Slide 1: Earnings Results Second Quarter 2019
Earnings Results Second Quarter 2019 July 30, 2019
Slide 2: Cautionary Language
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
Slide 3: Competitive Advantages and Philosophy Drive Investment Thesis
Competitive Advantages and Philosophy Drive Investment Thesis ADVANTAGES CONSISTENT Marketing Cost Asset PHILOSOPHY Strategy Structure Portfolio Hedge book Strong cash Large stacked- Investments in high rate of return opportunities Minimal FT margins pay inventory (over 20% hurdle rate) Blending Mid
Slide 4: 2019 and 2020 Program Drives Capital Allocation Opportunities
2019 and 2020 Program Drives Capital Allocation Opportunities ▪ Marcellus development lays the foundation for the The Company’s focus on risk-adjusted rates of returns has program resulted in: - Focus is on SWPA Marcellus where company has substantial core inventory ▪ Utica delineation wells in SWPA
Slide 5: Differentiated by Protection of Equity and Per Share Focus
Differentiated by Protection of Equity and Per Share Focus Through the end of Q2 2019, CNX is the Only Appalachian Producers Shares Outstanding Appalachian Producer to Have Fewer Shares % Growth / (Decline) Q4 2013 – Q2 2019(1) Outstanding Today than it Did Prior to the Last Downturn(1) 87% 87 ▪ Ove
Slide 6: CNX Midstream Free Cash Flow Presents Optionality
CNX Midstream Free Cash Flow Presents Optionality 2020E CNXM Value to CNX - Comparison EBITDA $260M Multiple(1) 9x 2020E EV $2,340M EBITDA Less: net debt $590M $250M-$270M Less: publicly owned units(2) $609M Free Cash Flow Less: CNX LP ownership(3) $315M CNXM value to CNX is $120M-$140M over $1.1 bi
Slide 7: CNX Better Positioned Than Peers 2020 and Beyond
CNX Better Positioned Than Peers 2020 and Beyond 2020E Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 85%+ Hedged ✓ X X ✓ X X X Sub-$1.10 Prod. Cash Costs ✓ X X X X X ✓ Minimal FT Obligations ✓ ✓ X X X X ✓ Reduction in S/O since 2014 ✓ X X X X X X EBITDAX/Share Growth at 2020 Gas Strip(1) ✓ X X X X ✓ X M
Slide 8: CNX Acreage Position Remains Top-Tier in Appalachia
CNX Acreage Position Remains Top-Tier in Appalachia Appalachian Peer Group Net Acres CNX SWPA Central Marcellus Locations(1) 1,400,000 450 Assuming a run rate of 30 36 SWPA Central Marcellus 400 1,200,000 24 TILs per year, CNX maintains over 12 years of 350 core inventory after YE2020 1,000,000 300
Slide 9: Q2 2019 Operational Results Summary
Q2 2019 Operational Results Summary Y/Y Q/Q ▪ Marcellus Shale cash production costs were $1.40 per Mcfe in Q2 ($/Mcfe) 2Q 2019 2Q 2018 Change 2Q 2019 1Q 2019 Change 2019, up $0.04 from $1.36 per Mcfe in Q2 2018, or a 2% increase Average Sales Price(1) $2.63 $2.87 ($0.24) $2.63 $2.97 ($0.34) ▪ Utica
Slide 10: Low Production Cash Costs Create Competitive Advantage
Low Production Cash Costs Create Competitive Advantage 2.50 TTM Q1/Q2 2019 Production Cash Costs(1) $2.12 2.00 CNX’s top-tier $1.68 production cash 1.50 $1.25 $1.30 costs and $1.09 $1.16 substantial hedge 1.00 $0.78 $0.79 book create a significant 0.50 advantage in a weak natural gas pricing - (3) (
Slide 11: Minimal FT Commitments Reduce Risk and Costs
Minimal FT Commitments Reduce Risk and Costs Total FT and Processing Commitments(1) Total FT and Processing Commitments + 1Q19End Net Debt(1) $23.5 $27.0 $19.1 $14.2 $14.0 $10.2 $8.8 $10.7 $5.8 $3.7 $4.1 $1.7 $2.3 $2.6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 1 CNX Peer 2 Peer 3 Peer 4 Pee
Slide 12: SWPA Utica Majorsville 6 Capital Costs Beating Targets
SWPA Utica Majorsville 6 Capital Costs Beating Targets Majorsville 6 – Deep Dry Utica Total Lateral Total Days Total Length Drilling D&C MAJ6E 6,345 29 $11,267,000 MAJ6F 6,214 52 $13,408,000 MAJ6G 6,335 33 $11,662,000 (2) MAJ6H 6,920 35 $12,151,000 Average 6,454 37 $12,122,000 ▪ First multi-well SWP
Slide 13: SWPA Stacked Pay Strategy Happening Now
