Cnx Resources Corporation · NYSE:CNX
Cnx Resources — Q3 2019 Earnings Presentation
47 slides from Cnx Resources's earnings presentation, Oct 29, 2019
Slide 1: Earnings Results Third Quarter 2019
Earnings Results Third Quarter 2019 October 29, 2019
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: Major Highlights
Major Highlights Large, High Quality Inventory in the Core Marcellus and Utica Low Cash Costs Matters Even More in a Low Price Environment Strong Hedge Position Protects Future Cash Flows and Ensures Capital Returns On Track to Significantly Lower SG&A Increasing Free Cash Flow Despite Lower Commodi
Slide 4: 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 5: Low Production Cash Costs Create Competitive Advantage
Low Production Cash Costs Create Competitive Advantage 2.25 $2.15 TTM Q2/Q3 2019 Production Cash Costs per Mcfe(1) $1.70 CNX’s top-tier production cash 1.50 $1.25 $1.31 costs and $1.11 $1.15 substantial hedge book create a $0.78 $0.79 0.75 significant advantage in a weak natural gas pricing environm
Slide 6: Workflow Integration Driving Significant SG&A Savings
Workflow Integration Driving Significant SG&A Savings Consolidated PREVIOUS FY2018 Consolidated UPDATED Actual FY2019E Consolidated PREVIOUS $113M(1) Guidance FY2019E Consolidated UPDATED $110M(1) Guidance FY2020E Consolidated $100M(1) Guidance FY2020E $110M(1) Guidance $85M(1) UPDATED Stand-Alone ~
Slide 7: Substantial Hedges in 2020 and 2021 with Strongest Hedge Price
Substantial Hedges in 2020 and 2021 with Strongest Hedge Price 2020E(1) Hedged Gas Production 2021E(1) Hedged Gas Production 100 % $2.97 $3.00 100 % $3.00 91 % $ 2.93 94 % $2.87 $2.88 $2.90 2021E % of production $2.90 hedged increases to 80% 80 % 80 % 79 % $ 2.83 under a scenario of flat 76 % $2.79
Slide 8: Despite Weaker Gas Prices, Preserved FCF and Bolstered 2021 Inventory
Despite Weaker Gas Prices, Preserved FCF and Bolstered 2021 Inventory OLD 2020 FCF Guidance Q2 $135M Free Cash Flow Outside Changes NYMEX Declined in 2020 ($2.55 to $2.40 per MMBtu) & 2019 Management Changes Volumes Capital Costs NEW 2020 FCF Guidance Q3 $146M Free Cash Flow 2019 also improved: EBIT
Slide 9: 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 10: CNX Operations Update
CNX Operations Update
Slide 11: Q3 2019 Operational Results Summary
Q3 2019 Operational Results Summary Y/Y Q/Q ▪ Marcellus Shale cash production costs were $1.33 per Mcfe in Q3 ($/Mcfe) 3Q 2019 3Q 2018 Change 3Q 2019 2Q 2019 Change 2019, up $0.08 from $1.25 per Mcfe in Q3 2018, or a 6% increase (1) Average Sales Price $2.51 $2.92 ($0.41) $2.51 $2.63 ($0.12) ▪ Utica
Slide 12: SWPA Blending Strategy in Full Swing
SWPA Blending Strategy in Full Swing Damp Marcellus to Dry Outlets ▪ Maximize NAV by drilling high ROR Marcellus pads with enough Utica to blend into dry outlet ▪ Two SWPA dry Utica pads TIL'd in Q3 2019 - MAJ 6 (4 wells) - MOR 10 (3 wells) ▪ One SWPA dry Utica pad to TIL in Q1 2020 ▪ Only completin
Slide 13: Operational Highlights
Operational Highlights Drilling Highlights Evolution Frac Crew ▪ RHL 8 – 6 Well Marcellus Pad – High Operational Performance - Drilling days average of ~ 13 days per well - Drilling footage in lateral of an average of 5,891’ per day ▪ Most recent rig move from pad to pad of 2.75 days Completions Hig
Slide 14: Financial Results & Guidance Update
Financial Results & Guidance Update
Slide 15: Q3 2019 Financial Results Summary
Q3 2019 Financial Results Summary Quarter Quarter Quarter Quarter Ended Ended Ended Ended September 30, September 30, September 30, September 30, 2019 2018 2019 2018 % Increase/ % Increase/ ($ in millions, except per share data) Stand-alone Consolidated (Decrease) (Decrease) Adjusted Net (Loss) Inco
Slide 16: An Emphasis on Flexibility in Planning and Strategic Decisions
An Emphasis on Flexibility in Planning and Strategic Decisions CNX has taken a deliberate approach, focusing on flexibility to appropriately manage through the commodity cycle ◼ In the event of a sustained downturn in gas prices, CNX has the ability and discipline to reduce activity and preserve bal
