Slide 1: Earnings Results Fourth Quarter 2019
Earnings Results Fourth Quarter 2019 January 30, 2020
Slide 2: Cautionary Language
Cautionary Language For purposes of this presentation: (i) “CNX”, “CNX Resources”, “Company”, “we” and “our” refer to CNX Resources Corporation (ii) “CNXM” refers to CNXM Midstream Partners LP; and (iii) “CNXM GP” refers to CNX Midstream GP LLC Risk Factors. This presentation, including the oral sta
Slide 3: CNX Highlights
CNX Highlights ◼ IDR elimination transaction simplifies capital structure CNXM Simplified Structure ◼ Reduces CNXM’s cost of capital ◼ Aligns sponsor and public unitholder economic interests ◼ Beating guidance Operational Excellence ◼ Strong well results ◼ Low operating costs ◼ Best-in-class hedge b
Slide 4: 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 5: Excelling Through the Downturn
Excelling Through the Downturn 1 IDR Transaction Puts CNXM in Right Capital Structure ✓ 2 Beat Guidance Across the Board in 2019 ✓ 3 Forecasting $250 million in FCF in 2020 ✓ 4 Hedge Book Protects the Company for Several Years ✓ 5 Forecasting $250 million in FCF in 2021 ✓ 6 Strong 2020 and 2021 Sets
Slide 6: Milestones
Milestones GP Acquisition & Enhanced HG Asset Exchange Agreement SWPA System Expansion IDR Elimination Transaction Commercial Agreement CNX acquires remaining 50% GP ▪ Additional +$145mm minimum ▪ Significant investment year: IDRs exchanged for common interest from Noble for ~$300mm revenue commitme
Slide 7: Incentive Distribution Rights (IDR) Transaction Overview
Incentive Distribution Rights (IDR) Transaction Overview Transaction Overview Pro Forma Structure The incentive distribution rights and economic general partner interest in CNXM owned by CNX were exchanged for the following: ▪ 26 million common LP Units Public ▪ 3 million Class B units, will not rec
Slide 8: CNXM is Crucial to CNX's Success
CNXM is Crucial to CNX’s Success CNXM Adjusted EBITDA 2015-2021E $300 Following IDR Elimination Transaction, $250 CNX now owns 47.7 $200 million common units. The transaction also $ in millions $150 includes 3 million Class $100 B units that will convert to CNXM common units $50 on January 1, 2022 $
Slide 9: Strong Full Year 2019 Financial and Operational Performance
Strong Full Year 2019 Financial and Operational Performance Actuals 2019 Guidance Actuals vs. ($ in millions) 2019 Low High Avg. Midpoint Guidance Production Volumes (Bcfe) 539 530 540 535 4 Adjusted EBITDAX $772 $745 $765 $755 $17 Total E&P Capital $876 $890 $915 $903 ($27) ▪ Finished 2019 with str
Slide 10: 2019 Capital and Operations Improvements
2019 Capital and Operations Improvements Capital Continuous Improvements Operations Continuous Improvements ▪ Completion design optimization ▪ Decreased water disposal through increased reuse ▪ Cycle time efficiencies ▪ Combined midstream and upstream production teams ▪ Fuel cost savings of frac cre
Slide 11: SWPA Marcellus: Increased Results and Efficiencies
SWPA Marcellus: Increased Results and Efficiencies Richhill (RHL) Marcellus - 2018 vs. Now Ohio River Water Line (to Richhill) 6.0 9000' Normalized Cumulative (Bcf) 5.0 4.0 3.0 2.0 1.0 - - 50 100 150 200 250 300 350 400 450 500 550 Days Current RHL TC 2018 TILs 2019 TILs ▪ 2019 RHL wells continue to
Slide 12: SWPA Blending Strategy in Full Swing
SWPA Blending Strategy in Full Swing Damp Marcellus to Dry Outlets ▪ Maximize NAV by drilling high ROR Marcellus pads with enough Utica to blend into dry outlet ▪ Only completing enough to blend over the next several years - 1 SWPA dry Utica pad expected to TIL in both 2020 and 2021 - Blending econo
