Earnings Results - CNX Resources...

Earnings ResultsFirst Quarter 2019

April 30, 2019

Cautionary Language

2

Risk Factors. This presentation, including the oral statements made in connection herewith, contains forward-looking statements, estimates and projections within the meaning of the federal securities laws.

Statements that are not historical are forward-looking and may include our operational and strategic plans; estimates of gas reserves and resources; 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, estimates and projections. Investors should not place undue reliance on forward-looking statements as a prediction of future actual results. 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.

Specific factors that could cause future actual results to differ materially from the forward-looking statements are described in detail under the captions "Forward Looking Statements" and "Risk Factors" in our annual

report on Form 10-K for the year ended December 31, 2018 filed with the SEC, as supplemented by our quarterly reports on Form 10-Q. Those risk factors discuss, among other matters, pricing volatility or pricing

decline for natural gas and NGLs; operational risks relating to midstream facilities, pipeline systems, drilling natural gas wells, access to key services and equipment, access to adequate water sources and customer

interactions; the impact of laws and regulations on our business and industry; competitive and economic concerns; risks associated with our debt and hedging strategy; our ability to acquire economically recoverable

natural gas reserves; challenges associated with strategic determinations, including the allocation of capital to strategic opportunities; our development and exploration projects and potential acquisitions or

divestitures, as well as CNXM's midstream system development.

Reserves. 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.

Title. 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.

Reconciliation. As it relates to the disclosures within this presentation of projected Adjusted EBITDA, projected EBITDAX, projected cash flow and other projected non-GAAP metrics for fiscal or quarterly periods in

2019 or beyond, for CNX or CNXM, CNX is unable to provide a reconciliation of such metrics to projected operating income, the most directly comparable financial measure calculated in accordance with GAAP, due to

its inability to calculate projected operating income due to the unknown effect, timing, and potential significance of certain income statement items for each of CNX and CNXM, respectively.

Data. This presentation has been prepared by CNX and includes market data and other statistical information from sources believed by CNX to be reliable, including independent industry publications, government

publications and other published independent sources. Some data are also based on CNX’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described

above. Although CNX believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy or completeness.

Trademarks. CNX owns or has rights to various trademarks, service marks and trade names that it uses in connection with the operation of its business. This presentation also contains trademarks, service marks

and trade names of third parties, which are the property of their respective owners. CNX’s use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and

does not imply, a relationship with CNX or an endorsement or sponsorship by or of CNX. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appear without the

®, TM or SM symbols, but such references are not intended to indicate, in any way, that CNX will not assert, to the fullest extent under applicable law, its rights or the right of the applicable licensor to these

trademarks, service marks and trade names.

Not an Offer. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CNX Resources Corporation or CNX Midstream Partners LP.

Executive Summary

3

Q1 2019 EXPECTATION

STRATEGIC THEME

Operational Execution and

Strong Cost and Margin

Performance(1)

▪ Production cash costs down 8% Y/Y and fully-burdened

margins up 6% Y/Y; LOE and low transportation and

gathering fees create advantage

▪ Bought back additional 3.7 million shares from 1Q19

start through 4/15/19 and reduced leverage to 2.1x

▪ Minimal firm transportation commitments, operational

initiatives, and robust hedge book to drive margins and

risk-adjusted returns through the backwardated price cycle

Adding Incremental Activity Set

to Benefit 2020 Program

▪ Supported by strong rates of return and robust hedge

book, 2019 activity increase driven by improved

confidence in Utica after quality assurance/quality

control initiative and decision to pull forward activity in

face of lower strip beyond 2020

▪ Benefit of additional activity primarily to impact 2020

production and development program

▪ Future development decisions will continue to be evaluated

against all capital allocation options

Updating 2019 Capital Budget

Guidance Based on Incremental

Activity

▪ 2019 minimum D&C capex guidance increasing by

$120 million to $695-$745 million to support incremental

TILs in 2020E

▪ Carryover D&C capex in 2020 to finish 2019 program of

~$165 would be enough to drive significant production

growth by itself in 2020

2019 Setting Up Capital

Allocation Options for 2020

▪ Total company guided capex spend including 2019 non-

D&C (water/land) and CNX Midstream buildout set

stage for 2020 production growth and optionality

▪ As the program stands, CNX would generate substantial

free cash flow in 2020 spending only what is necessary to

finish the 2019 program; de-risked by hedge book

Shaw Event Resolved with

Minimal Impact to Program and

Several Key Lessons Learned

▪ Shaw 1G well remediated following January event

▪ Operational reevaluation led to the identification and

development of a number of best practices

▪ Long-term benefit of broad-based risk mitigation positively

benefiting company’s NAV per share

(1) See non-GAAP reconciliation tables below.

