Slide 1: Earnings Results First Quarter 2019
Earnings Results First Quarter 2019 April 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: Executive Summary
Executive Summary Q1 2019 EXPECTATION STRATEGIC THEME ▪ Production cash costs down 8% Y/Y and fully-burdened Operational Execution and margins up 6% Y/Y; LOE and low transportation and ▪ Minimal firm transportation commitments, operational Strong Cost and Margin gathering fees create advantage initi
Slide 4: Q1 2019 Operational Results Summary
Q1 2019 Operational Results Summary ▪ Marcellus Shale costs were $2.02 per Mcfe in Q1 2019, a decrease of Y/Y Q/Q $0.28 from $2.30 per Mcfe vs. Q1 2018, or a 12% decline ($/Mcfe) 1Q 2019 1Q 2018 Change 1Q 2019 4Q 2018 Change - Driven primarily by decreases in LOE Average Sales Price(1) $2.97 $3.00 (
Slide 5: Q1 and FY2019E-2020E Activity Based on 2019 Capital Program
Q1 and FY2019E-2020E Activity Based on 2019 Capital Program Q1 2019 FY 2019E FY 2020E Average Rigs at Lateral Period ($ in millions) TD FRAC TIL Length(1) End 2019 Program TD FRAC TIL TD FRAC TIL Carryover SWPA Marcellus 6 14 18 7,618 2 Central Marcellus 41 51 48 - 8 20 Utica 2 - - 2 WV Marcellus -
Slide 6: 2019 Development Program and Capital Breakdown
2019 Development Program and Capital Breakdown Average CPA Utica Shaw Pad D&C CapEx(1) TILs Lateral Length(2) ▪ The Shaw 1G well that experienced issues in early ($ in millions) 2019E 2020E 2019E 2020E 2019E 2020E 1Q 2019 has been remediated ▪ The remaining three laterals exist as DUCs and, Marcellu
Slide 7: SWPA Marcellus: Continued Optimization and Outperformance
SWPA Marcellus: Continued Optimization and Outperformance Production Far Exceeds Legacy Well Performance Operational Efficiency Reduces Capital and Increases IRR Morris – Marcellus SWPA Operational Efficiency Cumulative Mcf Normalized to 8000' 7,000,000 MOR 29 (2018 Q4) 150% 141% 6,000,000 MOR 30 (2
Slide 8: OH Dry Utica: Optimized Field Development Informs PA Utica
OH Dry Utica: Optimized Field Development Informs PA Utica Switz Operational Efficiency Drilling (1) Frac(2) 240% Efficiency Gain (% ) 177% 190% 140% 90% 32% 40% Proppant -10% Selection SWITZ 16 SWITZ 5 SWITZ 28 SWITZ 11 SWITZ 26 SWITZ 7 SWITZ 18 SWITZ 27 SWITZ 9 and Loading 2016 90% Switz EUR Perfo
Slide 9: Implementing Elements of the "Perfect Pad"
Implementing Elements of the “Perfect Pad” Prior Days 120 Target Days 90 Process Dry month construction Cellar technology construction allows for subsurface well heads for faster return 11 return to pad trips in 2019; 4 of which are stacked pay ✓ ✓ 12 Marcellus 3D seismic drives well bore optimizati
Slide 10: Q1 2019 Financial Results Summary
Q1 2019 Financial Results Summary Net Income and Adjusted EBITDAX ▪ Net loss attributable to CNX Shareholders of $87 million in the 2019 first quarter; consolidated adjusted net income of $67 million(1); adjusted net income excludes the following pre-tax items: - $154 million unrealized loss on comm
Slide 11: Debt Discipline and EBITDAX Growth Drive Available Capacity
Debt Discipline and EBITDAX Growth Drive Available Capacity 250.0 Shares Repurchased Since Program Announced Stand-Alone and Consolidated Net Debt 6.4 5.8 5.3 8.3 $ in millions March 31, 2019 200.0 6.5 3.7 +1.4 Stand-Alone Midstream Total Shares (millions) 150.0 Total Long-Term Debt (GAAP)(1) $1,900
Slide 12: Updated 2019 Guidance
Updated 2019 Guidance PREVIOUS UPDATED 2019E 2019E Incremental D&C activity driven by confidence in Utica program coming out of QA/QC process and drilling success with SWPA Utica TDs Capital Expenditures Low High Low High ($ millions) Drilling & Completions $575 $625 $695 $745 Increase in non-D&C ca
Slide 13: Updated 2019 Guidance
Updated 2019 Guidance 2019E Revenue and Other Operating Income E&P Consolidated Production Volumes: Natural Gas (Bcf) 465-485 NGLs (MBbls) 4,500-4,600 Condensate (MBbls) 350-400 Total Production (Bcfe) 495-515 % Liquids 5-6% Natural Gas Basis Differential to NYMEX ($/Mcf) ($0.20)-($0.25) NGL Realize
Slide 14: 2020 Set Up for Production & FCF Growth on 2019 Program Alone
2020 Set Up for Production & FCF Growth on 2019 Program Alone ($ in million, except per unit) 2020E Expected Daily Production 2020E Production (Bcfe) ~555 1.8 Based on 2019 Development Program Only Weighted Average Revenue (NYMEX+Hedges) ($/Mcfe) $2.65 Fully Burdened Cash Costs ($/Mcfe)(1) $1.65 1.6