Slide 13: Operational Highlights
Operational Highlights Dry Ridge Compressor Station Highlights ▪ Richhill Area - Marcellus drilling cost per foot decreased 23% in 2019, compared to 2018 - Marcellus stimulation lateral footage per day improved 9% in 2019, compared to 2018 Production and Midstream Highlights ▪ In 2019, production in
Slide 14: Low Production Cash Costs Create Competitive Advantage
Low Production Cash Costs Create Competitive Advantage $2.25 $2.18 TTM Q3/Q4 2019 Production Cash Costs per Mcfe(1) $1.69 CNX’s top-tier production cash $1.50 $1.25 $1.31 costs, substantial $1.13 $1.13 hedge book, and midstream control $0.78 $0.78 $0.75 create a significant advantage in a weak natur
Slide 15: Proactive Business Management: Cumulative Changes Since Q2 2019 Call
Proactive Business Management: Cumulative Changes Since Q2 2019 Call OLD (Q2 2019) NEW (Q4 2019) 2020 NYMEX $2.55/MMBtu ($0.46)/MMBtu $2.09/MMBtu(1) Macro Conditions Got Much Worse But CNX Got Much Stronger E&P Capex Decreased by ~$144M Decreased cumulatively in 2019 and 2020 by ~$144M, based on 201
Slide 16: Updated 2020 and 2021 Guidance
Updated 2020 and 2021 Guidance Previous UPDATED 2020E 2020E Capital Expenditures Maintaining non-D&C capital in 2020 and expect this to be lower in 2021 Low High Low High ($ millions) Drilling & Completions $400 $450 $360 $410 Non-D&C $90 $100 $90 $100 For 2019 and 2020 combined, Total E&P capital i
Slide 17: Production Cadence and Hedge Advantage in 2020
Production Cadence and Hedge Advantage in 2020 1.8 Expected Daily Production 2020(1) 2021 Due to 1.6 minimum well Production commitments 2020 Sets Up 2021 Well 1.4 Growth Average Hedged Volumes: 498 Bcf or 98% of gas production hedged at NYMEX $2.96 in 2020 (MWC’s) 1.2 ~5% expect at a Production (Bc
Slide 18: Substantial Hedges with Strongest Prices in 2020 and 2021
Substantial Hedges with Strongest Prices in 2020 and 2021 2020E(1) Hedged Gas Production 2021E(1) Hedged Gas Production 100 % $ 3.00 100% $ 2.96 $3.00 ~57% of 2022(1) production $2.91 $ 2.87 90% $ 2.88 hedged under maintenance 98% $2.90 $ 2.90 scenario at $2.99 NYMEX 83% $2.80 92% 80% $2.80 80 % $ 2
Slide 19: Balance Sheet is Getting Stronger
Balance Sheet is Getting Stronger $ in millions December 31, 2019 Stand-Alone Net Debt and Leverage Stand-Alone LP-Adjusted(1) Total Long-Term Debt (GAAP) $2,048.5 $2,048.5 Less: Cash and Cash Equivalents $15.3 $15.3 Less: Forecasted 2020 Total FCF $250.0 $250.0 Less: 50.7M units Forecasted Net Debt
Slide 20: Highly Resilient Balance Sheet
Highly Resilient Balance Sheet Net Debt + Off-Balance Sheet Obligations / 22.0 x 2021E EBITDA(1) ▪ Under current strip, CNX expects to generate FCF and reduce Net Debt leverage in 2020 and 2021 Off-Balance Sheet Obligations 16.8 x 15.7 x 13.8 x ▪ Flexibility through low total liability positioning i
Slide 21: CNX Screens Well on All-In Debt Metrics vs. Appalachian Peers
CNX Screens Well on All-In Debt Metrics vs. Appalachian Peers Total Debt(1) as % of EV FT Commitments as % of EV Total Debt(1) + FT Commitments as a % of EV 484% 81% 80% 73% 403% 66% 65% 368% 319% 316% 54% 302% 251% 246% 231% 150% 95% 15% 41% 35% 20% Peer 1 Peer 5 Peer 4 Peer 2 Peer 3 CNX Peer 6 Pee
Slide 22: 2022 Senior Notes Maturities Easily Addressed
2022 Senior Notes Maturities Easily Addressed 2022 FCF also expected to be additional source of funds ~$780M CNXM Units(1) $ in millions Ability to $1.2B payoff or Revolver Liquidity refinance Note: CNX is unable to provide a reconciliation of projected financial results contained in this presentati
Slide 23: What Lies Ahead in 2021?