SWPA Stacked Pay Strategy Happening Now Damp Marcellus to Dry Outlets Blending Strategy in Full Swing ▪ Blending Marcellus and Utica volumes generates meaningful returns and unique optionality within Appalachia ▪ Three SWPA dry Utica pads to TIL by Q1 2020 ▪ Allows damp Marcellus gas to be blended i
Slide 14: State Record Long Lateral Drilled on Richhill Pad
State Record Long Lateral Drilled on Richhill 71 Pad Richhill 71 Marcellus Highlights Richhill 71 Pad Layout ▪ RHL71B: PA record longest drilled lateral: 19,609’ - Drilled 100% in target ▪ Pad average lateral length (6 wells): 15,744’ ▪ Estimated D&C capital expenditure: ~$800/ft(1) ▪ Estimated gros
Slide 15: Integrating and Optimizing Operations To Drive Efficiencies
Integrating and Optimizing Operations To Drive Efficiencies Integrated Real-Time Operations Center Objective Functionality Key Results ▪ 99.5% production uptime ▪ 24/7 real time surveillance ▪ ~60% reduction in NPT since 2016 ▪ Remote control and EBITDAX automation ▪ ~30% increase in production sinc
Slide 16: Q2 2019 Financial Results Summary
Q2 2019 Financial Results Summary Quarter Quarter Quarter Quarter Ended Ended Ended Ended June 30, June 30, June 30, June 30, 2019 2018 2019 2018 % Increase/ % Increase/ ($ in millions, except per share data) Stand-alone Consolidated (Decrease) (Decrease) Adjusted Net Income $12 $62 -80.6% $57 $90 -
Slide 17: Our Strategy Drives Significant EBITDAX per Share Growth
Our Strategy Drives Significant EBITDAX per Share Growth E&P Stand-Alone Adjusted EBITDAX per Share $1.50 Q1 2017 – Q2 2019 $1.36 $1.30 CNX Adjusted $1.10 $1.15 EBITDAX per $1.03 $0.92 $0.99 $0.93 share has grown $0.90 $0.83 145% in the last $0.70 two years while $0.54 natural gas prices $0.50 $0.38
Slide 18: Debt Discipline and EBITDAX Growth Drive Available Capacity
Debt Discipline and EBITDAX Growth Drive Available Capacity Shares Repurchased Since Program Announced Stand-Alone and Consolidated Net Debt 250.0 6.4 $ in millions June 30, 2019 25.9 3.1 8.8 200.0 Stand-Alone Midstream Total +1.7 Shares (millions) Total Long-Term Debt (GAAP)(1) $2,016.7 $601.7 $2,6
Slide 19: Guidance Update
CNX <p < 5000 72000 14.000 6000 — TUBE AM coNEcTION 4009 Guidance Update
Slide 20: Updated 2019 and 2020 Guidance
Updated 2019 and 2020 Guidance PREVIOUS UPDATED 2020E D&C capital expected to decline 2019E 2019E 2020E ~33% midpoint to midpoint while production expected to grow over 12% Capital Expenditures Low High Low High Low High ($ millions) Drilling & Completions $695 $745 $695 $745 $450 $520 Non-D&C capit
Slide 21: Hedge Book Reduces EBITDAX Sensitivity to Commodity Swings
Hedge Book Reduces EBITDAX Sensitivity to Commodity Swings 2020E EBITDAX and FCF Sensitivity(1) $ (0.30) $ (0.20) $ (0.10) Base (2) $ 0.10 $ 0.20 $ 0.30 Average NYMEX ($/MMBtu) $ 2.25 $ 2.35 $ 2.45 $ 2.55 $ 2.65 $ 2.75 $ 2.85 Each $0.10 move in 2020 NYMEX E&P Standalone price results in just a ~$10
Slide 22: Production Cadence and Hedge Advantage 2019-2020
Production Cadence and Hedge Advantage 2019-2020 Expected Daily Production 2019-2020(1) CNX One of Most Hedged Producers and with 1.8 Strongest Realization Heading into 2020(3) 1.6 2020 Hedged Gas Production 100% 1.4 Average Hedged Volumes $2.94 $2.95 90% 1.2 459 Bcf hedged at $2.87 Production (Bcfe
Slide 23: 2019 AMT Credit and Additional Refunds
2019 AMT Credit and Additional Refunds June 30, December 31, 2019 2018 Combined AMT refund and additional tax refunds to Current Assets Cash and Cash Equivalents $ 32,611 $ 17,198 drive total cash tax inflow of ~$146 million in 2019 Accounts and Notes Receivable Trade 125,084 252,424 Other Receivabl
Slide 24: Updated 2019 and 2020 Guidance
Updated 2019 and 2020 Guidance 2019E 2020E Revenue and Other Operating Income E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 480-500 535-560 NGLs (MBbls) 4,685-4,875 5,175-5,400 Condensate (MBbls) 205-215 460-480 Total Production (Bcfe) 510-530 570-595 % Liquids ~6% ~6% Natu
