Earnings Results Second Quarter 2018 August 2, 2018 Cautionary - - PowerPoint PPT Presentation

Earnings Results

Second Quarter 2018

August 2, 2018

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

• n 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, 2017 filed with the SEC, as supplemented by our quarterly reports on Form 10-Q. Those risk factors discuss, among

• ther matters, pricing volatility or pricing decline for natural gas and NGLs; our operational relationship with other parties, including midstream facilities; operational risks relating to pipeline

systems, drilling natural gas wells, 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

• pportunities; 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 and EBITDAX for fiscal or quarterly periods in 2018-2022, for CNX or CNXM, CNX Resources 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 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. 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

Q2 2018 EXPECTATION STRATEGIC INITIATIVE Ohio Utica JV Sale

▪ Announced sale of OH Utica JV assets for $400

million will bring total asset sales to approximately $765 YTD and further streamline the CNX portfolio

▪ Top-tier balance sheet and focused asset portfolio

creates platform for all future NAV accretive capital allocation decisions

Balance Sheet & Leverage Ratio

▪ Debt repayment and EBITDAX growth driving

potential leverage ratio well below stated 2.5x net debt/EBITDAX target by year-end

▪ Optionality exists to deploy balance sheet capacity in

highest return opportunities in development activity, share repurchases, or bolt-on acquisitions

Share Repurchases

▪ Repurchased 5.7 million shares from beginning of the

quarter through July 17, 2018; total of 17.9 million shares since the program was announced or an 8% reduction of shares outstanding

▪ Approximately $170 million remaining on repurchase

authorization that was recently extended through the end of 2018

Production and Outlook

▪ Q2 2018 production saw modest decline on just three

TILs in the quarter; prolific wells from 1Q18 bolstered total production

▪ 2018E TIL activity peaks in late Q3 2018 driving

expected volume ramp in Q4 2018; reaffirming FY2018 production guidance of 490-515 Bcfe

EBITDAX and Capital Guidance

▪ Increasing FY2018 attributable EBITDAX guidance to

$835-$860 million from $810-$835 million; increasing FY2018 E&P capital expenditure guidance to $900- $950 million from $790-$915 million

▪ Will continue to make all capital allocation decisions

• n a strict rate of return basis and look for
• pportunities to increase efficiencies

SWPA Utica and Stacked Pay

▪ Richhill 11E well (TIL in March 2018) continues to

flow above guided type curve supporting plans for stacked pay and blending strategy in the area

▪ Learnings from Richhill 11E are already being applied

to the design of the next SWPA deep Utica well expected TIL mid-2019

Sale of Ohio JV Assets Pulls Value Forward and Narrows Focus

4

OH Joint Venture Assets to be Sold for $800 Million Gross

▪ Net proceeds to CNX of approximately $400 million

• 50 net producing wells with an average net revenue interest ("NRI")
• f 48%
• Five 50% working interest wells the company recently completed

and turned-in-line

• Two 50% working interest wells for which the company has drilled

the top hole

• Approximately 26,000 net undeveloped acres

▪ Acreage was not in CNX five-year development plan ▪ Transaction expected to close in Q3 2018

Total Asset Sales YTD of Approximately $765 Million

▪ OH JV transaction in conjunction with Q1 2018 asset sales (Shirley- Penns drop, SOG, and scattered acreage) total more than $765 million in cash proceeds ▪ Cash being deployed to pay down debt, continue share repurchases, invest in drilling and completion activity, and take advantage of bolt-on acquisitions when opportunities arise

230.1 213.1 50 100 150 200 250 S/O 3Q17E Repurchased 4Q17 Repurchased 1Q18 Repurchased 2Q18 Repurchased 7/1-7/17 S/O 7/17/2018

Shares (millions)

Balance Sheet and Hedge Book Drive Capacity to Retire Shares

5

(1) Includes current portion. (2) Calculated by taking an average minority interest percentage of 63.91%. (3) For illustrative purposes; pro forma net debt includes additional $360 million transaction proceeds ($40 million deposit received in Q2 2018).