Margin 58% 61% 64% 68% 63%

$1.21 $1.09 $1.04 $1.00 $1.11

$1.79 $1.78 $1.88

$2.09

$1.86

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019

Total Production Cash Costs Total Production Cash Margin

$1.72 $1.65 $1.59 $1.46 $1.61

$1.28 $1.22 $1.33

$1.63

$1.36

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019

Total Fully-Burdened Cash Costs Total Fully-Burdened Cash Margin

Q1 2019 Operational Results Summary

4

▪ Marcellus Shale costs were $2.02 per Mcfe in Q1 2019, a decrease of

$0.28 from $2.30 per Mcfe vs. Q1 2018, or a 12% decline

- Driven primarily by decreases in LOE

▪ Utica Shale costs were $1.64 per Mcfe in Q1 2019, an increase of $0.04,

or 3%, from $1.60 per Mcfe in Q1 2018

- Excluding DD&A, Utica production cash costs were $0.47 per Mcfe in

Q1 2019

- The modest increase in Utica costs was driven by lower y/y production

volumes following the divestiture of OH joint venture assets

▪ E&P capital expenditures decreased 16% Q/Q to $223 million in Q1

2019 from $266 million spent in Q4 2018(1) Average sales prices for 1Q2019, 1Q2018, and 4Q2018 include (loss) / gain on commodity derivative instruments

(cash settlements) of ($0.33), ($0.14), and ($0.56) per Mcf, respectively.

(2) Total Production Costs for 1Q2019, 1Q2018, and 4Q2018 include DD&A of $0.88, $0.89, and $0.89 per Mcfe,

respectively.

(3) See non-GAAP reconciliation table below. Includes per unit Lease Operating Expense; Transportation, Gathering and Compression; and Production, Ad Valorem

and Other Fees. See non-GAAP reconciliation table below.

(4) See non-GAAP reconciliation table below. Includes Production Cash Costs listed above plus SG&A (excluding non-cash stock compensation), Other Operating Cash

Expense, Other Cash Expense (Income), and Interest Expense.

Production Cash Costs(3) and Margins 1Q18-1Q19 Fully-Burdened Cash Costs(4) and Margins 1Q18-1Q19

($/Mcfe) 1Q 2019 1Q 2018

Y/Y

Change 1Q 2019 4Q 2018

Q/Q

Change

Average Sales Price(1)

$2.97 $3.00 ($0.03) $2.97 $3.09 ($0.12)

Total Production Costs(2)

$1.99 $2.10 ($0.11) $1.99 $1.89 $0.10

Sales Volumes (Bcfe) 133.0 129.5 3.5 133.0 136.1 (3.1)

Sales Volumes by Category (Bcfe)

Marcellus 88.7 65.9 22.8 88.7 87.0 1.7

Utica 30.6 43.5 (12.9) 30.6 34.0 (3.4)

CBM 13.7 15.9 (2.2) 13.7 15.0 (1.3)

Other 0.0 4.2 (4.2) 0.0 0.1 (0.1)

Margin 44% 43% 46% 53% 46%

Q1 and FY2019E-2020E Activity Based on 2019 Capital Program

5

(1) Measured in lateral feet from perforation to perforation.

Q1 2019

($ in millions) TD FRAC TIL

Average

Lateral

Length(1)

Rigs at

Period

End

SWPA

Central

Marcellus 6 14 18 7,618 2

Utica 2 - - 2

WV

Shirley-Penns

Marcellus - - - - 1

Utica - - - -

CPA South Utica 1 - - -

OH Dry Utica - - - -

Total 9 14 18 5

FY 2019E

TD FRAC TIL

Marcellus 41 51 48

Utica 16 16 14

Total 57 67 62

FY 2020E

TD FRAC TIL

- 8 20

- 2 4

- 10 24

20

19

Pro

gra

m

Carr

yo

ve

r

▪ The 2019 minimum development program would result

in 24 DUCs at year-end with expected TIL in 2020

▪ Expected D&C capex required to frac and TIL the

carryover wells is ~$165 million

▪ Currently five rigs under contract

▪ With no additional rig commitments, there would be

three rigs under contract at year end 2019

▪ Decisions to retain or add rigs will be based on

market conditions and rate of return analyses

2019 Development Program and Capital Breakdown

(1) D&C capital expenditures includes all costs related to drilling, completions, pad construction, production facilities, water supply, and disposed water flowback.

(2) Average drilled lateral length.

(3) Midpoint of 2019 guided capital expenditure range of $695-$745 million. Includes $15 million associated with one-time Shaw pad remediation. 6

D&C CapEx(1) TILsAverage

Lateral Length(2)

($ in millions) 2019E 2020E 2019E 2020E 2019E 2020E

Marcellus $495 $115 48 20 10,050’ 10,650’

Utica $225 $50 14 4 6,500’ 8,900’

Total $720(3) $165 62 24 9,300 10,300

$885M D&C

CapEx86 TILs

CPA Utica Shaw Pad

▪ The Shaw 1G well that experienced issues in early

1Q 2019 has been remediated

▪ The remaining three laterals exist as DUCs and,

pending DEP approval, could be turned-in-line by

year-end 2019

▪ The 2019 D&C capital guidance includes $15

million of one-time Shaw-related remediation capital

TILs: Prior Plan (Feb. 2019) TILs: Revised Plan (Apr. 2019) Variance

2019E 2020E 2019E 2020E 2019E 2020E

Marcellus49 SWPA

5 WV

6 SWPA 43 SWPA

5 WV

20 SWPA -6 SWPA +14 SWPA

Utica

5 SWPA

2 OH

5 OH 9 SWPA

3 CPA

2 OH

4 SWPA +4 SWPA

+3 CPA

+4 SWPA

-5 OH

Total 61 11 62 24 +1 +13

Revised 2019 program

adds 11 PA deep dry Utica

TILs from prior plan

SWPA Marcellus: Continued Optimization and Outperformance

7

▪ Used remote frac pads to increase efficiency and eliminate need to shut in

existing PDP production

▪ 141% average increase in completion cycle times (sand volume pumped per

day) since 2017

▪ 50% average increase in drilling cycle times (feet drilled per day) since 2017

▪ 11% Increase in capital efficiency due to changes in process and design since

2017

50%

141%

-10%

10%

30%

50%

70%

90%

110%

130%

150%

MOR 30 MOR 31 RHL22 MOR 42 RHL27 MOR 29 MOR 40 MOR 44 RHL28

Eff

icie

ncy G

ain

(%

)

