Earnings Results Second Quarter 2018 August 2, 2018
Cautionary Language 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, 2017 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; 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 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 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. 2
Executive Summary STRATEGIC INITIATIVE Q2 2018 EXPECTATION Ohio Utica JV Sale Balance Sheet & Leverage Ratio Share Repurchases Production and Outlook EBITDAX and Capital Guidance SWPA Utica and Stacked Pay 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 Debt repayment and EBITDAX growth driving potential leverage ratio well below stated 2.5x net debt/ebitdax target by year-end 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 Q2 2018 production saw modest decline on just three TILs in the quarter; prolific wells from 1Q18 bolstered total production 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 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 Top-tier balance sheet and focused asset portfolio creates platform for all future NAV accretive capital allocation decisions Optionality exists to deploy balance sheet capacity in highest return opportunities in development activity, share repurchases, or bolt-on acquisitions Approximately $170 million remaining on repurchase authorization that was recently extended through the end of 2018 2018E TIL activity peaks in late Q3 2018 driving expected volume ramp in Q4 2018; reaffirming FY2018 production guidance of 490-515 Bcfe Will continue to make all capital allocation decisions on a strict rate of return basis and look for opportunities to increase efficiencies Learnings from Richhill 11E are already being applied to the design of the next SWPA deep Utica well expected TIL mid-2019 3
Sale of Ohio JV Assets Pulls Value Forward and Narrows Focus 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") of 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 4
Shares (millions) Balance Sheet and Hedge Book Drive Capacity to Retire Shares Net Debt Attributable to CNX Shareholders Shares Repurchased Since Program Announced June 30, 2018 250 E&P Midstream Total 200 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 $ in millions $1,901.8 $143.6 $2,045.4 2Q18 Net Debt / Guided 2018E EBITDAX 2.4x Pro Forma 2Q2018 Net Debt (3) / Guided 2018E EBITDAX 2.0x 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 150 100 50 0 230.1 S/O 3Q17E Repurchased 4Q17 Repurchased 1Q18 Repurchased 2Q18 Repurchased 7/1-7/17 213.1 S/O 7/17/2018 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 (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). 5
Q2 2018 Results Net Income and Adjusted EBITDAX Net income attributable to CNX shareholders of $42 million in the 2018 second quarter or $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 $231 million (1) in the second quarter Adjusted EBITDAX attributable to CNX shareholders increased 133% compared to Q2 2017 Q2 2018 Summary ($ 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) Note: The terms adjusted net income attributable to CNX shareholders, adjusted EBITDAX attributable to CNX shareholders, and adjusted EBITDAX from continuing operations" are non-gaap financial measures, which are reconciled to the GAAP net income below. (1) See non-gaap reconciliation table below. 6
Attributable Share Reconciled to Consolidated Results Q2 2018 E&P Standalone + Attributable to CNX Shareholders + Noncontrolling Interest = Consolidated Inside the MLP Outside the MLP 63.91% of CNXM 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 Cash from Operations and Capital Expenditures 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) Attributable Portion Calculation CNX LP ownership 34.09% GP ownership 2.00% Total CNX ownership 36.09% NCI 63.91% 100.00% (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 $53.7 million. 7
Gas Volumes Hedged (Bcf) Marketing: Natural Gas Hedging and Basis Protection 400 350 300 250 200 150 100 50 0 370.9 7.5 326.2 10.7 224.2 194.1 7.7 160.0 2018 2019 2020 2021 2022 2023 (2) NYMEX Only Hedges Exposed to Basis NYMEX + Basis Hedge Volumes and Pricing Q3 2018 2018 2019 2020 2021 2022 2023 NYMEX Hedges Volumes (Bcf) 88.8 353.8 320.9 223.9 172.8 153.9 38.1 Average Prices ($/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 $2.85 Total Volumes Hedged (Bcf) (1) 93.1 370.9 333.7 234.9 194.1 167.7 38.1 10.4 27.7 Systematically layering in hedges out to 2023 to protect margins on proved developed production and a portion of PUDs (capex) Locking-in revenue and de-risking capital decisions by matching NYMEX and basis hedge volumes Protecting from in-basin blowout through regional basis hedges Approximately 80% of total 2018E gas volumes hedged (3) NYMEX hedges added during Q2: 15.6 Bcf (for 2023) Basis hedges added during Q2: 90.3 Bcf (2019, 2020, 2022, and 2023) (1) Hedge positions as of 7/11/2018. Q3 2018, 2018, and 2021 exclude 2.3 Bcf, 14.1 Bcf, and 3.9 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total gas production guidance of 450-475 Bcf in 2018E. 8
