EARNINGS RESULTS - CNX Resources...

EARNINGS RESULTS

FIRST QUARTER 2017

Cautionary Language

2

This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we expect to receive for our natural gas, 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 participation in joint ventures may restrict our operational and corporate flexibility, and actions taken by a joint venture partner may impact our financial position and operational results; we may not be able to sell non-core assets on acceptable terms; acquisitions and 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 coal sales contracts may provide limited protection and may result in economic penalties to us or permit the customer to terminate the contract; the majority of our common units in CNX Coal Resources LP are subordinated, and we may not receive related distributions; there is no assurance that the potential dropdowns, spin-off or sale of the coal business will occur, or if it does occur that we will be able to negotiate favorable terms; 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, 2016 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.

Q1 2017 Highlights

Free Cash Flow Continue to expect annual production growth and free cash flow generation

Production Raising 2017 and 2018 production guidance based on improved cycle times and optimized type curves

EBITDA Raising 2017 EBITDA guidance by 7%

Debt Repurchased approximately $100 million of debt in Q1 2017; have paid down ~$1.3 billion since 2015 when total debt peaked at ~$3.7 billion

Leverage Ratio Expect to reach our target leverage ratios quicker than our 4Q16 forecast

3

Operations: E&P Results Summary

4

(3) Adjusted earnings before income tax for the E&P Division of $19.9 million for the three months ended March 31, 2017 is calculated as GAAP loss before income tax of $93.5 million plus total pre-tax adjustments of $113.4 million. The $113.4 million adjustment is a $24.6 million pre-tax gain related to the unrealized gain on commodity derivative instruments, a pre-tax loss of $137.9 million related to the impairment of exploration and production assets and a pre-tax loss of $0.1 million related to severance expense.

• Adjusted earnings before income tax for E&P Division of $19.9 million(3)

• Marcellus Shale total production costs were $2.18 per Mcfe in the first quarter, a decrease of $0.27 from $2.45 per Mcfe in the year-earlier quarter, or an 11% improvement

- Driven primarily by reductions to lease operating expense and DD&A rates

• Utica Shale total production costs were $2.16 per Mcfe in the first quarter, an increase of $0.37 from $1.79 per Mcfe in the year-earlier quarter, or a 21% impairment

- Driven by an increase in firm transportation and processing costs, property taxes, and DD&A rates

(1) Average Sales Prices for 1Q2017, 1Q2016, and 4Q2016 include gains/(loss) on commodity derivative instruments (cash settlements) of ($0.55), $0.98, and $0.46, respectively. (2) Average Costs for 1Q2017, 1Q2016, and 4Q2016 include DD&A of $1.01, $1.08, and $1.05, respectively.

1Q 2017(1)1Q 2016

Y/Y

Change 1Q 2017(1)4Q 2016

Q/Q

Change

Average Sales Price(1) ($/Mcfe) $2.85 $2.73 $0.12 $2.85 $2.77 $0.08

Total Production Costs(2)

($/Mcfe) $2.32 $2.41 ($0.09) $2.32 $2.27 $0.05

Sales Volumes (Bcfe) 95.0 97.5 (2.5) 95.0 101.3 (6.3)

Sales Volumes (Bcfe) by Category

Marcellus 58.0 51.2 6.8 58.0 56.5 1.5

Utica 15.3 22.9 (7.6) 15.3 22.2 (6.9)

CBM 16.7 17.6 (0.9) 16.7 17.4 (0.7)

Other 5.0 5.8 (0.8) 5.0 5.2 (0.2)

Operations: Operations Summary

5

Production Efficiency Highlights

• OPEX Efficiencies: Reduced Q1 2017 LOE by $6.1 million, improving unit costs by $0.05/Mcfe Y/Y

• Production Surveillance: Improved production surveillance yielded a 72% Y/Y reduction in lost volume due to downtime, driving production improvements of ~1.2 Bcfe and incremental revenue of $3.8 million

• Production Facilities: Additional focus on production facilities optimization resulted in a ~3% reduction in CAPEX and a five-day reduction in installation cycle time

SWPA SWPA WV OH

Marcellus Upper Devonian Marcellus Dry Utica TOTAL

Horizontal Rigs 1 - - 1 2

Drilled 2 - - 7 9

Completed 5 - 2 4 11

Turned In Line (TIL) 5 1 - - 6

Avg. TIL Lateral Length (ft) 9,417 10,663 - - 9,625

Q1 2017 Summary

TD TIL TD TIL

Marcellus 8 31 33-41 15-20

Utica 17 26 26-31 21-25

Upper Devonian - 3 - -

CBM 63 63 20-25 25-30

TOTAL ex. CBM 25 60 59-72 36-45

2017 2018

Two-Year TIL Schedule

• Total E&P and Midstream CapEx guidance remains unchanged:

- 2017E: $555 million

- 2018E: $600 million

Operations: Drilling Cycle Time Efficiencies

6

Utica

• Q1 2017 drilling days/1,000’ lateral length improved 23% compared to 2016 helping to reduce cost per lateral foot by 11%

• The increase in efficiency and reduction in non-productive time was driven by:

- New incentives for on-site drilling consultants

- Drilling motor and bit optimization - More efficient casing designs - Enhanced solids control

Marcellus

• Drilled two laterals using existing top holes with an average lateral length of 9,141 ft in SWPA in 5.85 days each

• Achieved an Appalachian Marcellus drilling record of 7,380’ drilled in a 24 hour period

Monroe County Drilling Cost Savings

1.3

1.0

$392

$347

$250

$270

$290

$310

$330

$350

$370

$390

$410

$430

$450

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

FY2016 1Q2017

$/L

ater

al F

oo

t

Day

s/1

00

0’ L

L D

rille

d

Days/1000' LL Monroe $/Lateral Foot

Operations: Completions Cycle Time Efficiencies

7

Marcellus

Efficiency • Q1 2017 lateral feet/day stimulated increased

56% compared to 2016

• Faster total completion activities: 27% improvement in Q1 2017 compared to 2016

- 1.9 days/1000’ vs 2.6 days/1000’

• The increased efficiency and reduced cycle times were driven by:

- Higher volume water and sand logistics - Improved vendor selection based on

KPIs rather than lowest cost - Preventive maintenance technology

Cost • The ACAA1 pad was recently completed for a

cost of $348/lateral foot, which was flat with 2016 as operational efficiencies offset increased vendor costs

Marcellus Frac Efficiency

800

1,245

0

200

400

600

800

1,000

1,200

1,400

1Q16 1Q17

Feet

per

Day

Lateral Feet/Day - Stimulated

Operations: Revised Type Curves

8

Monroe County, OH – Dry Utica

• Better-than-expected reservoir performance driving accelerated production forecast, but EUR unchanged

• Accelerated production driven by: - Optimized inter-lateral

spacing - Optimized stage length and

proppant type, size, and loading

Morris Field, SWPA – Marcellus

• Shape of type curve changed due to accelerated production, but EUR remains the same

• Production protocol used to enhance flowback and early time production

• Accelerated production driven by: - Optimized stage length,

diversion techniques, and proppant loading

Revised Type Curve Shape vs. Prior Plan

Revised Type Curve Shape vs. Prior Plan

• Two wells are currently being drilled as an offset to the Gaut

Operations: Gaut 4IH Update – as of Q1 2017 End

9

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 5/15/17

Cas

ing

Pre

ssu

re (

psi

)

Flo

w R

ate

(Mcf

/d)

Flow Rate MCf/Day Casing Pressure

Hit line pressure: 2/6/2017 Tubing installed: 2/22/2017

Testing period

Gaut 4IH IP: 61.4 MMcf/d Initial SICP: 9,921 psig Lateral Length: 5,808’ EUR: 3.5 Bcf/1,000’ lateral Cum. Production as of 3/31/2017: 8.4 Bcf

Initial SICP: 9,921 psig EUR: 3.5 Bcf/1,000’ lateral

Marketing: Q1 2017 E&P Marketing Highlights

10

• Executed two long-term physical sales with customers on East Tennessee

- Allows CONSOL to forego 80,000 Dth/day of FT renewals

• Permanently released 52,500 Dth/d of unutilized TCO firm transportation capacity

• Directly-marketed ethane volumes were 367,000 barrels in Q1 and, on an equivalent basis, yielded a $1.15 per MMBtu premium over CONSOL’s residue natural gas alternative

- Directly-marketed ethane gross realization is up 30% from Q4 2016

• $0.22/Mcfe uplift from liquids, including the impact of hedging

Natural Gas Price Reconciliation

2017 2016

Q1 Q1

NYMEX Natural Gas ($/MMBtu) $3.32 $2.09

Average Differential (0.30) (0.36)

BTU Conversion (MMBtu/Mcf)* 0.16 0.10

(Loss)/Gain on Commodity Instruments-Cash Settlement (0.55) 0.98

Realized Gas Price per Mcf $2.63 $2.81

* Conversion Factor 1.05 1.06

Marketing: Gas Hedges

11

(1) Hedge positions as of 4/18/2017. 2017 includes actual settlements of 97.8 Bcf. 2021 excludes 2.6 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX, index and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total production guidance of 420-440 Bcfe in 2017E.

