Earnings Results First Quarter 2018 May 3, 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, 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 Operational Execution Stacked Pay Development Q1 2018 Total production in the quarter of 129.5 Bcfe or average of 1.439 Bcfe/d exceeded YE2017 average monthly exit rate of 1.390 Bcfe/d Turned-in-line RHL11E deep dry Utica well with positive early results Share Repurchases Bought back ~$200 million of common stock since Oct. 17 EXPECTATION Reaffirming production guidance of 520-525 Bcfe for FY2018 Transferring completion design and spacing lessons from Monroe County and Green Hill to Richhill stacked pay Approximately $250 million remaining on outstanding repurchase authorization through 3Q18 Debt Repayment Payed down ~$391 million in debt in the period Continue to target steady state 2.5x net debt/ebitdax CNX Midstream Integration and Shirley-Penns Drop SOG and Other Asset Sales Closed GP transaction in early January and rebranded as CNX Midstream; closed Shirley-Pennsboro asset drop for $265 million helping to pay for a large portion of the cost of the GP Sold SOG assets for ~$88 million in cash proceeds; sold an additional ~$14 million in scattered acreage and other miscellaneous assets Fully aligned management teams with a clear development plan and well commitments sets the stage for steady and prolonged distribution growth Further focuses development activity on top-tier Marcellus and Utica assets; reduces legacy liabilities and cash servicing costs to de minimis levels HG Exchange Transaction On May 2, 2018, executed a transaction with HG Energy II; CNX received 11,400 DevCo I Marcellus acres and $5 million in cash in exchange for 95% interest in DevCo II midstream assets and scattered acres in DevCo III; CNXM received additional well commitments from both parties Transaction and revised GGA results in further de-risked 15% distribution growth based on minimum well commitments alone 3
SOG Sale Drives Continued Reduction in Legacy Liabilities Conventional Shallow Oil and Gas (SOG) assets sold in West Virginia and Pennsylvania, including CBM (1) Agreement signed mid-february - Closed on March 30, 2018 SOG Wells Included in Sale ~11,000 wells Cash proceeds of $88 million Buyer assumed liabilities of ~$200 million - Primarily asset retirement obligations Associated annual production of ~20 Bcfe (1) Excludes wells located in the Murray and CONSOL Energy development area. 4
Shares Outstanding (millions) Market Cap ($ in millions) Share Buybacks To-Date and Potential Capacity As of: Q3 2017 End Year-End 2017 As of 4/20/2018 2018E-2022E Buyback Potential Share Reduction S/O: 230.1 million 223.7 million 217.9 million Additional 85+ million share reduction (2) 250 200 ~$110/share with drop proceeds (1) $10,000 $9,000 $8,000 $7,000 Prior to spin (~$100 million): - 6.4 million shares repurchased at a volume weighted average price of $16.08 (3) Since spin (~$100 million): 150 $6,000 $5,000-6.7 million shares repurchased at a volume weighted average price of $14.61 (4) 100 $4,000 $3,000 Approximately $250 million remaining on share repurchase authorization for 2018 50 Potential share count reduction of ~60% by year-end 2022 including additional drop proceeds $2,000 $1,000-2017 2018E 2019E 2020E 2021E 2022E $- Market Cap Shares Outstanding - Including Drop Proceeds Shares Outstanding - No Additional Sales/Drops (1) Stock repurchase price assumes static year-forward