“damp” gas to continue facilitating

optimization of that gas

No NGL sales commitments were

impacted by the NBL transaction

20

Gas Marketing Natural Gas Processing and NGLs

Note: CONSOL Energy had processing capacity expansion rights of 110,000 Mcf/d.

Processing capacity is to be transferred in line with the asset areas it supports;

minimal impact to parties based on current volumes but gives

CNX additional flexibility in the future

CNX Expected Contracted Processing Capacity

21

Ethane 64%

Propane 22%

I-Butane 3%

N-Butane 6%

Natural gasoline

5%

Maximum Ethane Recovery* Potential Scenario

* Assumes 85% ethane recovery level

Ethane 36%

Propane 37%

I-Butane 5%

N-Butane 11%

Natural gasoline

11%

3Q16 Est NGL Sales Comp

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

Q3 2016 Avg. “NGL Barrel” Composition Q3 2016 liquids sold: 13.6 Bcfe, up 29% from Q2 2016

Total weighted average price of all liquids decreased

1.6% to $15.48 per Bbl in Q3 2016 from $15.73 per Bbl in

Q2 2016. Excluding ethane, average sales price was up

8.8% from Q2.

Directly-marketed ethane volumes were 612,000 barrels

in Q3 -- an increase of 132% from Q2 and, on an

equivalent basis, yielded a premium price over the Texas

Eastern M2 gas market

Liquids comprised approximately 14% of Q3 2016

production volumes, 14% of E&P sales revenue and 5%

of total Company revenue

17.5 million gallons of propane hedged from April of 2016

through March of 2017 at an average price of $0.48 per

gallon

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

Average Price Realization (per Bbl)

2016 2015

Q3 Q2 Q1 Q3 Q2 Q1

NGLs 13.14$ 12.84$ 12.30$ 4.80$ 12.48$ 20.40$

Oil 42.06 33.72 30.84 54.18 46.14 47.82

Condensate 37.26 31.68 14.64 27.84 31.26 20.82

22

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

(2) At the midpoint of production guidance of 390-395 Bcfe.

(3) Hedge positions as of 10/13/2016. FY 2016 includes actual settlements of 225.3 Bcf.

Gas Hedges

Gas Marketing

E&P Hedge Program:

Program and actively

monitored hedges

─ Program Hedge - protect

margins on up to 90% of

our Proved Developed

Production

─ Active Hedge Process -

supplements program

hedges up to 80% of our

total production including

proved undeveloped

production

Since 6/30/16, added 64 Bcf

of NYMEX gas hedges and

172 Bcf of basis hedges

through 2020, further

protecting downside

Approximately 69% of total

FY 2016E production

volumes hedged2

CNX Gas Volumes Hedged 2016-2020

Hedge Volume and Pricing 2016-2020 Q4 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020

NYMEX + Basis¹

Volumes (Bcf) 61.8 264.5 207.5 151.6 75.2 40.5

Average Prices ($/Mcf) 3.16$ 3.03$ 2.61$ 2.64$ 2.53$ 2.77$

NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) 1.8 - 30.3 11.8 25.2 2.6

Average Prices ($/Mcf) 3.41$ -$ 3.02$ 3.10$ 3.04$ 3.18$

Physical Sales With Fixed Basis Exposed to NYMEX

Volumes (Bcf) - 7.3 - - - -

Average Hedged Basis Value ($/Mcf) -$ (0.06)$ -$ -$ -$ -$

Total Volumes Hedged (Bcf)3

63.6 271.8 237.8 163.4 100.4 43.1

0

50

100

150

200

250

300

Q4 2016 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020

Gas V

olu

me

s H

ed

ge

d (B

cf)

Physical Sales With Fixed Basis Exposed to NYMEX

NYMEX Only Hedges Exposed to Basis

NYMEX + Basis¹

23

Financial

24

Net earnings attributable to continuing operations(1) in the 2016 third quarter of $62.6 million, or $0.26 per

diluted share

Adjusted net loss attributable to continuing operations(1) in the 2016 third quarter of $35.5 million, or ($0.15)

per diluted share

- Excludes the following pre-tax items:

$159.6 million unrealized gain on commodity derivative instruments

$3.7 million loss related to pension settlement

$0.2 million in severance expense

Q3 2016 production of 96.4 Bcfe, up approximately 10.3 Bcfe from Q3 2015, a 12% increase

Production volumes expected to grow to approximately 390-395 Bcfe in 2016

(1) Q3 2016 net income includes a net loss of ($35) million from discontinued operations, net of tax.