Slide 25: Workflow Efficiency Efforts to Drive SG&A, Capital, LOE Savings
Workflow Efficiency Efforts to Drive SG&A, Capital, LOE Savings 1 Cash SG&A per Mcfe Trending Favorably with Upside to Come Upstream/Midstream Integration ▪ Combined construction teams Upside to ▪ Streamlined to one monitoring Consolidated Consolidated system 2020E with FY2018 FY2020E Continued Gene
Slide 26: Financial Guidance: 2019E Natural Gas Marketing Mix and Basis
Financial Guidance: 2019E Natural Gas Marketing Mix and Basis Volumes 2019E CY 2019 Market Michcon Northeast Pipeline Projects (000 MMBtu) Gas Sold (%) Basis 2019E Gas: 10% DOM South 36,029 7% ($0.37) CY19 Basis: ($0.17) ETNG Mainline 5,917 1% $0.45 DOM South TCO Pool 89,265 17% ($0.28) TETCO M3 201
Slide 27: Financial Guidance: 2020E Natural Gas Marketing Mix and Basis
Financial Guidance: 2020E Natural Gas Marketing Mix and Basis Volumes 2020E CY 2020 Market Michcon Northeast Pipeline Projects (000 MMBtu) Gas Sold (%) Basis 2020E Gas: 9% DOM South 59,002 10% ($0.41) CY20 Basis: ($0.18) ETNG Mainline 23,516 4% $0.57 DOM South TCO Pool 78,797 14% ($0.32) TETCO M3 20
Slide 28: Q3 2019, 2019E, and 2020E Gas Hedging Gain/Loss Projections
Q3 2019, 2019E, and 2020E Gas Hedging Gain/Loss Projections Q3 2019 CY2019 CY2020 Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted (2)(4) (4) Hedged Volumes Hedged Forward Gain/(Loss) Hedged Volumes Hedged Forward Gain/(Loss) Hedged Volumes Hedged Forward Gain/(Loss)(4)
Slide 29: Appendix
CNX Appendix
Slide 30: Q2 Activity Summary
Q2 Activity Summary Q2 2019 YTD 2019 Average Rigs at Lateral Period ($ in millions) TD FRAC TIL Length(1) End TD FRAC TIL ▪ Currently three rigs in operation which SWPA Marcellus 17 5 4 10,123 2 23 19 22 Central are under contract through year-end Utica 8 4 - 1 10 4 - 2019 WV Marcellus 3 - - - 1 3 -
Slide 31: Natural Gas Hedging and Basis Protection
Natural Gas Hedging and Basis Protection 500 450 25.9 Gas Volumes Hedged (Bcf) 400 15.7 22.2 350 The substantial hedge 300 250 35.5 book de-risks rates of 200 380.9 444.6 394.0 return and creates 150 9.4 100 243.9 time to adjust 136.9 50 development plans 0 2019 2020 2021 2022 2023 and protect the N
Slide 32: Marketing Highlights and Liquids Realizations
Marketing Highlights and Liquids Realizations Marketing Highlights Natural Gas Liquids, Oil and Condensate ▪ Directly-marketed ethane sales volumes to Marcus ▪ Q2 2019 liquids sold: 8.1 Bcfe Hook were limited in the quarter due primarily to ▪ Total weighted average price of all liquids decreased 37%
Slide 33: CPA Dry Utica Results Remain Consistent and Strong
CPA Dry Utica Results Remain Consistent and Strong CPA Dry Utica Results CPA Dry Utica Cumulative Production Pressure Drawdown vs 7,000’ Norm. Cumulative Production 16,000 Normalized to 7000’ 100% 14,000 90% Cumulative Production (MMcf) 12,000 80% % of Initial Reservoir Pressure 10,000 70% 60% 8,000
Slide 34: CPA Deep Utica Wells Payback in Months at $2.59/Mcf
CPA Deep Utica Wells Payback in 10 Months at $2.59/Mcf (Q2 2019 Price) At 20 MMcf/d held flat, a 3.5 Bcf/1000’ EUR CPA deep dry Utica well pays for itself after just 10 months(1) (1) Assumes Q2 2019 average realized dry gas price of $2.59/Mcfe, Utica cash production costs of $0.47/Mcfe, and well cos
Slide 35: Stacked Pay Development Providing Economic Uplift
Stacked Pay Development Providing Economic Uplift Premier stacked pay field in SWPA Central type curve region Richhill Development Case Study ▪ CNX is developing the Richhill field, which provides optionality: - Send to processing 30% NPV uplift driven by: - Blend damp gas with dry Utica ▪ Capital e
Slide 36: Drilling and Completion Efficiency Continues to Improve
Drilling and Completion Efficiency Continues to Improve Drilling Days per Lateral by Formation Completion Efficiency Feet per Day Marcellus Total Total Portfolio 1200 28 26 Drilling Days (10k’ Lateral) 24 22 1000 20 18 16 800 Feet Stimulated per Day 14 12 10 2014 2015 2016 2017 2018 2019E 600 80 OH