EV/EBITDAX multiple of 5.9x on guided adjusted EBITDAX and net debt levels. Market cap estimate includes deployment of ~$1.8 billion related to potential drop proceeds and tax refunds. See CNX Analyst Day materials dated March 13, 2018 for full details. (2) Not including deployment of ~$1.8 billion of potential drop proceeds and tax refunds. (3) Shares repurchased from October-November 2017. Included rights to CEIX share distribution at a ratio of 1 share of CEIX for every 8 shares held of CNX. (4) Shares repurchased as of market close 4/20/2018. 5
Exchange Agreement Expands SWPA Central Marcellus Inventory 500 SWPA Central Marcellus Inventory 2018E-2020E 450 400 Additional Locations from HG Exchange 70 TILs 46 TILs 55 350 TILs 73 300 250 200 150 100 50 Prior Net SWPA Central Marcellus Inventory 391 461 SWPA Central Marcellus locations entering 2018 Additional Locations from HG Exchange 70 Prior Net SWPA Central Marcellus Inventory 217 287 SWPA Central Marcellus locations remaining at YE2020 based on current development schedule Increase in remaining SWPA Central Marcellus locations due to Asset 32% Exchange Agreement 0 Entering 2018 2018 2019 2020 Year End 2020 6
Attributable Share Reconciled to Consolidated Results Q1 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 $208 $13 $8 $8 $236 $22 $259 Total Debt $1,824 $149 -- $1,973 $264 $2,237 Total Cash $77 $2 $79 $4 $82 Net Debt $1,747 $147 $1,894 $260 $2,155 ($ in millions) Q1 2018 E&P Standalone + CNX Gathering (2) = CNX + MLP (2) = Total Consolidated Cash from Operations $217 $6 $223 $36 $259 Capital Expenditure $216 $2 $218 $14 $232 ($ in millions) Cash from Operations and Capital Expenditures 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 Q1 2018 was 85.6% and 14.4%, respectively. Consolidated cash flow from operations for CNX Midstream for Q1 2018 was $42.258 million. 7
Q1 2018 Results Net Income and Adjusted EBITDAX On a GAAP basis, net income attributable to CNX shareholders of $528 million in the 2018 first quarter or $2.35 per diluted share; adjusted net income attributable to CNX shareholders of $42 million, or $0.19 per diluted share (1) ; adjusted net income excludes the following pre-tax items: - $624 million gain on company s previously held equity interest in CNX Gathering in connection with acquisition of 50% of GP - $52 million unrealized gain on commodity derivative instruments - $9 million in gains on certain asset sales Total company adjusted EBITDAX attributable to CNX Shareholders in the first quarter of $236 million; on a consolidated basis, adjusted EBITDAX from continuing operations was $259 million in the first quarter Adjusted EBITDAX attributable to CNX Shareholders increased 90% compared to Q1 2017 Q1 2018 Summary ($ in millions, except per share data) 1Q 2018 1Q 2017 Y/Y Change 1Q 2018 4Q 2017 Q/Q Change Adjusted Net Income / (Loss) Attributable to CNX Shareholders $42 $37 $5 $42 $222 ($180) Adjusted Earnings / (Loss) Per Share $0.19 $0.16 $0.03 $0.19 $0.98 ($0.79) Revenue and Other Income from Continuing Operations $496 $320 $176 $496 $477 $19 Adjusted EBITDAX Attributable to CNX Shareholders $236 $124 $112 $236 $187 $49 Note: The terms adjusted net income attributable to CNX Shareholders, adjusted EBITDA attributable to CNX Shareholders, and adjusted EBITDAX from continuing operations" are non-gaap financial measures, which are reconciled to the GAAP net income below, under the caption Non-GAAP Reconciliation." (1) Income tax effect of Total Pre-tax Adjustments (excluding exploration expense) was ($180,679) for the three months ended March 31, 2018. Adjusted net income attributable to CNX Resources Shareholders for the three months ended March 31, 2018 is calculated as GAAP net income attributable to CNX Shareholders of $527,563 less total pre-tax adjustments of ($666,221), plus the associated tax expense of ($180,679) equals the adjusted net income attributable to CNX Resources Shareholders of $42,021. 8