SWPA Operational Efficiency

Drilling Frac

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

0 100 200 300 400 500 600

Cum

ula

tive M

cf N

orm

aliz

ed t

o 8

000'

Days

Richhill – Marcellus

RHL 22 (2018 Q3)

RHL 27 (2018 Q4)

RHL 28(2019 Q1)

Legacy RHL (2015-2016)

RHL Marcellus Type Curve

35%+ Increase

in EUR over

Legacy Wells

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

0 100 200 300 400 500 600

Cum

ula

tive M

cf N

orm

aliz

ed t

o 8

000'

Days

Morris – MarcellusMOR 29 (2018 Q4)

MOR 30 (2017-2018)

MOR 31 (2018 Q3)

MOR 42 (2018 Q3)

Legacy MOR (2012-2013)

MOR Marcellus Type Curve

110%+ Increase

in EUR over

Legacy Wells

Production Far Exceeds Legacy Well Performance Operational Efficiency Reduces Capital and Increases IRR

Substantial Richhill

inventory remains for near-

term development

2017

(1) (2)

(1) Change in total feet drilled per day.

(2) Change in sand volume pumped per day.

OH Dry Utica: Optimized Field Development Informs PA Utica

8

PA Dry Utica Compared to Switz:

▪ Similar geophysical density

responses

▪ Higher reservoir pressure

▪ Optimized managed pressure

drawdown strategy

Decreased

Cycle Times

Proppant

Selection

and Loading

Full Field

Optimization

with Wider

Spacing

However, PA dry Utica

benefits from:

▪ Stacked pay efficiencies

▪ Drilling guided by 3-D Seismic

Extending inter-lateral spacing from 1100’ to 1350’, increasing sand per foot,

and reducing specialty sand increased operational efficiencies and well

performance:

▪ 106% average increase in completion cycle times (sand volume pumped per day)

▪ 12% average increase in drilling cycle times (feet drilled per day)

▪ 33% average EUR/1000’ increase

▪ 18% increase in capital efficiency due to changes in process and design

32%

177%

-10%

40%

90%

140%

190%

240%

SWITZ 16 SWITZ 5 SWITZ 28 SWITZ 11 SWITZ 26 SWITZ 7 SWITZ 18 SWITZ 27 SWITZ 9

Eff

icie

ncy G

ain

(%

)

Switz Operational EfficiencyDrilling Frac

63%

-10%

10%

30%

50%

70%

90%

SWITZ 16 SWITZ 5 SWITZ 28 SWITZ 11 SWITZ 26 SWITZ 7 SWITZ 18 SWITZ 27 SWITZ 9

EU

R I

mpro

vem

ent (%

) Switz EUR Performance

(1) (2)

(1) Change in total drilled feet per day.

(2) Change in sand volume pumped per day.

2016

2016

Implementing Elements of the “Perfect Pad”

9

12 Marcellus

wells drilled

Process

Dry month construction

Subsurface Marcellus well heads

Marcellus

completions

8 Utica

wells drilled

Utica

completions

3D seismic drives well bore optimization

Marcellus wells turned in line

M M M M M M

M M M M M M

U U U U

U U U U

Utica wells turned in line

Lo

w P

ressu

re

Lin

e

Cellar technology construction allows for subsurface well heads

for faster return

Two pipe system creates flexibility to produce high pressure and

low pressure wells simultaneously

Hig

h P

ressu

re L

ine

Hig

h P

ressu

re L

ine

Lo

w P

ressu

re

Lin

eM M M M M M

M M M M M M

Prior

Days

Target

Days

120 90

122 97

142 78

124 102

119 57

Optimal inter-lateral spacing: Marcellus 750 ft, Utica 1200-1500 ft

31%

Reduction

35%

Reduction

✓

✓

✓~500 square miles of 3D seismic coverage by YE2019

11 return to pad trips in 2019; 4 of which are stacked pay

✓Under construction in core SWPA development area

Other Operational Advancements

▪ Low operational risk average lateral length increase of 23%

from 2018 to 2019

▪ Prioritization of reusing produced water and pumping fresh

water rather than trucking

▪ Remote fracs and Evolution all-electric frac crew expected to

minimize pad footprints

Q1 2019 Summary

($ in millions, except per share data) 1Q 2019 1Q 2018 Y/Y Units Y/Y - % 1Q 2019 4Q 2018 Q/Q Units Q/Q - %

Total Revenue and Other Operating Income $278 $496 ($218) -44% $278 $435 ($157) -36%

Consolidated Adjusted Net Income(1)

$67 $60 $7 12% $67 $160 ($93) -58%

Consolidated Adjusted EBITDAX(1)

$268 $259 $9 3% $268 $314 ($46) -15%

Consolidated Adjusted EBITDAX(1)

Per Share $1.37 $1.19 $0.18 15% $1.37 $1.58 ($0.21) -13%

Shares Outstanding (millions) 195.5 217.9 (22.4) -10% 195.5 198.3 (2.8) -1%

Q1 2019 Financial Results Summary

10

Note: The terms “Consolidated adjusted EBITDAX,” “Stand-Alone Adjusted EBITDAX (including distributions),” “Stand-Alone Adjusted EBITDAX (including distributions) per

share,” “Consolidated adjusted EBITDAX per share,” and “adjusted net income“ are non-GAAP financial measures, which are reconciled to the GAAP net income below.