Slide 37: A Decade of Rapid E&P Growth
A Decade of Rapid E&P Growth CNX forged its identity over 150 years as a leader in energy production in Appalachia and is now a top-ten natural gas producer in the United States Corporate Premier modern thermal Renewed focus on natural gas spin coal producer exploration and production 150+ years of
Slide 38: Acreage and Infrastructure Drive Risk-Adjusted Returns
Acreage and Infrastructure Drive Risk-Adjusted Returns Net Marcellus Acres Reserves to % Operated Proved Reserves Large / Net Utica Acres(1) Production(2) Contiguous Acreage 539,000 / Position 95.5% 15.6 years 7.9 Tcfe 627,000 2Q19 2Q19 2019E Production Production Fully-Burdened Leverage Ratio Cash
Slide 39: YE2018 Acreage and Undeveloped Location Update
YE2018 Acreage and Undeveloped Location Update MARCELLUS UTICA TYPE CURVE AREAS TYPE CURVE AREAS SWPA Central Greater TOTAL SWPA SWPA Central Greater TOTAL SWPA Total Net Acres 98,100 33,700 131,800 Total Net Acres 120,500 55,100 175,600 Net Developed Acres 28,300 2,400 30,800 Net Developed Acres 30
Slide 40: YE2018 Type Curve Area and Acreage Update
YE2018 Type Curve Area and Acreage Update Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019. 40
Slide 41: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended June 30, 2019 2018 2019 2018 Total Total Stand-alone(1) Stand-alone(1) ($ in thousands) Company Company Net Income from EBITDAX Reconciliation $148,281 $33,614 $192,694 $61,394 Adjustments Total Pre-tax Adjustments from EBITDAX Reconciliation (186,317) 38,3
Slide 42: Non-GAAP Reconciliation
Non-GAAP Reconciliation Price and Cost Data per Mcfe ($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Average Sales Price - Total Company $ 2.85 $ 2.47 $ 2.50 $ 2.80 $ 3.00 $ 2.87 $ 2.92 $ 3.09 $ 2.97 $ 2.63 Lease Operating Expense $ 0.23 $ 0.23 $ 0.22 $ 0.21
Slide 43: Non-GAAP Reconciliation
Non-GAAP Reconciliation Twelve Months Ended June 30, 2019 2019 2019 Total Stand-alone(1) Midstream ($ in thousands) Company Net Income $256,735 $147,479 $404,214 Interest Expense 115,837 29,031 144,868 Interest Income (834) - (834) Income Tax Expense 62,197 - 62,197 Earnings Before Interest & Taxes
Slide 44: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended June 30, 2019 2019 2019 (1) Total Stand-alone Midstream ($ in thousands) Company Net Income $148,281 $44,413 $192,694 Interest Expense 32,467 7,685 40,152 Interest Income (71) - (71) Income Tax Expense 40,791 - 40,791 Earnings Before Interest & Taxes (EBIT)
Slide 45: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended June 30, 2018 2018 2018 (1) Total Stand-alone Midstream ($ in thousands) Company Net Income $33,614 $27,780 $61,394 Interest Expense 31,320 7,118 38,438 Interest Income - - - Income Tax Benefit (31,102) - (31,102) Earnings Before Interest & Taxes (EBIT) 33,
Slide 46: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended March 31, 2019 2019 2019 (1) Total Stand-alone Midstream ($ in thousands) Company Net (Loss) Income ($97,235) $32,584 ($64,651) Interest Expense 28,432 7,339 35,771 Interest Income (722) - (722) Income Tax Benefit (11,559) - (11,559) Earnings Before Interes
Slide 47: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended Twelve Months Ended Stand-alone(1) March 31, June 30, September 30, December 31, December 31, ($ in thousands) 2018 2018 2018 2018 2018 Net Income $510,012 $33,614 $115,583 $90,106 $749,315 Interest Expense 36,062 31,320 28,467 26,471 122,320 Interest Incom
Slide 48: Non-GAAP Reconciliation
Non-GAAP Reconciliation Twelve Months Attributable to CNX Shareholders Three Months Ended Ended March 31, June 30, September 30, December 31, December 31, ($ in thousands) 2017 2017 2017 2017 2017 Net (Loss) Income ($38,966) $169,511 ($26,441) $276,643 $380,747 Less: (Income) Loss from Discontinued