• Approximately 73% of total 2017E production volumes hedged(3)

• NYMEX hedges added during Q1: 147 Bcf (2018-2021)

• Basis hedges added during Q1: 254 Bcf (2017-2021)

Hedge Volumes and Pricing Q2 2017 2017 2018 2019 2020 2021

NYMEX Only Hedges

Volumes (Bcf) 68.0 279.9 276.4 194.9 117.2 17.2

Average Prices ($/Mcf) $3.18 $3.17 $3.17 $3.07 $3.11 $3.03

Index Hedges and Contracts

Volumes (Bcf) 8.1 32.5 6.8 12.8 7.7 7.8


Total Volumes Hedged (Bcf)(1) 76.1 312.4 283.2 207.7 124.9 25.0

NYMEX + Basis (fully-covered volumes)(2)

Volumes (Bcf) 71.1 307.2 253.8 170.0 109.8 25.0


NYMEX Only Hedges Exposed to Basis

Volumes (Bcf) 5.0 5.2 29.4 37.7 15.1 -

Average Prices ($/Mcf) $3.18 $3.17 $3.17 $3.07 $3.11 -

Total Volumes Hedged (Bcf)(1) 76.1 312.4 283.2 207.7 124.9 25.0

Gas Hedges 2017-2021

307.2

253.8

170.0

109.8

25.0

5.2

29.4

37.7

15.1

-

50.0

100.0

150.0

200.0

250.0

300.0

350.0

2017 2018 2019 2020 2021

Gas

Vo

lum

es H

edge

d (

Bcf

)

NYMEX + Basis (2) NYMEX Only Hedges Exposed to Basis

Marketing: Gas Hedges – Continued

12

(1) Hedge positions as of 4/18/2017.

Physical Fixed Basis and Fixed Price Sales(1) Q2 2017 2017 2018 2019 2020 2021

Physical Fixed Basis Sales

Volumes (Bcf) 13.1 58.7 88.5 69.8 41.0 9.5

Average Basis Prices ($/Mcf) ($0.11) $0.01 $0.15 $0.10 $0.06 $(0.28)

Physical Fixed Price Sales

Volumes (Bcf) 0.9 3.4 6.8 12.8 7.7 7.8

Average Prices ($/Mcf):

NYMEX portion $3.70 $3.68 $3.22 $3.09 $3.06 $3.01

Basis portion $(1.13) $(1.13) $(0.61) $(0.58) $(0.60) $(0.60)

$2.57 $2.55 $2.61 $2.51 $2.46 $2.41

2017 2018

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

• Physical fixed basis sales provide opportunities to lock in revenue in illiquid markets

• Systematic hedging of both NYMEX and basis fully covers the majority of 2017 and 2018 expected production

Marketing: Natural Gas Sales Market Mix

13

MIDWEST TETCO M3

TETCO M2

EAST TENNESEE

TETCO ELA

TETCO WLA

TCO POOL

DOMINION SOUTH

Natural Gas Sales Market Mix 2017E 2018E

Columbia (TCO) 11% 9%

TETCO (M2) 42% 44%

TETCO (M3) 11% 8%

Dominion (DTI) 12% 11%

East Tennessee 12% 14%

TETCO ELA & WLA 8% 6%

Midwest (Michcon) 4% 8%

100% 100%

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

Q1 2017

Eth

ane

$/g

al

Mt. Belvieu Ethane CNX Netback Appalachian Gas Alternative

Q1 2017 Direct Ethane Sales Comparison

Marketing: Liquids Realizations

14

Natural Gas Liquids, Oil, and Condensate

• Q1 2017 liquids sold: 8.9 Bcfe

• Total weighted average price of all liquids increased 39% to $29.72 per Bbl in Q1 2017, from $21.34 per Bbl in Q4 2016(1) (+133% Y/Y)

• Liquids comprised approximately 9% of Q1 2017 production volumes, 16% of E&P revenue, and 6% of total company revenue(1)

Average Price Realization ($ per Bbl)(1)

Gas $ High

Gas $ Low

NGL $ Low NGL $ High

Avoid Processing

Optimize Send to Processing

Optimize

22 Bcf

Wet Gas Flexibility

(1) Excludes propane hedging impact. (2) Net of basis and de-ethanization fees.

2017 2016

Q1 Q1

NGLs $29.16 $12.30

Oil 44.40 30.84

Condensate 33.84 14.64

(2)

Marketing: Market Currently Undersupplied

15

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Po

pu

lati

on

Wei

ghte

d H

DD

s (t

ho

usa

nd

s)

Week

Cumulative Nationwide Population Weighted Heating Degree Days

10-11

11-12

12-13

13-14

14-15

15-16

16-17

Avg

-3000.00

-2500.00

-2000.00

-1500.00

-1000.00

-500.00

0.00

500.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20C

um

ula

tive

Wit

hd

raw

al (

Bcf

)

Week

Cumulative Lower 48 Storage Withdrawal

10-11

11-12

12-13

13-14

14-15

15-16

16-17

AvgYet, storage

withdrawals near average levels

• Despite a warmer-than-average winter, storage withdrawals have been trending along the five-year average - This implies that the market is currently undersupplied

One of the lowest levels of heating demand recently

observed

Source: NOAA National Weather Service – Climate Prediction Center Source: EIA

Nov.-Mar. Nov.-Mar.