What Lies Ahead in 2021? CNX has taken a deliberate approach, focusing on flexibility to appropriately manage through the commodity cycle ◼ Expect to generate approximately $250 million in total FCF in each 2020 and 2021 ◼ Leverage ratio decreases to approximately 2.0x CNX Under the Current ◼ Modest
Slide 24: Appendix
CNX Appendix
Slide 25: Financial Guidance
Financial Guidance PREVIOUS (10/30/2019) UPDATE (1/30/2020) 2020E 2020E Revenue and Other Operating Income E&P Consolidated E&P Consolidated Production Volumes: Natural Gas (Bcf) 505-535 495-525 NGLs (MBbls) 4,490-4,715 4,535-4,760 Condensate (MBbls) 245-265 245-265 Total Production (Bcfe) 535-565 5
Slide 26: Realignment Driving Expected Best-In-Class SG&A
Realignment Driving Expected Best-In-Class SG&A $350 TTM Q3/Q4 2019 SG&A(1) $0.20 Expect ~$30 million in total expected consolidated cash SG&A savings $0.18 $300 since 2018 $306 $0.16 ▪ Combined upstream and midstream teams Total SG&A Absolute Dollars ($M) $250 $0.14 ▪ Streamlined to one monitoring
Slide 27: Q4 2019 Financial Results Summary
Q4 2019 Financial Results Summary Quarter Quarter Quarter Quarter Ended Ended Ended Ended December 31, December 31, December 31, December 31, 2019 2018 2019 2018 % Increase/ % Increase/ ($ in millions, except per share data) Stand-alone Consolidated (Decrease) (Decrease) Adjusted Net (Loss) Income (
Slide 28: Q4 2019 Operational Results Summary
Q4 2019 Operational Results Summary Y/Y Q/Q ▪ Marcellus Shale cash production costs were $1.28 per Mcfe in Q4 ($/Mcfe) 4Q 2019 4Q 2018 Change 4Q 2019 3Q 2019 Change 2019, up $0.08 from $1.20 per Mcfe in Q4 2018, or a 7% increase (1) Average Sales Price $2.54 $3.09 ($0.55) $2.54 $2.51 $0.03 ▪ Utica S
Slide 29: Q4 2019 Activity Summary
Q4 2019 Activity Summary Q4 2019 2019 Average Rigs at Lateral Period ($ in millions) TD FRAC TIL Length (1) End TD FRAC TIL SWPA Marcellus 4 6 4 9,850 - 38 34 36 Central Utica 1 1 1 5,925 - 13 9 8 WV Marcellus 4 - - - 1 9 5 5 Shirley-Penns Utica - - - - - - - - CPA South Utica - - - - - 1 - - OH Dry
Slide 30: Executive Summary
Executive Summary Q4 2019 EXPECTATION STRATEGIC INITIATIVE ▪ ~98% of 2020 gas volumes hedged at NYMEX $2.96 ▪ Hedge book protects our returns and margins for the Substantial Hedge Position per Mcf; ~83% of 2021 gas volumes hedged at majority of 2020 and 2021 activity NYMEX $2.91 per Mcf ▪ 2020 produ
Slide 31: Cumulative Changes Since Q2 2019 Call
Cumulative Changes Since Q2 2019 Call Q2 2019 Earnings Call (7/30/2019) Q4 2019 Earnings Call (1/30/2020) Midpoints of Guidance Ranges 2019 Actuals/Midpoints of 2020 Guidance Total Changes ($ in millions) 2019 2020E Total 2019A 2020E Total Since Q2 2019 Production (Bcfe) 520 583 1,103 539 540 1,079
Slide 32: Marketing Highlights and Liquids Realizations
Marketing Highlights and Liquids Realizations Marketing Highlights Natural Gas Liquids, Oil and Condensate ▪ Directly-marketed ethane volumes were 273,000 ▪ Q4 2019 liquids sold: 10.5 Bcfe barrels in Q4 and, on an equivalent basis, yielded a ▪ Total weighted average price of all liquids decreased 20
Slide 33: Financial Guidance: 2020E Natural Gas Marketing Mix and Basis
Financial Guidance: 2020E Natural Gas Marketing Mix and Basis Volumes 2020E CY 2020 Northeast Pipeline Projects Market Gas Sold (%) Michcon (000 MMBtu) Basis 2020E Gas: 10% DOM South 42,496 8% ($0.44) CY20 Basis: ($0.18) ETNG Mainline 21,656 4% $0.20 DOM South TETCO M3 TCO Pool 79,382 14% ($0.33) 20