E&P Midstream

Net Debt Attributable to CNX Shareholders

$ in millions

June 30, 2018

Total

Total Debt (GAAP)(1) $1,950.4 $404.1 $2,354.5 Less: Cash and Cash Equivalents $48.6 $6.2 $54.8 Net Debt (Non-GAAP) $1,901.8 $397.9 $2,299.7 Less: Net Debt Attributable to Noncontrolling Interest(2)

• $254.3

$254.3 Net Debt Attributable to CNX Resources Shareholders $1,901.8 $143.6 $2,045.4

In Q2 2018, CNX redeemed ~$300 million of 8% notes due 2023 for a net interest savings of approximately $14 million per year for five years

2Q18 Net Debt / Guided 2018E EBITDAX

2.4x

Pro Forma 2Q2018 Net Debt(3) / Guided 2018E EBITDAX

2.0x

Shares Repurchased Since Program Announced ▪ Approximately $170 million remaining on outstanding authorization that was recently extended through YE2018 ▪ Repurchases will continue to be opportunistic and evaluated against other capital allocation decisions including investment in development activity, debt repayment, and bolt-on acquisitions

Q2 2018 Results

6

Note: The terms “adjusted net income attributable to CNX shareholders”, “adjusted EBITDAX attributable to CNX shareholders”, and “adjusted EBITDAX from continuing

• perations" are non-GAAP financial measures, which are reconciled to the GAAP net income below.

(1) See non-GAAP reconciliation table below.

Adjusted EBITDAX attributable to CNX shareholders increased

133%

compared to Q2 2017

Net Income and Adjusted EBITDAX ▪ Net income attributable to CNX shareholders of $42 million in the 2018 second quarter

• r $0.19 per diluted share; adjusted net income attributable to CNX shareholders of

$70 million, or $0.33 per diluted share(1); adjusted net income excludes the following pre-tax items:

• $9 million unrealized gain on commodity derivative instruments
• $23 million loss on debt extinguishment
• $19 impairment on customer relationship related to midstream GP acquisition

▪ Adjusted EBITDAX attributable to CNX shareholders in the second quarter of $204 million(1); on a consolidated basis, adjusted EBITDAX from continuing operations was $231 million(1) in the second quarter

Q2 2018 Summary ($ in millions, except per share data) 2Q 2018 2Q 2017 Y/Y Change 2Q 2018 1Q 2018 Q/Q Change Consolidated Adjusted Net Income / (Loss)(1) $90 $19 $71 $90 $60 $30 Adjusted Earnings / (Loss) Per Share $0.42 $0.08 $0.34 $0.42 $0.19 $0.23 Revenue and Other Income from Continuing Operations $402 $371 $31 $402 $496 ($94) Consolidated Adjusted EBITDAX(1) $231 $87 $144 $231 $259 ($28)

7

“Attributable Share” Reconciled to Consolidated Results

(1) CNX's unallocated expenses include other expense, gain on sale of assets, loss on debt extinguishment, and income taxes. (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 as of Q2 2018 was 95.5% and 4.5%, respectively. Consolidated cash flow from operations for CNX Midstream for Q2 2018 was $53.7 million.

Cash from Operations and Capital Expenditures

CNX LP ownership 34.09% GP ownership 2.00% Total CNX ownership 36.09% NCI 63.91% 100.00%

Attributable Portion Calculation

Attributable to CNX Shareholders

+

Noncontrolling Interest = Consolidated Inside the MLP Outside the MLP 63.91% of CNXM Q2 2018 E&P Standalone + Attributable to CNXM LP & GP + Unallocated(1) + CNX Gathering = Total "Attributable to CNX Shareholders" + Attributable to Noncontrolling Interest = Total Consolidated

• Adj. EBITDAX

$184.5 $10.8 $2.5

$6.1 $203.9 $26.7 $230.6

Total Debt $1,950.4 $145.8

• $2,096.2

$258.3 $2,354.5

Total Cash $48.6 $2.2

$50.8 $4.0 $54.8

Net Debt $1,901.8 $143.6

$2,045.4

$254.3

$2,299.7 ($ in millions)

Q2 2018 E&P Standalone + CNX Gathering(2) = CNX + MLP(2) = Total Consolidated Cash from Operations $137.9 $2.4 $140.3 $51.3 $191.6 Capital Expenditures $238.6 $1.0 $239.6 $24.6 $264.2

($ in millions)

370.9 326.2 224.2 194.1 160.0 27.7 7.5 10.7 7.7 10.4 50 100 150 200 250 300 350 400 2018 2019 2020 2021 2022 2023 Gas Volumes Hedged (Bcf) NYMEX Only Hedges Exposed to Basis NYMEX + Basis (2)