Marketing: Pipeline Projects will Make a Difference

16

02468

101214161820

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Reg

ion

al E

xpo

rt C

apac

ity

(Bcf

/d)

Year End

Regional Export by Delivery Market

Southwest

Midwest

Southeast

Canada

ACP Atlantic Sunrise Atlantic Sunrise

MVP NEXUS

NEXUS Rover

Rover

0

5

10

15

20

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Reg

ion

al E

xpo

rt C

apac

ity

(Bcf

/d)

Year End

Regional Export by Project

Forecast

Forecast

• The first wave of pipeline projects is expected to start coming online this year and will materially improve export capacity away from Appalachia

Source: EIA

Source: EIA

New Pipeline Projects Changing the Landscape

Marketing: But When Will Supply Respond?

17

0

1

2

3

4

5

6

7

8

9

-

100

200

300

400

500

600

Pro

du

ctio

n (

Bcf

/d)

Rig

Co

un

t

Permian Region Production and Rig Count

Rig count Total production

0

2

4

6

8

10

12

14

16

18

20

-

20

40

60

80

100

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160

Pro

du

ctio

n (

Bcf

/d)

Rig

Co

un

t

Marcellus Region Production and Rig Count

Rig count Actuals Prediction

• Even after the completion of several pipeline projects, it appears there are too few rigs running today to fill the additional capacity and balance the market

Source: EIA Source: EIA, CNX analysis

Historically, it appears 300+ rigs were required to grow

Permian gas production

We’ve not yet seen this dip in rig numbers manifest itself in

slowed production growth

Despite recent efficiency gains, Marcellus production will not be ready to fill the new pipelines due to the

recent low rig counts

Finance: Q1 2017 Results

18

• Adjusted net income attributable to CONSOL Energy Shareholders in the 2017 first quarter of $38 million, or $0.17 per diluted share(1); on a GAAP basis, a net loss attributable to CONSOL Energy shareholders of $39 million or ($0.17) per diluted share

- Adjusted net income excludes the following pre-tax items: $138 million impairment on Knox Energy and Coalfield Pipeline, which was recorded as Held

for Sale $25 million unrealized gain on commodity derivative instruments $5 million in various other nonrecurring items

• Total company adjusted EBITDA attributable to continuing operations in the first quarter of $217 million

(1) Income tax effect of Total Pre-tax Adjustments was $40,884 and $10,310 for the three months ended March 31, 2017 and March 31, 2016, respectively. Adjusted net income attributable to CONSOL Energy Shareholders for the three months ended March 31, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $38,966 plus total pre-tax adjustments from the table on slide 36 of $117,949, less the associated tax expense of $40,884 equals the adjusted net income attributable to CONSOL Energy Shareholders of $38,099.

Note: The terms "adjusted net income attributable to CONSOL Energy Shareholders," "EBITDA from continuing operations," and "adjusted EBITDA from continuing operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation."

Q1 2017 Summary

($ in millions, except per share data) 1Q 2017 1Q 2016

Y/Y

Change 1Q 2017 4Q 2016

Q/Q

Change

Net (Loss) Income Attributable to CNX Shareholders ($39) ($98) $59 ($39) ($306) $267

(Loss) Earnings per Diluted Share ($0.17) ($0.43) $0.26 ($0.17) ($1.33) $1.16

Revenue and Other Income from Continuing Operations $699 $533 $166 $699 $462 $237

Net Cash Provided by Continuing Operating Activities $205 $124 $81 $205 $87 $118Adjusted EBITDA Attributable to Continuing Operations $217 $181 $36 $217 $205 $12

Finance: Q1 2017 Review

19

Source: Company filings. Note: Numbers may not sum and may differ slightly from totals and financial statements due to rounding. The terms "adjusted net income attributable to CONSOL Energy Shareholders," "EBITDA from continuing operations," and "adjusted EBITDA from continuing operations" are non-GAAP financial measures, which are defined and reconciled to the GAAP net income below, under the caption “Non-GAAP Reconciliation."

Net Increase/(Decrease) in Cash

• Generated positive free cash flow

- Organic free cash flow from continuing operations in Q1 2017 of $98 million compared to $40 million in Q1 2016

- Total free cash flow in Q1 2017 of $117 million compared to $451 million in Q1 2016 (Buchanan sale) - Purchased approximately $100 million of long-term debt at a discount

Used free cash flow generated during the quarter, plus cash on hand Have paid down ~$1.3 billion since 2015 when total debt peaked at ~$3.7 billion

• Total capital expenditures in Q1 2017 of $113 million compared to $78 million in Q1 2016

Q1 2017 Cash Flow Summary (including Discontinued Operations)

($ in millions) 1Q 2017 1Q 2016

Y/Y

Change 1Q 2017 4Q 2016

Q/Q

Change

Net Cash Provided by Operating Activities $205 $130 $75 $205 $83 $122

Capital Expenditures ($113) ($78) ($35) ($113) ($47) ($66)