Balance Sheet and Hedge Book Drive Capacity to Retire Shares March 31, 2018 Net Debt Attributable to CNX Shareholders E&P Midstream Total Total Debt (GAAP) (1) Less: Cash and Cash Equivalents Net Debt (Non-GAAP) Less: Net Debt Attributable to Noncontrolling Interest (2) Net Debt Attributable to CNX Resources Shareholders $ in millions $1,824 $413 $2,237 $77 $6 $83 $1,747 $407 $2,154 - $261 $261 $1,747 $147 $1,894 Target <2.5x net debt / EBITDAX During the quarter, CNX purchased $391 million of its outstanding 5.875% senior notes due in April 2022 (1) Includes current portion. (2) Calculated by taking an average minority interest percentage of 63.91% 9
Gas Volumes Hedged (Bcf) Marketing: Natural Gas Hedging and Basis Protection 400 350 300 250 200 150 100 50 0 374.5 23.0 312.8 29.3 205.6 194.6 56.0 112.0 2018 2019 2020 2021 2022 (2) NYMEX Only Hedges Exposed to Basis NYMEX + Basis Hedge Volumes and Pricing Q2 2018 2018 2019 2020 2021 2022 NYMEX Hedges Volumes (Bcf) 89.5 357.2 323.0 223.9 173.3 154.2 Average Prices ($/Mcf) $3.13 $3.15 $3.03 $3.09 $3.01 $3.05 Physical Fixed Price Sales Volumes (Bcf) 4.3 17.3 12.8 11.0 21.3 13.8 Average Prices ($/Mcf) $2.60 $2.62 $2.49 $2.44 $2.46 $2.54 Total Volumes Hedged (Bcf) (1) 93.8 374.5 335.8 234.9 194.6 168.0 NYMEX + Basis (fully-covered volumes) (2) Volumes (Bcf) 93.8 374.5 312.8 205.6 194.6 112.0 Average Prices ($/Mcf) $2.75 $2.77 $2.68 $2.72 $2.54 $2.49 NYMEX Hedges Exposed to Basis Volumes (Bcf) - - 23.0 29.3-56.0 Average Prices ($/Mcf) - - $3.03 $3.09 - $3.05 Total Volumes Hedged (Bcf) (1) 93.8 374.5 335.8 234.9 194.6 168.0 Systematically layering in hedges out to 2022 to protect margins on proved developed production and a portion of PUDs (capex) Locking-in revenue and derisking capital decisions by matching NYMEX and basis hedge volumes Protecting from in-basin blowout through regional basis hedges Approximately 81% of total 2018E gas volumes hedged (3) NYMEX hedges added during Q1: 167.5 Bcf (2019-2022) Basis hedges added during Q1: 193.2 Bcf (2018-2022) (1) Hedge positions as of 4/23/2018. Q2 2018, 2018, and 2021 exclude 2.3 Bcf, 14.2 Bcf, and 4.0 Bcf of physical basis sales not matched with NYMEX hedges. (2) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements. (3) Based on midpoint of total gas production guidance of 450-475 Bcf in 2018E. 10
Financial Guidance: 2018E 2018E Revenue and Other Operating Income E&P Consolidated Production Volumes: Natural Gas (Bcf) 450-475 NGLs (MBbls) 7,500-7,700 Oil (MBbls) 15-20 Condensate (MBbls) 590-610 Total Production (Bcfe) 500-525 % Liquids 9%-10% Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.30)-($0.40) NGL Realized Price ($/Bbl) $23.00-$24.00 Condensate Realized Price % of WTI 70% Oil Realized Price % of WTI 100% Realized Hedging Gain/(Loss) ($ in millions) (1) $85-$90 Other Operating Income (3 rd party water income and resold FT) ($ in millions) $15-$20 CNXM 3rd Party Gathering Revenue $80-$85 Costs Average