Financial Guidance PREVIOUS (6/29/2018) UPDATE (8/2/2018) 2018E 2018E Revenue and Other Operating Income E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 450-475 450-475 NGLs (MBbls) 6,000 6,000 Condensate (MBbls) 475-500 475-500 Total Production (Bcfe) 490-515 490-515 % Liquids 7%-8% 7%-8% Natural Gas Basis Differential to NYMEX ($/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-$10 Other Operating Income (3 rd party water income and resold FT) ($ 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 Adjusted 6/29/18 following sale of 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: $5 million Royalty income, right of way sales, interest income and other all netted against bank fees, other corporate expense, and other land rental expense CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected net income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. (1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 7/3/2018. Anticipated hedging activity is not included in projections. (2) Excludes stock-based compensation. 9
Operations: Q2 2018 Results Summary ($/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) (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. 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 Marcellus Shale costs were $2.17 per Mcfe in Q2 2018, an increase of $0.12 from $2.05 per Mcfe vs. Q2 2017, or 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 $216 million spent in Q1 2018 10
Economic Impact Operational and Health, Safety, and Environmental Benefits Operations: Evolution Electric Frac Deal to Drive Efficiencies All-Electric, Natural Gas-Powered, Disruptive Frac Technology Three-year deal is first long-term engagement in Appalachian basin; expected in-service 1H19 - Long-term visibility on completions costs - Potential for further efficiencies over time Eight pump, 56,000 HP fracturing fleet = 23-25 conventional pumps Smaller pad result of fewer pumps and state of the art equipment 50% less personnel on location Equipment operated remotely, reducing personnel exposure Conventional Pad Footprint Estimated 30% increase in frac efficiency Higher horsepower = more rate Advanced AC motors = less downtime Automated and centralized controls with predictive analytics 60% reduction in footprint Evolution Pad Footprint Approximate 80% reduction in fuel costs Diesel replaced with abundant CNX field gas More than 25% reduction in noise from frac fleet alone Lower emission natural gas compared to conventional diesel Less truck traffic Elimination of dangerous hot fueling 11
Operations: Q2 2018 Activity and Updated 2018 Development Plan ($ in millions) TD FRAC TIL SWPA Central Q2 2018 YTD 2018 2018E Average Lateral Length (1) Rigs at Period End TD FRAC TIL TD FRAC TIL Marcellus 10 13 3 8,291 1 27 16 9 61 42 41 Utica - - - - - - 1 1 4 1 1 WV Marcellus 3 - - - 1 3 - - 5 5 5 Shirley-Penns Utica - - - - - - - - - - - CPA South Utica - - - - 1-1 1 4 5 2 OH Dry 3 - - - 1 5-6 8 8 14 Utica OH Wet (2) - 5 - - - - 5 - - 5 5 Total 16 18 3 4 35 23 17 82 66 68 Fourth Rig Came Online Late-Q2 2018 Marking Return to CPA Deep Dry Utica 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 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 (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. 12
Cumulative Gas (MMcf) Drawdown Sandface Pressure (%) Mcf/d Operations: SWPA Utica RHL11E Early Results Set the Stage RHL11E Forecast vs. Peer Well Average and Guided Type Curve (1) 35,000 30,000 25,000 20,000 15,000 10,000 5,000-5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 0 100 200 300 400 500 600 700 Days RHL11 Peer Well Average 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 0 100 200 300 400 500 600 700 Producing Days Peer Well Average Volume RHL11 Forecast CNX SWPA Central Utica Guided TC Daily Pressure Drawdown Percent vs. Cumulative Production RHL11 Volume Peer Well Average Daily Drawdown % RHL11 Daily Drawdown % 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 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 (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
Operations: De-risking Drill Plan with Customized Well Layouts Well Layouts Before Seismic Data Well Layouts After Seismic Data High capital and production risk based on formation complexity at the well heels Adjusted layouts allow for higher in-zone placement and de-risk capital and production impacts from formation complexity 14
Appendix
Marketing: Highlights and Liquids Realizations 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 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 $29.15 per Bbl in Q1 2018 In Q2, liquids comprised approximately 7% of 2018 production volumes and 11% of total revenue and other operating income Natural Gas Price Reconciliation 2018 2017 Q2 Q2 NYMEX Natural Gas ($/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 $2.42 * Conversion factor 1.06 1.05 Average Price Realization ($ 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 $33.84 (1) Calculation includes the impact of gas hedging cash settlements. 16
Marketing: Natural Gas Hedging Gain/Loss Projections Q3 2018 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (000 MMBtu) Price Market ($/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 $14,769 Note: Forward market prices, hedged volumes, and hedge prices are as of 7/11/2018. Anticipated hedging activity is not included in projections. (1) July prices are settled. 17
Non-GAAP Reconciliation Three Months Ended June 30, 2018 2018 2018 2018 2017 E&P Division Midstream Unallocated (1) Total Company Total Company ($ in thousands) 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 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. 18