Note: The terms "adjusted net loss attributable to continuing operations," "adjusted EBITDA," “adjusted EBITDA attributable to continuing operations,” "free cash flow," and "organic

free cash flow from continuing operations" are non-GAAP financial measures, which are defined and reconciled to GAAP net (loss)/income and net cash provided by continuing

operations below, under the caption “Non-GAAP Reconciliation."

Third Quarter 2016 Results

Financial: Q3 2016 Review

Q3 2016 Summary Y/Y Q-to-Q Seq. Q-to-Q

($ in millions, except per share data) 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change

Net Income (Loss) Attributable to CNX Shareholders $25 $119 ($94) $25 ($470) $495

Earnings (Loss) per Diluted Share $0.11 $0.52 ($0.41) $0.11 ($2.05) $2.16

Revenue and Other Income $746 $721 $25 $746 $286 $460

Net Cash Provided by Continuing Operations $166 $147 $19 $166 $82 $84

Adjusted EBITDA Attributable to Continuing

Operations $156 $146 $10 $156 $135 $21

(1) (1)

25

Generated positive free cash flow

- Organic free cash flow from continuing operations in Q3 2016 of $103 million; first nine months 2016 total organic

FCF of $188 million

- Total free cash flow in Q3 2016 of $92 million; first nine months 2016 total free cash flow of $608 million

Reduced outstanding borrowings on the revolving credit facility by approximately $112 million, which

increased liquidity and de-levered the balance sheet

- Used free cash flow generated during the quarter, plus cash on hand

Total capital expenditures in Q3 2016 of $64 million: First nine months 2016 total capital expenditures of

$179 million

Source: Company filings.

Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding.

Net (Decrease)/Increase in Cash

Financial: Q3 2016 Review (Cont’d)

Q3 2016 Cash Flow Summary (including Discontinued Operations) Y/Y Q-to-Q Seq. Q-to-Q

($ in millions) 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change

Net Cash Provided by Operating Activities $163 $110 $53 $163 $95 $68

Capital Expenditures ($64) ($248) $184 ($64) ($38) ($26)

Proceeds From Asset Sales $21 $76 ($55) $21 $10 $11

Other Investing ($27) ($38) $11 ($27) ($1) ($26)

(Payments on)/Proceeds From Short-Term Debt & Misc. Borrowings ($114) ($110) ($4) ($114) ($388) $274

Dividends Paid - ($2) $2 - - -

Other Financing 4 $285 ($281) $4 ($7) $11

Net (Decrease) / Increase in Cash ($17) $73 ($90) ($17) ($329) $312

26

E&P Division: Results Summary

Financial: Q3 2016 Review (Cont’d)

(1) Average Sales Prices for 3Q2016, 3Q2015 and 2Q2016 include gains on commodity derivative instruments (cash settlements) of $0.47, $0.60 and $0.91, respectively.

(2) Average Costs for 3Q2016, 3Q2015 and 2Q2016 include DD&A of $1.05, $1.05 and $1.04, respectively.

Adjusted earnings before income tax for E&P Division of $1.7 million(1)

Production increased by 12% in third quarter 2016, compared to year-earlier quarter

Marcellus Shale all-in unit costs were $2.33 per Mcfe in the third quarter, a decrease of $0.13 from $2.46 per Mcfe

in the year-earlier quarter, or a 5% improvement

Utica Shale all-in unit costs were $1.81 per Mcfe in the third quarter, a decrease of $0.29 from $2.10 per Mcfe in

the year-earlier quarter, or a 14% improvement

CBM all-in unit costs were $2.84 per Mcfe in the third quarter, an increase of $0.04 from $2.80 per Mcfe in the

year-earlier quarter, or a 1% increase

Other Gas all-in unit costs were $3.37 per Mcfe in the third quarter, a decrease of $0.02 from $3.39 per Mcfe in the

year-earlier quarter

(1) Adjusted earnings before income tax for the E&P Division of $1.6 million for the three months ended September 30, 2016 is calculated as GAAP earnings before income tax of

$161.1 million less total pre-tax adjustments of $159.5 million. The $159.5 million adjustment is the $159.6 million pre-tax gain related to the unrealized gain on commodity derivative

instruments and a pre-tax loss of $0.1 million related to severance expense.