per unit operating expenses ($/Mcfe): Lease Operating Expense $0.15-$0.18 Production, Ad Valorem, and Other Fees $0.06-$0.08 Transportation, Gathering and Compression $0.80-$0.85 $0.60-$0.65 Total Cash Production and Gathering Costs $1.01-$1.11 $0.81-$0.91 ($ in millions) Selling, General, and Administrative Costs (2) $85-$95 $95-$110 Exploration Expense $10-$15 Other Operating Expense (unutilized FT and processing, idle rig fees, and other misc.) $65-$70 Other Non-Operating Expense $15-$20 Total Capital Expenditures $790-$915 $875-$1,005 CNXM EBITDA Attributable to CNX $60-$65 EBITDAX Attributable to CNX $825-$850 Basis calculated on 2018 market mix. Hedge gain/(loss) calculated on NYMEX and financial basis hedges Transportation, gathering and compression costs expected to decline $0.15-$0.20 year-over-year primarily due to increased contribution of lower cost dry Utica volumes in Monroe County, OH Unutilized FT and Processing Fees: $50 million Idle Rig Fees: $5 million Royalty income, right of way sales, interest income and other all netted against bank fees, other corporate expense, and other land rental expense CNX Resources is unable to provide a reconciliation of projected Adjusted EBITDAX to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing, and potential significance of certain income statement items. (1) Refer to Appendix on hedging gain/(loss) assumptions. Forward pricing date as of 2/16/2018. Anticipated hedging activity is not included in projections. (2) Excludes stock-based compensation. 11
Operations: Q1 2018 Results Summary ($/Mcfe) 1Q 2018 1Q 2017 Y/Y Change 1Q 2018 4Q 2017 (1) Average sales prices for 1Q2018, 1Q2017, and 4Q2017 include (loss)/gain on commodity derivative instruments (cash settlements) of ($0.14), ($0.55), and $0.19, respectively. (2) Average Costs for 1Q2018, 1Q2017, and 4Q2017 include DD&A of $0.89, $1.01, and $1.01, respectively. Q/Q Change Average Sales Price (1) $3.00 $2.85 $0.15 $3.00 $2.80 $0.20 Total Production Costs (2) $2.10 $2.32 ($0.22) $2.10 $2.17 ($0.07) Sales Volumes (Bcfe) 129.5 95.0 34.5 129.5 118.9 10.6 Sales Volumes by Category (Bcfe) Marcellus 65.9 58.0 7.9 65.9 64.0 1.9 Utica 43.5 15.3 28.2 43.5 33.8 9.7 CBM 15.9 16.7 (0.8) 15.9 16.0 (0.1) Other 4.2 5.0 (0.8) 4.2 5.1 (0.9) Marcellus Shale costs were $2.30 per Mcfe in Q1 2018, an increase of $0.12 from $2.18 per Mcfe vs. Q1 2017, or a 6% impairment - Water disposal costs increased and processing costs were higher related to Shirley-Pennsboro wells turned-in-line in second half of 2017 Utica Shale costs were $1.60 per Mcfe in Q1 2018, a decrease of $0.56 from $2.16 per Mcfe in Q1 2017, or a 26% improvement - Transportation, gathering and compression expenses improved as lower cost Monroe Country dry Utica volumes increased E&P capital expenditures decreased in Q1 2018 to $216 million from $233 million spent in Q4 2017 12
Operations: Q1 2018 Activity and 2018 Development Plan Q1 2018 ($ in millions) TD FRAC TIL SWPA Central Average Lateral Length (1) 2018E Rigs at Period End TD FRAC TIL Marcellus 17 3 6 9,281 2 62 48 46 Utica - 1 1 6,213 3 1 1 WV Shirley-Penns Marcellus - - - - 5 5 5 Utica - - - - - - - CPA South Utica - 1 1 6,741 4 4 2 OH Dry 2-6 8,641 1 8 10 15 Utica OH Wet (2) - - - - - 5 5 Total 19 5 14 3 82 73 74 Notable Wells Richhill 11E and Marchand 3M deep dry Utica wells currently undergoing testing 1 additional CPA deep dry Utica TIL planned for 2H18 (1) Measured in lateral feet from perforation to perforation. (2) 50% working interest. 13