(1) See non-GAAP reconciliation table below and Q4 2018 press release dated January 31, 2019.

(2) Shares outstanding as of April 15, 2019.

(3) Shares outstanding as of April 16, 2018.

(4) Shares outstanding as of January 18, 2019.

Net Income and Adjusted EBITDAX

▪ Net loss attributable to CNX Shareholders of $87 million in the 2019 first quarter; consolidated adjusted net income of $67

million(1); adjusted net income excludes the following pre-tax items:

- $154 million unrealized loss on commodity derivative instruments

- $11 million in stock-based compensation

- $15 million in other miscellaneous items

▪ Consolidated adjusted EBITDAX in the first quarter of $268 million or $1.37 outstanding per share(1)(2); stand-alone adjusted

EBITDAX + distributions in the first quarter was $224 million(1) or $1.15 per outstanding share

(2) (2)(3) (4)

230.1

6.4 5.8 5.3

8.3 6.5 1.4

195.5

3.7

-

50.0

100.0

150.0

200.0

250.0

S/O 3Q17E Repurchased4Q17E

Repurchased1Q18

Repurchased2Q18

Repurchased3Q18

Repurchased4Q18

Repurchased1Q19 to4/15/19

Comp SharesIssued

S/O 4/15/2019

Sh

are

s (

mill

ion

s)

Debt Discipline and EBITDAX Growth Drive Available Capacity

11

(1) Includes current portion.

(2) See non-GAAP reconciliation table below.

Stand-Alone Midstream

Stand-Alone and Consolidated Net Debt

$ in millions March 31, 2019

Total

Total Long-Term Debt (GAAP)(1) $1,900.4 $530.1 $2,430.5

Less: Cash and Cash Equivalents $22.8 $1.2 $24.0

Net Debt (Non-GAAP)(2) $1,877.6 $528.9 $2,406.5

▪ In Q1 2019, CNX redeemed $400 million of 5.875% notes

due 2022 upon completion of the offering of $500 million of

7.25% senior notes due 2027; remainder of senior notes

net proceeds used to repay existing credit facility debt

▪ In April of 2019, CNX amended and restated its credit

facility, while maintaining a $2.1 billion borrowing base; the

maturity has been extended from March 2023 to April 2024

Q1 2019 Stand-Alone Net Debt /

TTM Stand-Alone Adjusted EBITDAX + Distributions2.1x

Shares Repurchased Since Program Announced

▪ Have deployed ~$520 million since the end of Q3 2017 retiring

approximately 15% of shares outstanding

▪ Remaining authorization outstanding for ~$230 million with no

expiration date

▪ As capital allocation decisions arise, all will be analyzed through

the strict NAV/share lens and with future opportunities in mind

TTM Adjusted Stand-Alone EBITDAX + Distributions(2) $892.7

+

Updated 2019 Guidance

CNX Resources Corporation is unable to provide a reconciliation of projected stand-alone or consolidated adjusted EBITDAX to projected operating income, the most

comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate GAAP projected operating income given the unknown effect,

timing, and potential significance of certain income statement items.

(1) Expected 5-6% liquids.

(2) Pro forma growth comparing 2019E production with 2018 production from assets not sold of 480 Bcfe.

(3) Forward pricing date as of 4/5/2019.

(4) Includes CNX Midstream LP + GP/IDR distributions of $55 million in FY2019E.12

PREVIOUS UPDATED

2019E 2019E

Capital Expenditures($ millions)

Low High Low High

Drilling & Completions $575 $625 $695 $745

Non-D&C $175 $175 $200 $200

Total E&P Capital $750 $800 $895 $945

CNX Midstream LP Capital $250 $280 $310 $330

Total Consolidated Capital $1,000 $1,080 $1,205 $1,275

Production(Bcfe)

Total Production Volumes(1) 495 515 495 515

Y/Y Growth (2018 pro forma)(2) 3% 7% 3% 7%

Adjusted EBITDAX(3)

($ millions)

E&P Standalone +

Distributions(4)$790 $825 $770 $790

Consolidated $945 $985 $920 $950

Incremental D&C activity driven by confidence in Utica program coming out

of QA/QC process and drilling success with SWPA Utica TDs

CNX Midstream capital expenditure increase resulting from acceleration of

2020 buildout to facilitate incremental parent activity

As previously guided, CNX Midstream capital expected to decline

meaningfully in 2020 following initial system buildout in 2019

Increase in non-D&C capital expenditure guidance due to higher water line

spend and additional land and midstream capital

Reduction in stand-alone and consolidated EBITDAX expectations due to

decline in natural gas prices since last update

Updated 2019 Guidance

13

2019ERevenue and Other Operating Income E&P Consolidated

Production Volumes:

Natural Gas (Bcf) 465-485

NGLs (MBbls) 4,500-4,600

Condensate (MBbls) 350-400

Total Production (Bcfe) 495-515

% Liquids 5-6%

Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.20)-($0.25)

NGL Realized Price ($/Bbl) $20.00-$22.00

Condensate Realized Price % of WTI 75%

Realized Hedging Gain/(Loss) ($ in millions) (1) ($55)-($60)

Other Operating Income (3rd party water income and resold FT) ($ in millions) $15-$20

CNXM 3rd Party Gathering Revenue $55-$65

Costs

Average per unit operating expenses ($/Mcfe):

Lease Operating Expense $0.12-$0.14

Production, Ad Valorem, and Other Fees $0.05-$0.06

Transportation, Gathering and Compression $0.96-$1.00 $0.62-$0.66

Total Cash Production and Gathering Costs $1.13-$1.20 $0.79-$0.86

($ in millions)

Selling, General, and Administrative Costs(2) $90-$100 $110-$120

Exploration Expense $5-$10

Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $75-$85

Other Non-Operating Expense (Income) ($5)-($15)

Total Capital Expenditures $895-$945 $1,205-$1,275

EBITDAX (E&P Stand-alone + Distributions and Total Consolidated) $770-$790 $920-$950

Total Distributions (LP + GP/IDR) $55

CNX Resources Corporation is unable to provide a reconciliation of projected stand-alone or consolidated adjusted EBITDAX to projected operating income, the most

comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate GAAP projected operating income given the unknown effect,

timing, and potential significance of certain income statement items.

(1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 4/5/2019. Anticipated hedging activity is not included in projections.

(2) Excludes stock-based compensation.

Royalty income, right of way sales, interest income

and ‘other’ all netted against bank fees, other

corporate expense, and other land rental expense

Expected hedging loss improved due to decline in

Henry Hub pricing since last update

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Pro

duction (

Bcfe

/d)

Legacy PDP Marcellus PUD Utica PUD

2020 Set Up for Production & FCF Growth on 2019 Program Alone

14

Expected Daily Production 2020E

Based on 2019 Development Program Only

Note: Graph based on midpoint of 2019 production volume guidance range of 495-515 Bcfe.

(1) Fully burdened cash costs based on midpoint of 2019 guidance, includes production cash costs, selling, general and administrative (SG&A) cash costs, other

operating cash expense, other cash (income) expense, and interest expense.

2020

Marcellus: 20

Utica: 4

Significant

Production

Growth

2020 DUC

D&C Capex

of $165M

$51M

AMT

Refund

HE

DG

E B

OO

K

440

Bcfe

fu

lly-h

ed

ge

d in

20

20

Marcellus: 48

Utica: 14

2019

Average Hedged Volumes

2020 FCF

OPPORTUNITY

Potential to:

Reduce debt

and/or

Retire additional

25% of S/O

and/or

Increase activity

($ in million, except per unit) 2020E

Production (Bcfe) ~555

Weighted Average Revenue (NYMEX+Hedges) ($/Mcfe) $2.65

Fully Burdened Cash Costs ($/Mcfe)(1) $1.65

Cash Margin ($/Mcfe) $1.00

Plus: Distributions (LP+GP/IDR) and AMT Tax Refund $125

Less: 2020 DUC Capital $165

Free Cash Flow ~$500

86

TIL

s

460 Bcf hedged at

NYMEX $2.94 in 2020

377.0 440.4

370.3

222.4

113.7

-

30.9

45.9

59.7

33.6

0

50

100

150

200

250

300

350

400

450

500

2019 2020 2021 2022 2023

Gas V

olu

mes H

edged (

Bcf)

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

Natural Gas Hedging and Basis Protection

15

(2)

Hedge Volumes and Pricing Q2 2019 2019 2020 2021 2022 2023

NYMEX Hedges

Volumes (Bcf) 91.1 360.1 459.9 395.1 268.5 119.7

Average Prices ($/Mcf) $3.04 $3.04 $2.94 $2.92 $2.97 $2.85

Physical Fixed Price Sales and Index Hedges

Volumes (Bcf) 4.0 16.9 11.4 21.1 13.6 27.6


Total Volumes Hedged (Bcf)(1) 95.1 377.0 471.3 416.2 282.1 147.3

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

Volumes (Bcf) 95.1 377.0 440.4 370.3 222.4 113.7


NYMEX Hedges Exposed to Basis

Volumes (Bcf) - - 30.9 45.9 59.7 33.6

Average Prices ($/Mcf) - - $2.94 $2.92 $2.97 $2.85

Total Volumes Hedged (Bcf)(1) 95.1 377.0 471.3 416.2 282.1 147.3

(1) Hedge positions as of 4/11/2019. Q2 2019 and 2019, exclude 5.0 Bcf and 3.2 Bcf, respectively, of physical basis sales not matched with NYMEX hedges

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

(3) Assuming midpoint of total dry gas production guidance in 2019E.