Marketing: Natural Gas Hedging and Basis Protection

8

▪ Systematically layering in hedges

• ut to 2023 to protect margins on

proved developed production and a portion of PUDs (capex) ▪ Locking-in revenue and de-risking capital decisions by matching NYMEX and basis hedge volumes ▪ Protecting from in-basin blowout through regional basis hedges ▪ Approximately 80% of total 2018E gas volumes hedged(3) ▪ NYMEX hedges added during Q2: 15.6 Bcf (for 2023) ▪ Basis hedges added during Q2: 90.3 Bcf (2019, 2020, 2022, and 2023)

(1) Hedge positions as of 7/11/2018. Q3 2018, 2018, and 2021 exclude 2.3 Bcf, 14.1 Bcf, and 3.9 Bcf 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) Based on midpoint of total gas production guidance of 450-475 Bcf in 2018E.

(2)

Hedge Volumes and Pricing Q3 2018 2018 2019 2020 2021 2022 2023 NYMEX Hedges Volumes (Bcf) 88.8 353.8 320.9 223.9 172.8 153.9 38.1 Average Prices ($/Mcf) $3.19 $3.18 $3.05 $3.09 $3.02 $3.06 $2.85 Physical Fixed Price Sales Volumes (Bcf) 4.3 17.1 12.8 11.0 21.3 13.8

• Average Prices ($/Mcf)

$2.65 $2.64 $2.51 $2.44 $2.47 $2.54

• Total Volumes Hedged (Bcf)(1)

93.1 370.9 333.7 234.9 194.1 167.7 38.1 NYMEX + Basis (fully-covered volumes)(2) Volumes (Bcf) 93.1 370.9 326.2 224.2 194.1 160.0 27.7 Average Prices ($/Mcf) $2.80 $2.79 $2.71 $2.71 $2.55 $2.48 $2.35 NYMEX Hedges Exposed to Basis Volumes (Bcf)

• 7.5

10.7

• 7.7

10.4 Average Prices ($/Mcf)

• $3.05

$3.09

• $3.06

$2.85 Total Volumes Hedged (Bcf)(1) 93.1 370.9 333.7 234.9 194.1 167.7 38.1

Financial Guidance

9

PREVIOUS (6/29/2018) UPDATE (8/2/2018) 2018E 2018E

Revenue and Other Operating Income E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 450-475 450-475 NGLs (MBbls) 6,000 6,000 Condensate (MBbls) 475-500 475-500 Total Production (Bcfe) 490-515 490-515 % Liquids 7%-8% 7%-8% Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40) ($0.30)-($0.40) NGL Realized Price ($/Bbl) $23.00-$24.00 $29.00-$30.00 Condensate Realized Price % of WTI 70% 70% Realized Hedging Gain/(Loss) ($ in millions) (1) $85-$90 $5-$10 Other Operating Income (3rd party water income and resold FT) ($ in millions) $15-$20 $20-$25 CNXM 3rd Party Gathering Revenue $80-$85 $70-$75 Costs Average per unit operating expenses ($/Mcfe): Lease Operating Expense $0.15-$0.18 $0.20-$0.21 Production, Ad Valorem, and Other Fees $0.06-$0.08 $0.06-$0.08 Transportation, Gathering and Compression $0.80-$0.85 $0.60-$0.65 $0.80-$0.85 $0.60-$0.65 Total Cash Production and Gathering Costs $1.01-$1.11 $0.81-$0.91 $1.06-$1.14 $0.86-$0.94 ($ in millions) Selling, General, and Administrative Costs(2) $85-$95 $95-$110 $85-$95 $95-$110 Exploration Expense $10-$15 $10-$15 Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70 $65-$70 Other Non-Operating Expense (Income) $15-$20 $0 Total Capital Expenditures $790-$915 $875-$1,005 $900-$950 $1,000-$1,060 EBITDAX Attributable to CNX $810-$835 $835-$860 $945-$970

CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected net 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) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 7/3/2018. Anticipated hedging activity is not included in projections. (2) Excludes stock-based compensation.