Proceeds from Asset Sales $19 $404 ($385) $19 $21 (2)

Other Investing $6 ($6) $12 $6 $79 ($73)

Proceeds from Noble Exchange Agreement - - - - $213 ($213)

(Payments on) / Proceeds from Short-Term Debt & Misc. Borrowings ($3) ($103) $100 ($3) ($356) $353

(Payments on) / Proceeds from Long-Term Notes ($98) - ($98) ($98) - (98)

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

Other Financing ($15) $9 ($24) ($15) ($13) ($2)

Net (Decrease) / Increase in Cash $1 $354 ($353) $1 ($20) $21

Finance: Strong Liquidity Position of ~$1.7 Billion

20

$2.0 billion Revolving Credit Facility

• 5 year credit facility expires June 2019

• Paid down nearly $1 billion of revolving debt on the credit facility in 2016

• Gas reserves based lending facility borrowing base reaffirmed at $2 billion in Q4 2016

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

(1) Cash and cash equivalents on CNX’s consolidated balance sheet was $61 million as of 3/31/2017, $6 million of which was CNXC’s and consolidated in CNX’s financial statements per US GAAP accounting.

(2) Revolving credit facility as of 3/31/2017.

March 31, 2017 ($ in millions)Amount/

Capacity

Amount

Drawn

Letters

of Credit

Amount

Available

Cash and Cash Equivalents (1) $55 - - $55

Revolving Credit Facility(2) $2,000 $0 $333 $1,667

Total $2,055 $0 $333 $1,722

Maintenance Covenants LimitMar. 31,

2017

CONSOL Energy Revolver:

Minimum Interest Coverage Ratio < 2.5 to 1.0 3.9 to 1.0

Minimum Current Ratio < 1.0 to 1.0 2.4 to 1.0

Finance: Debt and Liquidity Profile

21

Note: Some numbers may not match exactly to financial statements due to rounding. (1) The 2022 and 2023 senior notes includes $4 million and $5 million of

unamortized bond premium / discount, which will be amortized over the life of the notes, respectively.

(5) Number of MLP units owned by CNX as of 3/31/2017 and unit prices as of market close on 4/21/2017. (6) CNX Coal Resources liquidity data is as of 3/31/2017 and CONE Midstream data is as of 12/31/2016. (7) Adjusted EBITDA Attributable to CNX Shareholders is a non-GAAP financial measure and the reconciliation is provided in the Appendix. Bank methodology LTM EBITDA equals LTM Adjusted EBITDA of $727 million less the $57 million of CNXC EBITDA net of cash distributions attributable to CNX, plus coal contract buyout of $6 million, less $3 million of severance payments, plus $10 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 of $2.688 billion equals debt of $2.695 billion, less $55 million cash on hand excluding CNXC’s cash, less $197 million of CNXC revolver debt, less $3 million of advance mining royalties, plus $248 million of net letters of credit related to firm transportation obligations, mining equipment leases, and insurance policies.

(2) Total Debt of $2.695 billion excludes total unamortized debt issuance costs of $25 million. (3) Net Debt equals Total Debt less Cash and Cash Equivalents. (4) As of 3/31/2017, CNX had approximately $333 million of outstanding letters of credit under its revolving credit facility, leaving approximately $1,667 million of availability. CNXC

had $197 million outstanding on its revolving credit facility leaving approximately $203 million of availability.

CNX

Owned

LP Units(5)

Unit

Price(5)

Market

Value

CNX Coal Resources LP (CNXC:NYSE) 16.6 $15.20 $252

CONE Midstream Partners LP (CNNX:NYSE) 21.7 $21.25 $461

Total Equity Value of Ownership Interests in Affiliated Public MLPs $713

Liquidity of Affiliated MLPs

Total

Facility

Capacity

Outstanding

Balance

Available

CapacityCash

Total

Liquidity

CNX Coal Resources LP (6)

$400 $197 $203 $6 $209

CONE Midstream Partners LP (6) $250 $167 $83 $6 $89

Leverage Ratio 3/31/2017

LTM Bank EBITDA Attributable to CONSOL Energy Shareholders (7)

$683

LTM Bank Net Debt / Adj. EBITDA (7)

3.9x

Equity Value of Ownership in Affiliated Public MLPs

CNX

Consolidated

CNXC:

100%

CNX

Attributable

Capitalization and Liquidity 3/31/2017 3/31/2017 3/31/2017

Capitalization

Cash and Cash Equiva lents $61 $6 $55

Revolving Credit Faci l i ty Balance 197 197 -

Capita l Lease Obl igations 47 - 47

Total Secured Debt $244 $197 $47

8.25% Senior Notes due 2020 $74 - $74

6.375% Senior Notes due 2021 21 - 21

5.875% Senior Notes due 2022 (1) 1,754 - 1,754

8.0% Senior Notes due 2023 (1) 495 - 495

Baltimore 5.75% Revenue Bonds due 2025 103 - 103

Miscel laneous Debt 4 - 4

Total Debt (2) $2,695 $197 $2,498

Net Debt (3) $2,634 $191 $2,443

Stockholders ’ Equity $3,906 $142 $3,764

Total Capitalization $6,601 $339 $6,262

Liquidity

Cash and Cash Equiva lents $61 $6 $55

Revolving Credit Faci l i ty Capacity (4)