Capital Efficiency (Mcf/$) Daily Production Normalized @ 10,000 (Mcf/d) Consistent SWPA Marcellus Performance Sets Richhill Baseline Green Hill Production Comparison Over Time Applied learnings in SWPA Central is demonstrating consistent production results with capital efficiency increases 10,000 GH Legacy (2008-2011) GH Modern (2015-2016) GH-55 (2018) Average lateral length (ft) 1,800 5,750 9,500 1,000 5.00 4.00 3.00 2.00 1.00 0.00 0 50 100 150 200 Production Days GH Legacy GH Modern GH-55 Green Hill Capital Efficiency Over Time 4.02 2.89 0.92 GH Legacy (2008-2011) GH Modern (2015-2016) GH-55 (2018) Costs/ft $3,384 $1,170 $903 EUR (Bcf/1,000 ) 2.5 3.6 3.6 96% of the lateral footage was placed in the 10 target zone Comingled flowback operations accelerated production by 20 days along with reduced capital Replicating these techniques and results in Richhill Marcellus will compound stacked pay efficiencies 14
8,000 Normalized Production (Mcf/d) Q1 2018 SWITZ Dry Utica Optimized Field Development Informs Richhill 10,000 Ohio Dry Utica Field Spacing Changes 1100' vs 1350' Spacing Decreased Cycle Times Proppant Selection and Loading 1,000 0 50 100 150 Days 200 250 300 350 1100' Spacing 1350' Spacing Extending inter-lateral spacing from 1100 to 1350 reduced total field capital as fewer wells were required to recover comparable volumes This concept is being deployed in Richhill SWPA Utica Optimized completion design and process have driven further efficiencies as seen here: 1100 Spacing 1350 Spacing Δ Costs/ft $1,534 $1,328-13% Capital Efficiency (Mcfe/$) 1.46 2.41 +65% Full Field Optimization with Wider Spacing Richhill Compared to Switz: Similar geophysical density responses Higher reservoir pressure Same landing point Optimized managed pressure drawdown strategy However, Richhill benefits from: Stacked pay efficiencies Drilling guided by 3-D Seismic 15
Appendix
Marketing: Highlights and Liquids Realizations Marketing Highlights Directly-marketed ethane volumes were 439,000 barrels in Q1 and, on an equivalent basis, yielded a $1.24 per MMBtu premium over CNX Resources residue natural gas alternative $0.18/Mcfe uplift (1) from liquids for total average realization of $3.00 per Mcfe in Q1 2018 Natural Gas Liquids, Oil and Condensate Q1 2018 liquids sold: 12.0 Bcfe Total weighted average price of all liquids decreased 2% to $29.15 per Bbl in Q1 2018 from $29.72 per Bbl in Q1 2017 (2) and decreased 8% from $31.82 per Bbl in Q4 2017 In Q1, liquids comprised approximately 9% of 2018 production volumes and 12% of total revenue and other operating income Natural Gas Price Reconciliation 2018 2017 Q1 Q1 NYMEX Natural Gas ($/MMBtu) $3.00 $3.32 Average Differential (0.21) (0.30) BTU Conversion (MMBtu/Mcf)* 0.17 0.16 Loss on Commodity Derivative Instruments-Cash Settlement (0.14) (0.55) Realized Gas Price per Mcf $2.82 $2.63 * Conversion factor 1.06 1.05 Average Price Realization ($ per Bbl) (2) 2018 2017 Q1 Q1 NGLs $27.48 $29.16 Oil $56.46 $44.40 Condensate $49.32 $33.84 (1) Calculation includes the impact of gas hedging cash settlements. (2) Excludes propane hedging impact. 17