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

E&P Division 3Q2016 3Q2015 Change 3Q2016 2Q2016 Change

Average Sales Price(1)

($ / Mcfe) $2.54 $2.35 $0.19 $2.54 $2.50 $0.04

Average Costs(2)

($ / Mcfe) $2.36 $2.54 ($0.18) $2.36 $2.27 $0.09

Sales Volumes (Bcfe) 96.4 86.1 10.3 96.4 99.3 (2.9)

Sales Volumes (Bcfe) by Category

Marcellus 51.8 45.9 5.9 51.8 53.1 (1.3)

Utica 22.5 15.3 7.2 22.5 23.3 (0.8)

CBM 17.0 18.5 (1.5) 17.0 17.1 (0.1)

Other 5.1 6.4 (1.3) 5.1 5.8 (0.7)

27

$2.0 billion Revolving Credit Facility:

5 year credit facility expires June 2019

Paid down approximately $600 million of revolving debt on the credit facility year-to-date

Gas reserves based lending facility: fall redetermination process expected to be completed in November

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

Strong Liquidity Position of ~$1.4 Billion

Financial: Liquidity

(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $80 million as of 9/30/2016, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per

US GAAP accounting.

(2) Revolving credit facility as of 9/30/2016.

Sept. 30,

Maintenance Covenants Limit 2016

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 4.0 to 1.0

Minimum Current Ratio < 1.0 to 1.0 2.7 to 1.0

Amount/ Amount Letters Amount

September 30, 2016 ($ in million) Capacity Drawn of Credit Available

Cash and Cash Equivalents(1) $74 - - $74

Revolving Credit Facility(2) $2,000 $354 $324 $1,322

Total $2,074 $354 $324 $1,396

Ample liquidity of $1.4 billion with business plans focused on positive free cash

flow generation and de-leveraging the balance sheet

28

Debt and Liquidity Profile

Financial: Liquidity (Cont’d)

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

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

(2) Total Debt of $3.151 billion excludes total unamortized debt issuance costs of $29 million.

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

(4) As of 9/30/2016, CNX had approximately $354 million of borrowings and $324 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,322 million of

availability. CNXC had $208 million outstanding on its revolving credit facility leaving approximately $192 million of availability.

(5) Number of MLP units owned by CNX as of 9/30/2016 and unit prices as of market close on 10/21/2016.

(6) CNX Coal Resources liquidity data is as of 9/30/2016 and CONE Midstream data is as of 6/30/2016.

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

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

$680 million less a loss on sale of assets of $6 million, plus gain related to changes in retiree medical

(OPEB) plan of $110 million, less the $50 million of CNXC EBITDA net of cash distributions attributable to

CNX, less $3 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 $3.151 billion, less $74 million cash on hand

excluding CNXC’s cash, less $208 million of CNXC revolver debt, less $3 million of advance mining

royalties, plus $240 million of net letters of credit related to firm transportation obligations, mining equipment

leases, and insurance policies.

Transaction further strengthens the balance sheet as leverage ratio falls

and liquidity rises $205 million to $1.6 billion

CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 9/30/2016 9/30/2016 9/30/2016

Capitalization

Cash and Cash Equivalents $80 $6 $74

Revolving Credit Facility Balance 562 208 354

Capital Lease Obligations 37 - 37

Total Secured Debt $599 $208 $391

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 5 - 5

Total Debt (2) $3,151 $208 $2,943

Net Debt (3) $3,071 $202 $2,869

Stockholders’ Equity $4,290 $143 $4,147

Total Capitalization $7,441 $351 $7,090

Liquidity

Cash and Cash Equivalents $80 $6 $74

Revolving Credit Facility Capacity (4) 1,514 192 1,322

Total Liquidity $1,594 $198 $1,396

Equity Value of Ownership in

Affiliated Public MLPs

CNX

Owned LP

Units(5)