1,870 203 1,667

Total Liquidity $1,931 $209 $1,722

2.2

1.4

4.4

2.0

1.2

0.0

1.0

2.0

3.0

4.0

5.0

2016 2017E 2018E

4Q16 Forecast Current Forecast

Finance: Leverage Ratio and Liquidity Projection

22

(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.

(2) Excludes letters of credit of $333 million. Note: Assumes $400-$600 million in asset sales in 2017 and a base case 20% CNXC drop in 2018. Forecasts based on strip pricing for open volumes as of 4/4/2017.

• Reduced 2017 and 2018 expected leverage ratio targets by an additional 0.2x each since the end of 4Q16

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

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

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

Leverage Ratio 2016-2018E(1)

Liquidity 2016-2018E

Asset Sales Organic

FCF Sources 2017E-2018E

1.7

2.2

2.6

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2016 2017E 2018E

$ in

bill

ion

s

(2) (2)

Finance: Legacy Liabilities

23

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

Balance Sheet Liability Long-Term Liability Guidance

3/31/2017 FY 2017E FY 2018E

LTD $19

WC 79 CWP 118

OPEB 698

Salary Retirement/Pension 111

Asset Retirement Obligations 238

Total Legacy Liabilities $1,263

Total Cash Servicing Cost $19 $74 - $79 $70 - $75

EBITDA Impact ($12) ($57 - $62) ($57 - $62)

Note: 3/31/17 liability balance includes approximately $22 million and $38 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 long-term liabilities are forecasted to approximate $8 million, while the EBITDA loss associated thereto is forecasted to approximate $12 million. Excludes gas well closing.

$4,187

$1,703 $1,497 $1,362 $1,267 $1,263 $1,258

$365

$144 $139 $133

$92 $77 $77 $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 2016 Q1 2017 2017E

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: Segment Guidance

24

Note: Guidance as of 5/2/2017, based on strip pricing as of 4/4/2017. (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.

E&P Segment Guidance 2017E 2018E

Production Volumes:

Natural Gas (Bcf) 380-400 NGLs (MBbls) 6,000-7,000 Oil (MBbls) 45-50 Condensate (MBbls) 600-700

Total Production (Bcfe) 420-440 490-520 % Liquids 9%-11% 7%-12%

Open Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.31) ($0.27) NGL Realized Price ($/Bbl) $20.40 $17.60 Condensate Realized Price % of WTI 70% 70% Oil Realized Price % of WTI 90% 90%

Capital Expenditures ($ in millions):

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

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

Lease Operating Expense $0.17-$0.21 Production, Ad Valorem, and Other Fees $0.07-$0.08 Transportation, Gathering and Compression $0.85-$0.90

Total Cash Production and Gathering Costs $1.09-$1.19 $0.98-$1.11

Other Expenses ($ in millions):

Selling, General, and Administrative Costs(1) $70-$75 $65-$75

Other Corporate Expenses(2) $75-$80 $50-$60

PA Mining Operations – Consolidated 100% Basis 2017E

Coal Sales Volumes:

Total Coal Sales Volumes (millions of tons) 25.6-27.6

Total Committed Volumes (contracted and priced) 25.4 % Committed ~95%

Capital Expenditures ($ in millions): Total Coal Capital Expenditures ($ in millions) $120-$136

• Coal capital expenditures expected to be approximately $5 per ton in 2017 and beyond

Finance: Raising 2017E EBITDA Guidance

25

(1) Includes forecasted Earnings of Equity Affiliates of $40 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.

Base plan assumes NYMEX as of 4/4/2017 of $3.40 per MMBtu + weighted average basis of ($0.29) per MMBtu on open volumes. 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

($ in millions) E&P(1) PA Mining

Operations Other

Current Total

(5/2/17)

Prior Total

(1/31/17)

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

$705 $410 ($20) $1,095 $1,080

Adjustments:

Unrealized (Gain)/Loss on Commodity Derivative Instruments

(150) - - (150) (200)

Stock-Based Compensation 20 10 - 30 30

Adjusted EBITDA $575 $420 ($20) $975 $910

Noncontrolling Interest - (50) - (50) (45)

Adjusted EBITDA Attributable to CNX $575 $370 ($20) $925 $865

APPENDIX

26

Operations: Acreage Position

27

Note: Acreage numbers as of 2016 10-K ; PDPs as of 3/31/2017 (1) Approx. Net Locations calculated with corresponding lateral lengths and spacing for each respective asset region and formation found on modeling input slides; based on total

undeveloped acreage, including both type curve guidance area and surrounding acreage.