Layering in hedges out to 2023 and beyond

to protect margins on proved developed

production and a portion of PUDs

De-risked pricing for next three

years and meaningful upside

potential

Protecting from in-basin

blowout through regional

basis hedges

Fully-covered hedges represent

~79% of 2019E base dry gas

volumes(3)

NYMEX hedges added during Q1:

152.4 Bcf (for 2021 through 2024)

Basis hedges added during Q1:

137.7 Bcf (2019 through 2023)

Fresh60%

Produced40%

SWPA Frac Water

CNX Water Infrastructure Drives SWPA Advantage

16

Produced

Volume

(bbls)

~Cost Δ

($/bbl)

Trucked 17% +$5.00

Pumped 83%

Fresh

Volume

(bbls)

~Cost Δ

($/bbl)

Trucked 4% +$2.50

Pumped 96%

CNX currently handling ~30,000 barrels a day of produced water

▪ CNX benefits from low cost of pumping

produced water off pads

▪ 800,000 Bbls of storage by YE2019

- Allows buffer between completion

operations

- Minimizes disposal volumes

- Allows for efficient truck off-loading

▪ ~ 90% of SWPA pads connected to

infrastructure

▪ Diverse access to multiple fresh water

sources

- Avoids delaying completion

operations

- Sustainable sources such as Ohio

River and Washington Reservoirs

▪ Fewer safety accidents

- 87% less when pumping

▪ SWPA pumping removes 800 truck

hours a day

- Less truck emissions

- Less truck traffic

- Less noise and light pollution

- Significant reduction in road

maintenance

▪ Automated monitoring of infrastructure

- Monitored by command center 24/7

- Real-time tank level and flow rate

meters

▪ Provide fresh water to other E&P

operators

- ~$11 million of third-party revenue in

2018

▪ Currently accepting produced water for

a fee at off-load facilities

- Industry generates 4.5 million bbls

of water produced in PA each month

- 500,000 bbls pass CNX

infrastructure for treatment or

reuse at $5+/bbl savings

▪ Positioned for the long-term

- CNX is able to provide outlets when

reuse is no longer an option

- Treatment options for CNX and third

parties

Reduced Cost Safe and Clean Third-Party RevenueSWPA Water Infrastructure Investments

December 31,

2018 2017

Deferred Tax Assets:

Alternative Minimum Tax $ 102,482 $ 188,080

Net Operating Loss - Federal 124,341 99,524

Net Operating Loss - State 110,339 107,756

Foreign Tax Credit 43,194 44,402

Interest Limitation 32,147 —

Equity Compensation 13,096 21,866

Gas Well Closing 10,140 55,486

Salary Retirement 9,434 9,404

Capital Lease 1,624 2,020

Other 13,714 11,831

Total Deferred Tax Assets 460,511 540,369

Valuation Allowance (94,455) (136,576)

Net Deferred Tax Assets 366,056 403,793

2019 AMT Credit and Additional Refunds

Note: Current Assets and Deferred Tax tables from Q1 2019 10-Q and 2018 10-K respectively.

(1) Timing of recovery of approximately $3.5 million remains uncertain and therefore not included in 2019 plan.

17

▪ Approximately $131 million in total AMT refund expected in 2019

▪ Additional cash tax refunds related to past filings and other

miscellaneous recoveries of ~$15 million expected by the end of the

year

▪ $36 million of AMT and other tax refunds received in Q1 2019;

incremental ~$110 million expected in remainder of the year

▪ Incremental AMT refund expected in 2020 and 2021 of approximately

$51 million each year

▪ Company continues to expect no cash tax payments for 4-5 years due

to NOL utilization

Combined AMT refund and additional tax refunds to

drive total cash tax inflow of ~$146 million in 2019

March 31, December 31,

2019 2018

Current Assets

Cash and Cash Equivalents $ 23,972 $ 17,198

Accounts and Notes Receivable

Trade 157,908 252,424

Other Receivables 10,276 11,077

Supplies Inventories 16,642 9,715

Recoverable Income Taxes 113,592 149,481

Prepaid Expenses 42,576 61,791

Total Current Assets 364,966 501,686

(1)

Appendix

TYPE CURVE AREAS

SWPA Central Greater TOTAL SWPA

Total Net Acres 98,100 33,700 131,800

Net Developed Acres 28,300 2,400 30,800

Net Undeveloped Locations 427 191

Average Lateral Length (ft) 9,500 9,500

Inter-Lateral Spacing (ft) 750 750

WV SHR/PENS East TOTAL WV

Total Net Acres 17,200 14,300 93,400

Net Developed Acres 6,700 - 6,700




CPA South North TOTAL CPA

Total Net Acres 103,300 95,300 301,100

Net Developed Acres 5,100 900 6,100




OH TOTAL OH

Total Net Acres 12,800

Net Developed Acres 200

Net Undeveloped Locations

Average Lateral Length (ft)

Inter-Lateral Spacing (ft)

COMPANY Total Net Acres 539,000

YE2018 Acreage and Undeveloped Location Update

Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019.

Acres by type curve area do not equal total acres because some CNX-controlled acres fall outside of identified type curve areas. Average lateral lengths and inter-lateral

spacing assumptions unchanged from 2018 Analyst Day.

Totals may not foot due to rounding.19

MARCELLUS UTICATYPE CURVE AREAS

SWPA Central Greater TOTAL SWPA

Total Net Acres 120,500 55,100 175,600

Net Developed Acres 300 - 300



Inter-Lateral Spacing (ft) 1,200 1,200

WV SHR/PENS East TOTAL WV

Total Net Acres 14,100 83,900 134,500

Net Developed Acres - - -




CPA South North TOTAL CPA

Total Net Acres 104,900 95,200 239,600

Net Developed Acres 400 200 600




OH Dry TOTAL OH

Total Net Acres 13,800 77,600

Net Developed Acres 10,000 10,000

Net Undeveloped Locations 14

Average Lateral Length (ft) 9,000

Inter-Lateral Spacing (ft) 1,350

COMPANY Total Net Acres 627,000

YE2018 Type Curve Area and Acreage Update

Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019.