Adjusted 6/29/18 following sale

• f OH Utica JV assets, which

were expected to produce 10 Bcfe after closing expected in Q3 2018

Unutilized FT and Processing Fees: $50 million Idle Rig Fees: $5 million Royalty income, right of way sales, interest income and ‘other’ all netted against bank fees, other corporate expense, and other land rental expense

Operations: Q2 2018 Results Summary

10

▪ Marcellus Shale costs were $2.17 per Mcfe in Q2 2018, an increase of $0.12 from $2.05 per Mcfe vs. Q2 2017,

• r a 6% increase
• Water disposal costs increased and processing costs

were higher as a result of the Shirley-Pennsboro wells being turned-in-line in second half of 2017 ▪ Utica Shale costs were $1.57 per Mcfe in Q2 2018, a decrease of $0.47 from $2.04 per Mcfe in Q2 2017, or a 23% improvement

• Transportation, gathering and compression

expenses improved as lower cost Monroe Country dry Utica volumes increased ▪ E&P capital expenditures increased in Q2 2018 to $239 million from $216 million spent in Q1 2018

(1) Average sales prices for 2Q2018, 2Q2017, and 1Q2018 include (loss)/gain on commodity derivative instruments (cash settlements) of $0.15, ($0.39), and ($0.14) per Mcf, respectively. (2) Average Costs for 2Q2018, 2Q2017, and 1Q2018 include DD&A of $0.91, $0.98, and $0.89 per Mcfe, respectively.

($/Mcfe)

2Q 2018 2Q 2017 Y/Y Change 2Q 2018 1Q 2018 Q/Q Change Average Sales Price(1) $2.87 $2.47 $0.40 $2.87 $3.00 ($0.13) Total Production Costs(2) $2.00 $2.20 ($0.20) $2.00 $2.10 ($0.10) Sales Volumes (Bcfe) 122.6 92.2 30.4 122.6 129.5 (6.9) Sales Volumes by Category (Bcfe) Marcellus 64.7 56.9 7.8 64.7 65.9 (1.2) Utica 42.6 13.8 28.8 42.6 43.5 (0.9) CBM 14.8 16.5 (1.7) 14.8 15.9 (1.1) Other 0.5 5.0 (4.5) 0.5 4.2 (3.7)

Virginia CBM Cost Reduction Efforts Driving Increase in Cash Flow ▪ Total Operating Costs/Mcfe declined 6% Q/Q and 10% Y/Y as a renewed effort to drive efficiencies took hold in the first half of the year

• Updated work scheduling process with data driven analytics for

production, operations scheduling, and decision making

• Right-sized company and contractor man power count

▪ Initiatives have improved the rates of return across the field ▪ Asset continues to generate meaningful cash flow with limited capital investment

Operations: “Evolution” Electric Frac Deal to Drive Efficiencies

11

All-Electric, Natural Gas-Powered, Disruptive Frac Technology ▪ Three-year deal is first long-term engagement in Appalachian basin; expected in-service 1H19

• Long-term visibility on completions costs
• Potential for further efficiencies over time

Conventional Pad Footprint Evolution Pad Footprint Operational and Health, Safety, and Environmental Benefits Economic Impact Estimated 30% increase in frac efficiency Higher horsepower = more rate Advanced AC motors = less downtime Approximate 80% reduction in fuel costs Diesel replaced with abundant CNX field gas

Eight pump, 56,000 HP fracturing fleet = 23-25 conventional pumps Smaller pad result of fewer pumps and state of the art equipment 50% less personnel on location Equipment operated remotely, reducing personnel exposure Automated and centralized controls with predictive analytics 60% reduction in footprint More than 25% reduction in noise from frac fleet alone Lower emission natural gas compared to conventional diesel Less truck traffic Elimination of dangerous hot fueling

Operations: Q2 2018 Activity and Updated 2018 Development Plan

12

(1) Measured in lateral feet from perforation to perforation. (2) 50% working interest. Sale of OH Utica JV assets expected to close in Q3 2018, at which point future flowing production from five TILs will transfer to buyer.