Natural Gas Hedging Gain/Loss Projections Q2 2018 CY2018 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) Hedged Volumes Hedged Forward Forecasted (1) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's) (000 MMBtu) Price Market ($/MMBtu) ($/MMBtu) NYMEX 94,185 $2.98 $2.70 $0.28 $26,560 377,775 $2.98 $2.84 $0.14 Basis: DOM South (DOM) 7,280 ($0.59) ($0.57) ($0.02) ($168) 30,100 ($0.60) ($0.63) $0.03 ETNG Cascade Creek TZ5 0 $0.00 $0.00 $0.00 $0 0 $0.00 $0.45 $0.00 ETNG Mainline 0 $0.00 $0.00 $0.00 $0 0 $0.00 $0.23 $0.00 Chicago 0 $0.00 ($0.25) $0.00 $0 0 $0.00 ($0.14) $0.00 TCO Pool (TCO) 9,100 ($0.27) ($0.20) ($0.07) ($623) 36,500 ($0.27) ($0.26) ($0.01) Michcon (NMC) 3,640 ($0.03) ($0.16) $0.13 $485 14,448 ($0.03) ($0.22) $0.18 TETCO ELA (TEB) 1,365 ($0.09) ($0.09) $0.00 $2 5,475 ($0.09) ($0.09) $0.00 TETCO WLA (TWB) 0 $0.00 ($0.08) $0.00 $0 0 $0.00 ($0.07) $0.00 TETCO M3 (TMT) 4,550 ($0.12) ($0.48) $0.37 $1,666 19,895 ($0.05) $0.25 ($0.31) TETCO M2 (BM2) 47,548 ($0.60) ($0.59) ($0.01) ($263) 191,613 ($0.60) ($0.63) $0.03 Total Financial basis 73,483 $1,099 298,031 Total Projected Gain/(Loss) $27,659 Note: Forward market prices are as of 4/12/2018. Hedged volumes and prices are as of 4/23/2018. Anticipated hedging activity is not included in projections. (1) April prices are settled. 18
Non-GAAP Reconciliation Three Months Ended March 31, 2018 2018 2018 2018 2017 E&P Division Midstream Unallocated (1) Total Company Total Company ($ in thousands) Net Income (Loss) $99,809 $35,534 $410,203 $545,546 ($38,966) Less: Loss from Discontinued Operations - - - - (36,269) Add: Interest Expense 36,062 2,489-38,551 41,606 Less: Interest Income (76) - - (76) (953) Add: Income Taxes - - 213,694 213,694 (63,194) Earnings/(Loss) Before Interest & Taxes (EBIT) 135,795 38,023 623,897 797,715 (97,776) Add: Depreciation, Depletion & Amortization 115,866 8,801-124,667 95,678 Earnings/(Loss) Before Interest, Taxes and DD&A (EBITDA) from Continuing Operations $251,661 $46,824 $623,897 $922,382 ($2,098) Adjustments: Unrealized Gain on Commodity Derivative Instruments (52,078) - - (52,078) (24,640) Gain on Certain Asset Sales - (4,737) (4,750) (9,487) - Gain on Previously Held Equity Interest - - (623,663) (623,663) - Severance Expense 749 65-814 230 Put Option Fair Value - Reversal from Prior Year - - (3,500) (3,500) - Other Transaction Fees 1,149 - - 1,149 - Loss (Gain) on Debt Extinguishment - - 15,635 15,635 (822) Stock-Based Compensation 4,330 579-4,909 3,754 Impairment of E&P Properties - - - - 137,865 Exploration Expense 2,380 - - 2,380 9,785 Total Pre-tax Adjustments ($43,470) ($4,093) ($616,278) ($663,841) $126,172 Adjusted EBITDAX from Continuing Operations $208,191 $42,731 $7,619 $258,541 $124,074 Less: Adjusted EBITDA Attributable to Noncontrolling Interest (2) - 22,763-22,763 - Adjusted EBITDAX Attributable to CNX Resources Shareholders $208,191 $19,968 $7,619 $235,778 $124,074 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 March 31, 2018 is Net Income Attributable to Noncontrolling interest of $17,983 plus Depreciation, Depletion and Amortization of $2,707, plus Interest Expense of $1,699, plus Stock-based compensation of $374. Note: Income tax effect of Total Pre-tax Adjustments (excluding exploration expense) was ($180,679) and $40,306 for the three months ended March 31, 2018 and March 31, 2017, respectively. Adjusted net income attributable to CNX Resources Shareholders for the three months ended March 31, 2018 is calculated as GAAP net income attributable to CNX Shareholders of $527,563 less total pre-tax adjustments from the above table of ($666,221), plus the associated tax expense of ($180,679) equals the adjusted net income attributable to CNX Resources Shareholders of $42,021. 19