20

Marketing Highlights and Liquids Realizations

21

(1) Calculation includes the impact of gas hedging cash settlements.

Marketing Highlights

▪ Directly-marketed ethane sales volumes were limited

in the quarter due primarily to Mariner East delivery

constraints.

▪ $0.09 per Mcfe uplift(1) from liquids for total average

realization of $2.97 per Mcfe in Q1 2019

2019 2018

Q1 Q1

NYMEX Natural Gas ($/MMBtu) $3.15 $3.00

Average Differential (0.17) (0.21)

BTU Conversion (MMBtu/Mcf)* 0.23 0.17

Loss on Commodity Derivative

Instruments-Cash Settlement(0.33) (0.14)

Realized Gas Price per Mcf $2.88 $2.82

* Conversion factor 1.07 1.06

Natural Gas Price Reconciliation

Natural Gas Liquids, Oil and Condensate

▪ Q1 2019 liquids sold: 7.1 Bcfe

▪ Total weighted average price of all liquids decreased 6% to $27.41 per

Bbl in Q1 2019 from $29.15 per Bbl in Q1 2018 and increased 7% from

$25.61 per Bbl in Q4 2018

▪ In Q1 2019, liquids comprised approximately 5% of production

volumes and 12% of total revenue and other operating income

Average Price Realization ($ per Bbl)

2019 2018

Q1 Q1

NGLs $26.76 $27.48

Oil $43.56 $56.46

Condensate $39.00 $49.32

Q2 2019 CY2019

Hedged Volumes Hedged Forward Forecasted Gain/(Loss)

(000 MMBtu) Price Market ($/MMBtu) ($ in 000's)

($/MMBtu)

NYMEX 98,053 $2.83 $2.70 $0.13 $12,879

Basis:

DOM South (DOM) 10,920 ($0.59) ($0.33) ($0.26) ($2,885)

TCO Pool (TCO) 14,560 ($0.36) ($0.24) ($0.12) ($1,683)

Michcon (NMC) 8,872 ($0.21) ($0.14) ($0.07) ($583)

TETCO ELA (TEB) 1,820 ($0.09) ($0.12) $0.03 $63

TETCO WLA (TWB) 1,820 ($0.08) ($0.08) ($0.00) ($3)

TETCO M3 (TMT) 4,323 ($0.19) ($0.26) $0.07 $285

TETCO M2 (BM2) 29,575 ($0.58) ($0.35) ($0.23) ($6,842)

Total Financial Basis Hedges 71,890 ($11,648)

Total Projected Realized Gain $1,231

Q2 2019E Gas Hedging Gain/Loss Projections

22

Note: Forward market prices, hedged volumes, and hedge prices are as of 4/11/2019. Anticipated hedging activity is not included in projections.

(1) April prices are settled.

(1)

CY2019 CY2020

Hedged Volumes Hedged Forward Forecasted Gain/(Loss)

(000 MMBtu) Price Market ($/MMBtu) ($ in 000's)

($/MMBtu)

NYMEX 386,088 $2.83 $2.88 ($0.05) ($18,841)

Basis:

DOM South (DOM) 43,800 ($0.59) ($0.35) ($0.24) ($10,591)

TCO Pool (TCO) 52,360 ($0.35) ($0.26) ($0.09) ($4,503)

Michcon (NMC) 32,262 ($0.20) ($0.16) ($0.04) ($1,316)

TETCO ELA (TEB) 7,300 ($0.09) ($0.12) $0.03 $248

TETCO WLA (TWB) 7,300 ($0.08) ($0.08) $0.00 $13

TETCO M3 (TMT) 15,423 $0.12 $0.27 ($0.15) ($2,289)

TETCO M2 (BM2) 110,610 ($0.58) ($0.38) ($0.20) ($22,266)

Total Financial Basis Hedges 269,055 ($40,704)

Total Projected Realized Loss ($59,545)

2019E Gas Hedging Gain/Loss Projections

23

Note: Forward market prices, hedged volumes, and hedge prices are as of 4/11/2019. Anticipated hedging activity is not included in projections.

(1) January through April prices are settled.

(1)

▪ In addition to NYMEX and basis financial

hedges, CNX has physical fixed basis sales and

physical fixed price sales with customers

▪ CY 2019E physical fixed basis sales and

physical fixed price sales: 128.9 Bcf

▪ Physical sales provide additional basis hedge

- Flows through gas sales in financials

Non-GAAP Reconciliation

24

Source: Company filings.

(1) Stand-alone includes both CNX’s E&P and Unallocated segments.