Slide 15: Natural Gas Hedging and Basis Protection
Natural Gas Hedging and Basis Protection 500 450 30.9 Layering in hedges out to 2023 and beyond Gas Volumes Hedged (Bcf) 400 - 45.9 to protect margins on proved developed 350 production and a portion of PUDs 300 250 59.7 440.4 200 377.0 370.3 De-risked pricing for next three 150 33.6 100 222.4 years
Slide 16: CNX Water Infrastructure Drives SWPA Advantage
CNX Water Infrastructure Drives SWPA Advantage CNX currently handling ~30,000 barrels a day of produced water Reduced Cost Safe and Clean Third-Party Revenue SWPA Water Infrastructure Investments ▪ CNX benefits from low cost of pumping ▪ Fewer safety accidents ▪ Provide fresh water to other E&P prod
Slide 17: 2019 AMT Credit and Additional Refunds
2019 AMT Credit and Additional Refunds March 31, December 31, 2019 2018 Combined AMT refund and additional tax refunds to Current Assets Cash and Cash Equivalents $ 23,972 $ 17,198 drive total cash tax inflow of ~$146 million in 2019 Accounts and Notes Receivable Trade 157,908 252,424 Other Receivab
Slide 18: Appendix
CNX 6000 4009 2000 Appendix
Slide 19: YE2018 Acreage and Undeveloped Location Update
YE2018 Acreage and Undeveloped Location Update MARCELLUS UTICA TYPE CURVE AREAS TYPE CURVE AREAS SWPA Central Greater TOTAL SWPA SWPA Central Greater TOTAL SWPA Total Net Acres 98,100 33,700 131,800 Total Net Acres 120,500 55,100 175,600 Net Developed Acres 28,300 2,400 30,800 Net Developed Acres 30
Slide 20: YE2018 Type Curve Area and Acreage Update
YE2018 Type Curve Area and Acreage Update Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019. 20
Slide 21: Marketing Highlights and Liquids Realizations
Marketing Highlights and Liquids Realizations Marketing Highlights Natural Gas Liquids, Oil and Condensate ▪ Directly-marketed ethane sales volumes were limited ▪ Q1 2019 liquids sold: 7.1 Bcfe in the quarter due primarily to Mariner East delivery ▪ Total weighted average price of all liquids decrea
Slide 22: Q2 2019E Gas Hedging Gain/Loss Projections
Q2 2019E Gas Hedging Gain/Loss Projections Q2 2019 CY2019 Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (1) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's) ($/MMBtu) NYMEX 98,053 $2.83 $2.70 $0.13 $12,879 Basis: DOM South (DOM) 10,920 ($0.59) ($0.33) ($0.26) ($2,885) TCO Pool (TCO) 14,560 ($0
Slide 23: 2019E Gas Hedging Gain/Loss Projections
2019E Gas Hedging Gain/Loss Projections CY2019 CY2020 (1) Hedged Volumes Hedged Forward Forecasted Gain/(Loss) (000 MMBtu) Price Market ($/MMBtu) ($ in 000's) ($/MMBtu) ▪ In addition to NYMEX and basis financial NYMEX 386,088 $2.83 $2.88 ($0.05) ($18,841) hedges, CNX has physical fixed basis sales a
Slide 24: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended March 31, 2019 2019 2019 (1) Total Stand-alone Midstream ($ in thousands) Company Net (Loss) Income ($97,235) $32,584 ($64,651) Interest Expense 28,432 7,339 35,771 Interest Income (722) - (722) Income Tax Benefit (11,559) - (11,559) Earnings Before Interes
Slide 25: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended March 31, 2018 2018 2018 Total Stand-alone(1) Midstream ($ in thousands) Company Net Income $510,012 $35,534 $545,546 Interest Expense 36,062 2,489 38,551 Interest Income (76) - (76) Income Tax Expense 213,694 - 213,694 Earnings Before Interest & Taxes (EBI
Slide 26: Non-GAAP Reconciliation
Non-GAAP Reconciliation Twelve Months Ended March 31, 2019 2019 2019 Total Stand-alone(1) Midstream ($ in thousands) Company Net Income $142,068 $130,846 $272,914 Interest Expense 114,690 28,464 143,154 Interest Income (763) - (763) Income Tax Benefit (9,696) - (9,696) Earnings Before Interest & Tax
Slide 27: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended March 31, 2019 2018 2019 2018 Total Total Stand-alone(1) Stand-alone(1) ($ in thousands) Company Company Net (Loss) Income from EBITDAX Reconciliation ($97,235) $510,012 ($64,651) $545,546 Adjustments Total Pre-tax Adjustments from EBITDAX Reconciliation 17
Slide 28: Non-GAAP Reconciliation
Non-GAAP Reconciliation ($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Average Sales Price - Total Company $ 2.85 $ 2.47 $ 2.50 $ 2.80 $ 3.00 $ 2.87 $ 2.92 $ 3.09 $ 2.97 Lease Operating Expense $ 0.23 $ 0.23 $ 0.22 $ 0.21 $ 0.28 $ 0.21 $ 0.14 $ 0.12 $ 0.14 Transport