SWPA WV CPA OH Total

Upper Devonian Net Acres 111,500 157,000 35,500 - 304,000

Net Acres 103,000 62,000 234,500 13,500 413,000

Fee Acres 41,000 2,000 19,000 3,000 65,000

Approx. Net Locations (1)

572 411 1,472 85 2,540

Net Producing Wells (PDPs) 196 34 60 1 291

Net Acres 151,500 181,000 229,000 121,500 683,000

Fee Acres 48,000 13,000 16,000 38,000 115,000

Approx. Net Locations (1) 855 1,104 1,294 483 3,736

Gross Producing Wells (PDPs) 1 - 1 98 100

Utica

Marcellus

Acreage Position and PDPs by Asset Region and Formation

Asset Region 1: Southwest Pennsylvania Overview

28

Upper Devonian Shale

• Total net acres: 112,000

Marcellus Shale

• Average EUR/1,000’ of 2.7 Bcf(1)


• Total NRI: 89%

• Sizable capital expenditure in the next two years

Utica Shale



• Total NRI: 89%

• Continue to delineate through drilling and participation

(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://investors.consolenergy.com/events-and-presentations/events/2017.

64% Utica/Marcellus core over core acreage overlap

http://investors.consolenergy.com/events-and-presentations/events/2017






0

100,000

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300,000

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0 12 24 36 48

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Months After TIL

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8500' LL

Southwest Pennsylvania Modeling Inputs and Economics

29

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, total undeveloped net locations in region (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing, total undeveloped net locations in region (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) ~572

Wells Online (3/31/17) 196

Avg. PDP Acres/Well 104

Reserves Detail

Gross EUR (Bcf) 21.4

BTU 1,010


WI / NRI (%) 100% / 89%



Asset Region 2: West Virginia Overview

30

Marcellus Shale



• Total NRI: 86%

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

Utica Shale



• 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 Note: Asset region type curve data and modeling inputs available at http://investors.consolenergy.com/events-and-presentations/events/2017.

30% Utica/Marcellus acreage overlap






0

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20,000

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NG

L/C

ND

Pro

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BB

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on

th)

Gro

ss G

as P

rod

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(M

cf/m

on

th)

Months After TIL

Gas

NGL

CND

0

100,000

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Pro

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Mcf

/mo

nth

)

Months After TIL

6500' LL

BTAX ROR % (4)


$2.00 10%

$2.50 20%

$3.00 31%

West Virginia Modeling Inputs and Economics

31

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, total undeveloped net locations in TC guidance area (2) Assuming 6,500 ft lateral @ 1,100 ft inter-lateral spacing, total undeveloped net locations in region (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

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%

Net Locations(2) ~1,104

Wells Online (3/31/17) -


WI / NRI (%) 100% / 86%




Asset Region 3: Central Pennsylvania Overview

32

Marcellus Shale



• Total NRI: 88%

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

• Evaluate Marcellus development in conjunction with Utica

Utica Shale



• Total NRI: 89%

• Continued drilling expected in 2017 and 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 Note: Asset region type curve data and modeling inputs available at http://investors.consolenergy.com/events-and-presentations/events/2017.

96% Utica/Marcellus acreage overlap






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9000' LL

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)

Months After TIL

7000' LL

Central Pennsylvania Modeling Inputs and Economics

33

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, total undeveloped net locations in region (2) Assuming 7,000 ft lateral @ 1,100 ft inter-lateral spacing, total undeveloped net locations in region (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


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%



Reserves Detail


BTU 1,000


WI / NRI (%) 100% / 88%




Asset Region 4: Ohio Overview

34

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

• 100 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

• 159 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://investors.consolenergy.com/events-and-presentations/events/2017.






0

5,000

10,000

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20,000

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30,000

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L/C

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Pro

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Gro

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Months After TIL

Gas

NGL

CND

0

100,000

200,000

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9000' LL

Ohio Modeling Inputs and Economics

35

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


(1) Assuming average 8,500 ft lateral @1,100’ spacing, total undeveloped net locations in region (2) Assuming 8,000 ft and 9,000 ft lateral @ 1,100’ spacing for Ohio Wet and Ohio Dry, respectively, total undeveloped net locations in TC guidance area (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.