Three Months Ended

March 31,

2019 2019 2019

($ in thousands)Stand-alone

(1) MidstreamTotal

Company

Net (Loss) Income ($97,235) $32,584 ($64,651)

Interest Expense 28,432 7,339 35,771

Interest Income (722) - (722)

Income Tax Benefit (11,559) - (11,559)

Earnings Before Interest & Taxes (EBIT) (81,084) 39,923 (41,161)

Depreciation, Depletion & Amortization 117,075 8,086 125,161

Exploration Expense 3,258 - 3,258

Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX) $39,249 $48,009 $87,258

Adjustments:

Unrealized Loss on Commodity Derivative Instruments 153,994 - 153,994

(Gain) Loss on Certain Asset Sales and Abandonments (3,665) 7,229 3,564

Loss on Debt Extinguishment 7,537 - 7,537

Stock-Based Compensation 10,291 612 10,903

Shaw Event 4,305 - 4,305

Total Pre-tax Adjustments $172,462 $7,841 $180,303

Adjusted EBITDAX Consolidated $211,711 $55,850 $267,561

Midstream Distributions 12,145 N/A N/A

Stand-alone EBITDAX $223,856 N/A N/A


25



Three Months Ended

March 31,

2018 2018 2018


(1) MidstreamTotal

Company

Net Income $510,012 $35,534 $545,546



Income Tax Expense 213,694 - 213,694

Earnings Before Interest & Taxes (EBIT) 759,692 38,023 797,715




Adjustments:

Unrealized Gain on Commodity Derivative Instruments (52,078) - (52,078)

Gain on Certain Asset Sales (4,750) (4,737) (9,487)

Gain on Previously Held Equity Interest (623,663) - (623,663)

Severance Expense 749 65 814

Put Option Fair Value - Reversal from Prior Year (3,500) - (3,500)

Other Transaction Fees 1,149 - 1,149


Stock-Based Compensation 4,331 579 4,910

Total Pre-tax Adjustments ($662,127) ($4,093) ($666,220)

Adjusted EBITDAX Consolidated $215,811 $42,731 $258,542




26



Twelve Months Ended

March 31,

2019 2019 2019


(1) MidstreamTotal

Company

Net Income $142,068 $130,846 $272,914



Income Tax Benefit (9,696) - (9,696)

Earnings Before Interest & Taxes (EBIT) 246,299 159,310 405,609




Adjustments:

Unrealized Loss on Commodity Derivative Instruments 166,565 - 166,565

Settlement Expense 2,000 - 2,000

(Gain) Loss on Certain Asset Sales and Abandonments (134,418) 7,229 (127,189)

Severance Expense 715 - 715

Stock-Based Compensation 24,890 2,445 27,335


Impairment of Other Intangible Assets 18,650 - 18,650

Shaw Event 4,305 - 4,305

Total Pre-tax Adjustments $128,727 $9,674 $138,401

Adjusted EBITDAX Consolidated $850,295 $200,543 $1,050,838




27



(2) MLP cash flow from operations and CNX Gathering calculated using same percentage mix of gross adjusted EBITDA and adjusted EBITDA net to the MLP, which in Q1 2019 was 97.5%

and 2.5%, respectively. Consolidated cash flow from operations for CNX Midstream for Q1 2019 was $49.9 million.

Three Months Ended

March 31,

2019 2018 2019 2018


(1)Stand-alone

(1) Total

Company

Total

Company

Net (Loss) Income from EBITDAX Reconciliation ($97,235) $510,012 ($64,651) $545,546

Adjustments

Total Pre-tax Adjustments from EBITDAX Reconciliation 172,462 (662,127) 180,303 (666,220)

Tax Effect of Adjustments (46,810) 179,569 (48,899) 180,679

Adjusted Net Income $28,417 $27,454 $66,753 $60,005

Cash from Operations and Capital Expenditures by Segment

($ in millions)

Q1 2019

E&P

Standalone +

CNX

Gathering(2)

= CNX + MLP(2)

=

Total

Consolidated

Cash from Operations $258.7 $1.2 $260.0 $48.7 $308.7

Capital Expenditures $220.6 $2.7 $223.3 $75.9 $299.1


28

($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019

Average Sales Price - Total Company 2.85$ 2.47$ 2.50$ $ 2.80 3.00$ 2.87$ 2.92$ $ 3.09 2.97$

Lease Operating Expense 0.23$ 0.23$ 0.22$ 0.21$ 0.28$ 0.21$ 0.14$ 0.12$ 0.14$

Transportation, Gathering and Compression 0.99$ 0.94$ 0.98$ 0.87$ 0.86$ 0.82$ 0.84$ 0.82$ 0.92$

Production, Ad Valoren, and Other Fees 0.09$ 0.05$ 0.06$ 0.08$ 0.07$ 0.06$ 0.06$ 0.06$ 0.05$

Depreciation, Depletion and Amortization 1.01$ 0.98$ 1.00$ 1.01$ 0.89$ 0.91$ 0.93$ 0.89$ 0.88$

Total Production Costs 2.32$ 2.20$ 2.26$ 2.17$ 2.10$ 2.00$ 1.97$ 1.89$ 1.99$

Less: Depreciation, Depletion and Amortization 1.01$ 0.98$ 1.00$ 1.01$ 0.89$ 0.91$ 0.93$ 0.89$ 0.88$

Total Cash Production Costs 1.31$ 1.22$ 1.26$ 1.16$ 1.21$ 1.09$ 1.04$ 1.00$ 1.11$

Operating Cash Margin 1.54$ 1.25$ 1.24$ 1.64$ 1.79$ 1.78$ 1.88$ 2.09$ 1.86$

Earnings Results - CNX Resources...

Documents

Transcript of Earnings Results - CNX Resources...