Slide 34: Natural Gas Hedging and Basis Protection
Natural Gas Hedging and Basis Protection 550 500 Gas Volumes Hedged (Bcf) 450 400 CNX’s substantial 350 300 hedge book de-risks 250 490.8 200 417.0 rates of return and 150 100 281.0 creates time to adjust 164.7 147.7 50 development plans 0 2020 2021 2022 (2) 2023 2024 and protect the NYMEX + Basis (
Slide 35: Q1 2020 and 2020 Gas Hedging Gain/Loss Projections
Q1 2020 and 2020 Gas Hedging Gain/Loss Projections Q1 2020 CY2020 Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted (2) Hedged Volumes Hedged Forward Gain/(Loss) Hedged Volumes Hedged Forward Gain/(Loss)(2) (000 MMBtu) Price Market(1) ($ in 000s) (000 MMBtu) Price Market(1) ($ in 000s) ($/MMBtu) N
Slide 36: 2020 AMT Credit and Additional Refunds
2020 AMT Credit and Additional Refunds December 31, December 31, 2019 2018 Current Assets $138 million of AMT and other tax refunds Cash and Cash Equivalents $ 16,283 $ 17,198 Accounts and Notes Receivable received in 2019 Trade 133,480 252,424 Other Receivables 13,679 11,077 Supplies Inventories 6,
Slide 37: 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 Normalized to 7000’ 100% 16,000 90% 14,000 Cumulative Production (MMcf) 12,000 80% 10,000 70% % of Initial Reservoir Pressure 8,000 60%
Slide 38: 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) Assuming a run rate of 36 1,400,000 SWPA Central Marcellus TILs per year: 1,200,000 CNX maintains ~12 years of core inventory after YE2020 1,000,000 CNX maintains approximatel
Slide 39: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended December 31, 2019 2018 2019 2018 (1) (1) Stand-alone Stand-alone Total Company Total Company ($ in thousands) Net (Loss) Income from EBITDAX Reconciliation ($287,970) $90,106 ($240,055) $129,415 Adjustments Total Pre-tax Adjustments from EBITDAX Reconciliat
Slide 40: Non-GAAP Reconciliation
Non-GAAP Reconciliation Price and Cost Data per Mcfe ($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 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 $ 2.51 $ 2.54 Lease Operating Expens
Slide 41: Non-GAAP Reconciliation
Non-GAAP Reconciliation Twelve Months Ended December 31, 2019 2019 2019 Stand-alone(1) Midstream Total Company ($ in thousands) Net (Loss) Income ($134,706) $166,654 $31,948 Interest Expense 121,054 30,325 151,379 Interest Income (1,915) (34) (1,949) Income Tax Expense 27,736 - 27,736 Earnings Befor
Slide 42: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended December 31, 2019 2019 2019 Stand-alone(1) Midstream Total Company ($ in thousands) Net (Loss) Income ($287,970) $47,915 ($240,055) Interest Expense 29,372 7,679 37,051 Interest Income (66) (12) (78) Income Tax Benefit (50,398) - (50,398) Earnings Before In
Slide 43: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended December 31, 2018 2018 2018 Stand-alone(1) Midstream Total Company ($ in thousands) Net Income $90,106 $39,309 $129,415 Interest Expense 26,471 6,751 33,222 Interest Income 1 - 1 Income Tax Expense (23,713) - (23,713) Earnings Before Interest & Taxes (EBIT)
Slide 44: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Three Months Three Months Three Months Twelve Months Ended Ended Ended Ended Ended March 31, June 30, September 30, December 31, December 31, ($ in thousands) 2019 2019 2019 2019 2019 Net (Loss) Income ($64,651) $192,694 $143,960 ($240,055) $31,948 Interest Expen