Unit

Price(5)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 16.6 $17.50 $291

CONE Midstream Partners LP (CNNX:NYSE) 19.1 $20.80 $397

Total Equity Value of Ownership Interests in Affiliated Public MLPs $688

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity of

Affiliates

CNX Coal Resources LP (6)

$400 $208 $192 $6 $198

CONE Midstream Partners LP (6)

$250 $47 $203 $5 $208

Total Liquidity of Affiliated

Public MLPs $650 $255 $395 $11 $406

Leverage Ratio 9/30/2016

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7)

$731

LTM Bank Net Debt / Adj. EBITDA (7)

4.3x

$4,345

$1,902 $1,694

$1,542 $1,385 $1,374

$370

$148 $153 $137

$100 $100

$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 Q3 2016 FY 2016E

An

nu

al

Ca

sh

Se

rvic

ing

Co

sts

($

in

Millio

ns

)

Le

ga

cy L

iab

ilit

ies

($

in

millio

ns

)

Total Legacy Liabilities Total Annual Legacy Liabilities Cash Servicing Cost

As of Period End: 12/31/2012 12/31/2013 12/31/2014 12/31/2015 9/30/2016 12/31/2016E

Legacy Liabilities ($MM)

LTD $39 $20 $22 $20 $18 $17

WC 180 85 90 83 82 82

CWP 184 121 126 123 126 125

OPEB 3,018 1,022 761 672 655 655

Salary Retirement/Pension 225 53 119 94 92 89

Asset Retirement Obligations 699 601 576 550 412 406

Total Legacy Liabilities $4,345 $1,902 $1,694 $1,542 $1,385 $1,374

FY 2012 FY 2013 FY 2014 FY 2015 Q3 2016 FY 2016E

Total Annual Legacy Liabilities Cash Servicing Cost $370 $148 $153 $137 $100 $100

29

Significant Legacy Liability Reductions Over Past 3 Years

Financial: Legacy Liabilities

Flows through P&L in operating

costs (impact reflected in operating

cost guidance)

Flows through P&L within DD&A

Flows through Other Segment in

“Miscellaneous Operating Expense”

Projected $100MM Annual Cash

Servicing Cost for FY 2016, a

$37MM reduction from the year-

end 2015 run-rate of $137MM

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

since 2012, with further reductions expected going forward

30

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

In September 2016, CNXC acquired an additional 5%

undivided interest in the PA Mining Complex for total

consideration of $88.8 million ($21.5 million in cash

and preferred units valued at $67.3 million) implying

total complex value of $1.8 billion

CONSOL Energy retains a 75% 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 25% 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.

75% undivided

ownership interest

CNX Coal Resources LP

NYSE: CNXC

CNX Coal Resources GP

LLC

Pennsylvania

Mining Complex

100% ownership

interest

60% limited

partner

interest

2% general partner

interest and IDRs

25% undivided

ownership interest and

management and control

rights

limited partner

interest

CONSOL Energy Inc.

("CONSOL Energy")

NYSE: CNX

Public

Greenlight

Capital

CNXC is a vehicle to separate the businesses

(in millions except for per unit amounts)

Total LP Units held by CONSOL Energy 16.6

Unit Price (as of close on 10.21.2016) $17.50

CNXC Units Equity Value to CONSOL Energy $290.8

CONSOL Energy's Ownership Interest in CNX Coal

Resources LP (CNXC:NYSE)

CONSOL owns 32.1% of CONE Midstream Partners LP’s

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

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

CNNX owns interests in 3 development companies

The remaining un-dropped portion of the development

companies’ interests are held by CONE Gathering LLC

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

Energy (NYSE: CNX) and Noble Energy (NYSE: NBL)

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

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

Affiliates,” which in CNX’s consolidated financial statements

falls within the “Miscellaneous Other Income” line item

Distributions run straight through CNX’s cash flow statement in

the “Return on Equity Investment” line item

CNX has seen increasing benefit from CONE’s EBITDA and

cash distributions, on top of which CNNX recently increased its

cash distribution 3.7% from 2Q16

31

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.