Q2 2018 YTD 2018 2018E

($ in millions) TD FRAC TIL Average Lateral Length(1) Rigs at Period End TD FRAC TIL TD FRAC TIL SWPA Central Marcellus 10 13 3 8,291 1 27 16 9 61 42 41 Utica

• 1

1 4 1 1 WV Shirley-Penns Marcellus 3

• 1

3

• 5

5 5 Utica

• CPA South

Utica

• 1
• 1

1 4 5 2 OH Dry Utica 3

• 1

5

• 6

8 8 14 OH Wet(2)

• 5
• 5
• 5

5 Total 16 18 3 4 35 23 17 82 66 68

▪ Rig is designed to meet the demands of the deep dry Utica and is under a new contract with lower daily rates than existing rigs in portfolio

• Increased drilling efficiencies expected to help lower

costs and demonstrate repeatability of economic deep dry Utica wells in CPA Fourth Rig Came Online Late-Q2 2018 Marking Return to CPA Deep Dry Utica ▪ Now drilling first of three wells on Shaw pad near Aikens and Gaut (Mamont area) for expected TIL early 2019

• Salina Salt section drilled without issue and at roughly

half the time and cost of the Gaut 4I to this point ▪ Another rig is currently drilling a well on the Bell Point pad in Mamont for expected TIL in Q4 2018

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 100 200 300 400 500 600 700 Drawdown Sandface Pressure (%) Cumulative Gas (MMcf) Producing Days

Peer Well Average Volume RHL11 Volume Peer Well Average Daily Drawdown % RHL11 Daily Drawdown %

• 5,000

10,000 15,000 20,000 25,000 30,000 35,000 100 200 300 400 500 600 700 Mcf/d

Days

RHL11 RHL11 Forecast Peer Well Average CNX SWPA Central Utica Guided TC

Operations: SWPA Utica RHL11E Early Results Set the Stage

(1) Peer well average comprised of six deep dry Utica wells in SWPA and WV. Excludes Scotts Run well. Actual daily production normalized to 7,000’ lateral.

13

RHL11E Forecast vs. Peer Well Average and Guided Type Curve(1)

RHL11E currently flowing at 3.5 Bcfe/1000’ EUR, or better than the 3.2 Bcfe/1000’ guided type curve for the SWPA Central type curve region This level of performance sets the stage for the “stacked pay factory” and CNX’s blending strategy Daily Pressure Drawdown Percent vs. Cumulative Production Pressures observed to-date and managed pressure drawdown driving confidence in RHL 11E ~12 month flat period RHL11E production volumes at current drawdown levels surpass the average peer production at much steeper daily average drawdown

Operations: De-risking Drill Plan with Customized Well Layouts

14

Well Layouts Before Seismic Data Well Layouts After Seismic Data High capital and production risk based

• n formation

complexity at the well heels Adjusted layouts allow for higher in-zone placement and de-risk capital and production impacts from formation complexity

Appendix

Marketing: Highlights and Liquids Realizations

16

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

Marketing Highlights ▪ Directly-marketed ethane volumes were 177,200 barrels in Q2 and, on an equivalent basis, yielded a $1.23 per MMBtu premium over CNX Resources’ residue natural gas

• alternative. Ethane sales volumes were limited in the

quarter due primarily to Mariner East delivery constraints. ▪ $0.17 per Mcfe uplift(1) from liquids for total average realization of $2.87 per Mcfe in Q2 2018

2018 2017 Q2 Q2 NYMEX Natural Gas ($/MMBtu) $2.80 $3.18 Average Differential (0.40) (0.52) BTU Conversion (MMBtu/Mcf)* 0.15 0.15 Gain (Loss) on Commodity Derivative Instruments-Cash Settlement 0.15 (0.39) Realized Gas Price per Mcf $2.70 $2.42 * Conversion factor 1.06 1.05

Natural Gas Price Reconciliation Natural Gas Liquids, Oil and Condensate ▪ Q2 2018 liquids sold: 9.0 Bcfe ▪ Total weighted average price of all liquids increased 70% to $30.28 per Bbl in Q2 2018 from $17.81 per Bbl in Q2 2017 and increased 4% from $29.15 per Bbl in Q1 2018 ▪ In Q2, liquids comprised approximately 7% of 2018 production volumes and 11% of total revenue and other operating income Average Price Realization ($ per Bbl)

2018 2017 Q2 Q1 Q2 Q1 NGLs $28.38 $27.48 $15.96 $29.16 Oil $58.32 $56.46 $48.18 $44.40 Condensate $56.82 $49.32 $34.14 $33.84

Marketing: Natural Gas Hedging – Gain/Loss Projections

17

Note: Forward market prices, hedged volumes, and hedge prices are as of 7/11/2018. Anticipated hedging activity is not included in projections. (1) July prices are settled.