OH Utica Total



Ohio Dry - Reserves Detail


BTU 1,060

Ohio Dry - Interest / Net Locations

WI / NRI (%) 100% / 89%




Ohio Wet - Reserves Detail


BTU 1,150

Ohio Wet - Interest / Net Locations

WI / NRI (%) 50% / 45%




Non-GAAP Reconciliation: EBITDA and Adjusted EBITDA

36

Source: Company filings. Note: Income tax effect of Total Pre-tax Adjustments was $40,884 and $10,310 for the three months ended March 31, 2017 and March 31, 2016, respectively. Adjusted net income attributable to CONSOL Energy Shareholders for the three months ended March 31, 2017 is calculated as GAAP net loss attributable to CONSOL Energy Shareholders of $38,966 plus total pre-tax adjustments from the above table of $117,949, less the associated tax expense of $40,884 equals the adjusted net income attributable to CONSOL Energy Shareholders of $38,099. (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

March 31,

2017 2017 2017 2017 2016

($ in thousands)

E&P Division

PA Mining

Operations

DivisionOther

(1) Total Company Total Company

Net (Loss) Income ($93,502) $61,015 ($1,015) ($33,502) ($96,458)

Less: Loss from Discontinued Operations - - - - 53,167

Add: Interest Expense 621 2,297 41,515 44,433 49,865

Less: Interest Income - - (1,543) (1,543) (214)

Add: Income Taxes - - (53,789) (53,789) (23,800)

(Loss)/Earnings Before Interest & Taxes (EBIT) from Continuing Operations (92,881) 63,312 (14,832) (44,401) (17,440)

Add: Depreciation, Depletion & Amortization 95,348 42,301 11,104 148,753 154,988

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

Continuing Operations $2,467 $105,613 ($3,728) $104,352 $137,548

Adjustments:

Unrealized (Gain)/Loss on Commodity Derivative Instruments (24,640) - - ($24,640) 29,271

Impairment of E&P Properties 137,865 - - $137,865 -

Loss on Sale of Gathering Pipeline - - - - 12,636

Severance Expense 162 - 68 $230 2,918

Other Transaction Fees - - 5,316 5,316 -

Gain on Debt Extinguishment - - (822) (822) -

Total Pre-tax Adjustments $113,387 - $4,562 $117,949 $44,825

Adjusted EBITDA from Contiuing Operations $115,854 $105,613 $834 $222,301 $182,373

Less: Net Income Attributable to Noncontrolling Interest - 5,464 - 5,464 1,114

Adjusted EBITDA Attributable to Continuing Operations $115,854 $100,149 $834 $216,837 $181,259

Non-GAAP Reconciliation: TTM EBIT, EBITDA and Adjusted EBITDA

37

Source: Company filings.

Three Months

Ended

Three Months

Ended

Three Months

Ended

Three Months

Ended

Twelve Months

Ended

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

($ in thousands) 2016 2016 2016 2017 2017

Net (Loss)/Income ($468,649) $27,593 ($301,634) ($33,502) ($776,192)

Less: Loss from Discontinued Operations 234,605 34,975 (19,564) - 250,016

Add: Interest Expense 47,427 47,317 46,867 44,433 186,044

Less: Interest Income (547) (214) (532) (1,543) (2,836)

Add: Tax Valuation Allowance - - 166,798 - 166,798

Add: Income Taxes (100,856) 52,858 (84,990) (53,789) (186,777)

(Loss)/Earnings Before Interest & Taxes (EBIT) from Continuing Operations (288,020) 162,529 (193,055) (44,401) (362,947)

Add: Depreciation, Depletion & Amortization 135,220 151,712 156,583 148,753 592,268

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

Continuing Operations ($152,800) $314,241 ($36,472) $104,352 $229,321

Adjustments:

Unrealized Loss/(Gain) on Commodity Derivative Instruments 279,715 (159,555) 236,802 (24,640) 332,322

Impairment of E&P Properties - - - 137,865 137,865

Severance Expense 1,451 952 424 230 3,057

Pension Settlement 13,696 3,652 4,848 - 22,196

Other Transaction Fees - - 3,752 5,316 9,068

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

Gain on Debt Extinguishment - - - (822) (822)

Total Pre-tax Adjustments $288,574 ($154,951) $245,826 $117,949 $497,398

Adjusted EBITDA from Continuing Operations $135,774 $159,290 $209,354 $222,301 $726,719

Less: Net Income Attributable to Noncontrolling Interest $1,179 $2,248 $4,413 $5,464 $13,304

Adjusted EBITDA Attributable to Continuing Operations $134,595 $157,042 $204,941 $216,837 $713,415

Free Cash Flow Reconciliation

38

Source: Company filings.

Three Months Ended Three Months Ended

March 31, March 31,

($ in thousands) 2017 2016

Net Cash provided by Continuing Operations $205,194 $119,808

Capital Expenditures (112,978) (78,968)

Net Distributions from Equity Affiliates 5,909 (5,578)

Organic Free Cash Flow From Continuing Operations $98,125 $35,262

Net Cash Provided By Operating Activities $205,119 $128,442

Capital Expenditures (112,978) (78,968)

Capital Expenditures of Discontinued Operations - (5,737)

Net Distributions from Equity Affiliates 5,909 (5,578)

Proceeds from Sales of Assets 19,427 411,259

Free Cash Flow $117,477 $449,418

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