CNNX: CNX Ownership and Cash Contribution

$10 $15

$29

$44

$57

$0

$10

$20

$30

$40

$50

$60

FY 2012 FY 2013 FY 2014 FY 2015 3Q16Annualized

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 NetIncome

$10$15

$34

$50

$62

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

FY 2012 FY 2013 FY 2014 FY 2015 3Q16Annualized

CONE Midstream's and Gathering's Pro Rata EBITDA Contribution to CNX

CNX Pro Rata Share of CONE Midstream Partners LP's CashDistributionsCNX Total Pro Rata Share of CNNX and CONE Gathering, LLC'sEBITDA

$68

$82

$18

$20

(in millions except for per unit amounts)

Total LP Units held by CONSOL Energy 19.1

Unit Price (as of close on 10.21.2016) $20.80

CNNX Units Equity Value to CONSOL Energy $397.3

CONSOL Energy's Ownership Interest in CONE

Midstream Partners LP (CNNX:NYSE)

($ in millions)

($ in millions)

32

Guidance

Note: Guidance as of 11/1/2016.

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

E&P Segment Guidance 2016E

Production Volumes:

Natural Gas (Bcf) 346 - 349

NGLs (MBbls) 6,500 - 6,750

Oil (MBbls) 62 - 68

Condensate (MBbls) 800 - 850

Total Production (Bcfe) 390 - 395

Natural Gas Basis Differential to NYMEX ($Mcf) ($0.65) - ($0.75)

NGL Realized Prices ($Bbl) $13.00 - $15.00

Condensate Realized Prices % of WTI 65% - 70%

Oil Realized Prices % of WTI 85% - 90%

Capital Expenditures ($ in millions):

Drilling and Completion $160 - $165

Midstream $25 - $30

Land and Other $5 - $10

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

Average per unit operating expenses ($/Mcfe):

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

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

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

Depreciation, Depletion and Amortization $1.04 - $1.07

Total Production and Gathering Cost $2.27 - $2.40

Other Expenses ($ in millions):

Selling, General and Administrative Costs $58 - $62

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

33

Guidance

Note: Guidance as of 11/1/2016. CONSOL Energy is unable to provide a reconciliation of projected CNXC Adjusted EBITDA, CONSOL's Other Coal Division EBITDA, and

CONSOL's Other Miscellaneous Coal 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.

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

Loss on Sale for the Miller Creek and Fola mines.

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

and other miscellaneous land income.

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

and pension settlement charges.

Coal Segment Guidance 2016E

Estimated Total PA Mining Operations Sales Volumes (in millions of tons) 23.6 - 24.4

Sales Volumes Attributed to Discontinued Operations (in millions of tons) 2.1

% PA Mining Operations Tonnage Sold 100%

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

Production $60 - $76

Other (Land/Water/Safety/Terminal) $15 - $24

Total Coal Capital Expenditures $75 - $100

Adjusted EBITDA Guidance

CNXC EBITDA $74 - $82

4x

100% PA Mining Operations Operating EBITDA $296 - $328

Less: Noncontrolling Interest ($26) - ($30)

Plus: Other Coal Operating EBITDA(1)

$15 - $16

Plus: Other Coal Misc. EBITDA(2)

$24 - $30

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

($104) - ($109)

CNX Pro Rata Coal and Other Segment Adjusted EBITDA $205 - $235

34

Milestones:

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

cycle times, and service cost deflation

Adding two rigs while maintaining discipline on capital expenditures

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

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

the 5th consecutive increase since July 2015

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

stacked pay opportunities

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

Marcellus Shale joint venture separation provides more control and flexibility for future development

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

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

Plans and Goals Aligned to Drive Increased Valuation

Key Takeaways

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

within our core values of safety, compliance, and continuous improvement

35

Appendix

36

Non-GAAP Reconciliation: EBITDA and Adj. EBITDA

Appendix

Source: Company filings.

Note: Income tax effect of Total Pre-tax Adjustments was ($57,599) and ($54,680) for the three months ended September 30, 2016 and September 30, 2015, respectively. Adjusted

net income attributable to CONSOL Energy shareholders for the three months ended September 30, 2016 is calculated as GAAP net income from continuing operations of $62,568

less total pre-tax adjustments of $155,675, plus the tax expense of $57,599, equals the adjusted net loss from continuing operations of $35,508.

(1) CONSOL Energy's Other Division includes expenses from various other corporate and diversified business unit activities including legacy liabilities costs and income tax expense

that are not allocated to E&P or PA Mining Operations Divisions.