Q3 2018 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's) ($/MMBtu) NYMEX 95,220 $2.98 $2.87 $0.10 $9,877 Basis: DOM South (DOM) 7,360 ($0.59) ($0.64) $0.05 $350 TCO Pool (TCO) 9,200 ($0.27) ($0.20) ($0.07) ($642) Michcon (NMC) 3,680 ($0.03) ($0.14) $0.10 $382 TETCO ELA (TEB) 1,380 ($0.09) ($0.09) $0.00 $4 TETCO M3 (TMT) 4,600 ($0.12) ($0.52) $0.41 $1,868 TETCO M2 (BM2) 48,070 ($0.60) ($0.66) $0.06 $2,930 Total Financial Basis Hedges 74,290 $4,892 Total Projected Realized Gain $14,769

Non-GAAP Reconciliation

18

Source: Company filings. (1) CNX's unallocated expenses include other expense, gain on sale of assets, loss on debt extinguishment and income taxes. (2) Adjusted EBITDA Attributable to Noncontrolling Interest for the three months ended June 30, 2018 is Net Income Attributable to Noncontrolling interest of $19,380 plus Depreciation, Depletion and Amortization of $3,078, plus Interest Expense of $3,835, plus Stock-based compensation of $416. Calculated by taking an average noncontrolling interest percentage of 63.91%. Adjusted net income for the three months ended June 30, 2018 is calculated as GAAP net income of $61,394 plus total pre-tax adjustments from the above table of $39,054, less the associated tax expense of $10,592 equals adjusted net income of $89,856. Adjusted net income for the three months ended June 30, 2017 is calculated as GAAP net income of $169,510 less total pre-tax adjustments from the above table of $238,508, plus the associated tax expense of $88,332 equals adjusted net income of $19,334. Adjusted net income attributable to CNX Resources shareholders for the three months ended June 30, 2018 is calculated as GAAP net income attributable to CNX shareholders of $42,014 plus total pre-tax adjustments from the above table of $39,054, less the associated tax expense of $10,592 equals adjusted net income attributable to CNX shareholders of $70,476. Adjusted net income attributable to CNX Resources shareholders for the three months ended June 30, 2017 is calculated as GAAP net income attributable to CNX shareholders of $169,510 less total pre-tax adjustments from the above table of $238,508, plus the associated tax expense of $88,332 equals adjusted net income attributable to CNX shareholders of $19,334.

Three Months Ended June 30, 2018 2018 2018 2018 2017 ($ in thousands) E&P Division Midstream Unallocated(1) Total Company Total Company Net Income (Loss) $42,124 $27,780 ($8,510) $61,394 $169,510 Less: Income from Discontinued Operations

• (47,703)

Add: Interest Expense 31,320 7,118

• 38,438

40,683 Less: Interest Income

• (6,077)

Add: Income Taxes (Benefit)

• (31,102)

(31,102) 57,958 Earnings/(Loss) Before Interest & Taxes (EBIT) 73,444 34,898 (39,612) 68,730 214,371 Add: Depreciation, Depletion & Amortization 111,125 7,962

• 119,087

91,640 Add: Exploration Expense 3,699

• 3,699

19,717 Earnings/(Loss) Before Interest, Taxes, DD&A, and Exploration (EBITDAX) from Continuing Operations $188,268 $42,860 ($39,612) $191,516 $325,728 Adjustments: Unrealized Gain on Commodity Derivative Instruments (8,975)

• (8,975)

(116,073) Gain on Certain Asset Sales

• (126,707)

Severance Expense 257

• 257

73 Loss on Debt Extinguishment

• 23,413

23,413 36 Stock-Based Compensation 5,018 691

• 5,709

4,163 Impairment of Other Intangible Assets

• 18,650

18,650

• Total Pre-tax Adjustments

($3,700) $691 $42,063 $39,054 ($238,508) Adjusted EBITDAX from Continuing Operations $184,568 $43,551 $2,451 $230,570 $87,220 Less: Adjusted EBITDA Attributable to Noncontrolling Interest(2)

• 26,711
• 26,711
• Adjusted EBITDAX Attributable to CNX Resources Shareholders

$184,568 $16,840 $2,451 $203,859 $87,220