Three Months Ended Twelve Months Ended

September 30,

2016 2016 2016 2016 2015

($ in thousands)E&P

Division

PA Mining

Operations

Division

Other1 Total

Company

Total

Company

Net Income/(Loss) $161,075 $34,741 ($168,223) $27,593 $125,470

Less: Loss from Discontinued Operations - - 34,975 34,975 3,842

Add: Interest Expense 669 2,309 44,339 47,317 48,558

Less: Interest Income - - (214) (214) (361)

Add: Income Taxes Benefit - - 52,858 52,858 65,868

Earnings/(Loss) Before Interest & Taxes (EBIT) from Continuing Operations 161,744 37,050 (36,265) 162,529 243,377

Add: Depreciation, Depletion & Amortization 101,257 42,370 8,085 151,712 146,844

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

Continuing Operations $263,001 $79,420 ($28,180) $314,241 $390,221

Adjustments:

Unrealized Gain on Commodity Derivative Instruments (159,555) - - (159,555) (99,138)

Severance Expense 129 14 86 229 7,683

Pension Settlement - - 3,651 3,651 3,132

Gain on Sale of Western Allegheny - - - - (48,468)

OPEB Plan Changes - - - - (100,947)

Total Pre-tax Adjustments ($159,426) $14 $3,737 ($155,675) ($237,738)

Adjusted EBITDA $103,575 $79,434 ($24,443) $158,566 $152,483

Less: Noncontrolling Interest - (2,248) - (2,248) (6,490)

Adjusted EBITDA Attributable to Continuing Operations $103,575 $77,186 ($24,443) $156,318 $145,993

37

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

Appendix

Source: Company filings.

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

December 31, March 31, June 30, September 30, September 30,

($ in thousands) 2015 2016 2016 2016 2016

Net Income / (Loss) $34,326 ($96,458) ($468,649) $27,593 ($503,188)

Less: Income from Discontinued Operations 11,017 53,167 234,605 34,975 333,764

Add: Interest Expense 49,081 49,865 47,427 47,317 193,690

Less: Interest Income (431) (214) (547) (214) (1,406)

Add: Income Taxes 125,742 (23,800) (100,856) 52,858 53,944

Earnings Before Interest & Taxes (EBIT) from Continuing Operations 219,735 (17,440) (288,020) 162,529 76,804

Add: Depreciation, Depletion & Amortization 139,988 154,988 135,220 151,712 581,908

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

Continuing Operations $359,723 $137,548 ($152,800) $314,241 $658,712

Adjustments:

OPEB Plan Changes (109,879) - - - (109,879)

Unrealized (Gain)/Loss on Commodity Derivative Instruments (62,388) 29,271 279,715 (159,555) 87,043

Pension Settlement 15,921 - 13,696 3,651 33,268

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

Gain on Sale of Non-core Assets (7,551) 13,735 - - 6,184

Severance Expense - 2,918 1,451 229 4,598

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

Total Pre-tax Adjustments ($157,639) $45,924 $288,574 ($155,675) $21,184

Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA) $202,084 $183,472 $135,774 $158,566 $679,896

Less: Noncontrolling Interest ($3,920) ($1,114) ($1,179) ($2,248) ($8,461)

Adjusted EBITDA Attributable to Continuing Operations $198,164 $182,358 $134,595 $156,318 $671,435

38

Free Cash Flow Reconciliation

Appendix

Source: Company filings.

Three Months Ended Nine Months Ended

September 30, September 30,

($ in thousands) 2016 2016

Net Cash provided by Continuing Operations 166,064$ 372,211$

Capital Expenditures (64,132) (179,389)

Net Investment in Equity Affiliates 1,023 (4,555)

Organic Free Cash Flow From Continuing Operations 102,955$ 188,267$

Net Cash Provided By Operating Activities 162,897$ 386,638$

Capital Expenditures (64,132) (179,389)

Capital Expenditures of Discontinued Operations 11 (8,284)

Net Investment in Equity Affiliates 1,023 (4,555)

Proceeds From Sales of Assets 20,693 38,977

Payments on Sale of Miller Creek and Fola Complexes (28,271) (28,271)

Proceeds From Sales of Buchanan Mine - 402,806

Total Free Cash Flow 92,221$ 607,922$