Slide 17: Updated 2019 and 2020 Guidance
Updated 2019 and 2020 Guidance Previous UPDATED Previous UPDATED 2019E D&C capital based on midpoint expected to decrease by $17.5M from 2019E 2019E 2020E 2020E previous update, while production expected Capital Expenditures to increase 15 Bcfe Low High Low High Low High Low High ($ millions) Drilli
Slide 18: Updated 2019 and 2020 Guidance
Updated 2019 and 2020 Guidance 2019E 2020E Revenue and Other Operating Income E&P Consolidated E&P Consolidated Workforce Production Volumes: integration driving Natural Gas (Bcf) 500-508 505-535 NGLs (MBbls) 5,125-5,315 4,490-4,715 SG&A reductions Condensate (MBbls) 205-215 245-265 Total Production
Slide 19: Realignment Driving Expected Best-In-Class SG&A
Realignment Driving Expected Best-In-Class SG&A $300 TTM Q2/Q3 2019 SG&A(1) $0.20 Already realized ~$25 million in total $278 expected consolidated cash SG&A $0.18 savings out of the original $30 million $250 $0.16 target for 2020 ▪ Combined upstream and midstream Total SG&A Absolute Dollars ($M) $0
Slide 20: Production Cadence and Hedge Advantage 2019-2020
Production Cadence and Hedge Advantage 2019-2020 1.8 Expected Daily Production 2019-2020(1) 1.6 Five-year average all-in maintenance capital (D&C + 1.4 Average Hedged Volumes non-D&C): ~$400 million to 490 Bcf or 94% of gas production hedged at hold flat production of 550 1.2 NYMEX $2.97 in 2020 Bcf
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) $ 2.10 $ 2.20 $ 2.30 $ 2.40 $ 2.50 $ 2.60 $ 2.70 Each $0.10 move in 2020 NYMEX E&P Standalone price results in just a ~$5 mi
Slide 22: Prudent Thoughtful Financial Policy
Prudent Thoughtful Financial Policy ◼ Low cost-structure, robust hedge book, and planned capital program are positioning the company to deliver significant free cash flow in 2020 and beyond Overview ◼ Free cash flow expected to be deployed across three options: incremental 2020 activity at high inte
Slide 23: Highly Resilient Balance Sheet
Highly Resilient Balance Sheet Current Leverage (Net Debt + Off-Balance Sheet Obligations)(1) ($ in billions) $29 ▪ Flexibility through low total liability positioning in Appalachia Net Debt $21 Off-Balance Sheet Obligations ▪ Deliberate, strategic decision by management to avoid expensive FT contra
Slide 24: CNX Screens Well on All-In Debt Metrics vs. Appalachian Peers
CNX Screens Well on All-In Debt Metrics vs. Appalachian Peers Total Debt(1) as % of EV FT Commitments as % of EV Total Debt(1) + FT Commitments as a % of EV 85% 484% 82% 402% 77% 71% 67% 383% 316% 340% 58% 325% 268% 248% 218% 133% 102% 14% 43% 34% 20% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 CNX Peer 6 Pe
Slide 25: Appendix
CNX Appendix
Slide 26: Solid Financial and Operational Performance
Solid Financial and Operational Performance 1 Revenue Protection Active Long-term Cost Management 2 ▪ Active hedging program locks in revenue and de-risks ▪ Significant reduction to SG&A capital decisions prior to drilling ▪ Avoided expensive FT contracts that are now underwater ▪ ~94% total 2020E g
Slide 27: Q3 Activity Summary
Q3 Activity Summary Q3 2019 YTD 2019 Average Rigs at Lateral Period ($ in millions) TD FRAC TIL Length(1) End TD FRAC TIL ▪ Expect to run approximately two rigs SWPA Marcellus 11 10 10 11,169 1 34 29 32 Central and one frac crew in 2020 Utica 2 3 7 6,205 1 12 7 7 WV Marcellus 2 5 5 11,063 5 5 5 Shir
Slide 28: Marketing Highlights and Liquids Realizations
Marketing Highlights and Liquids Realizations Marketing Highlights Natural Gas Liquids, Oil and Condensate ▪ Directly-marketed ethane volumes were 262,000 ▪ Q3 2019 liquids sold: 8.1 Bcfe barrels in Q3 and, on an equivalent basis, yielded a ▪ Total weighted average price of all liquids decreased 51%
Slide 29: Financial Guidance: 2019E Natural Gas Marketing Mix and Basis
Financial Guidance: 2019E Natural Gas Marketing Mix and Basis Volumes 2019E CY 2019 Michcon Northeast Pipeline Projects Market (000 MMBtu) Gas Sold (%) Basis 2019E Gas: 10% DOM South 24,788 5% ($0.45) CY19 Basis: ($0.19) ETNG Mainline 6,504 1% $0.53 DOM South TCO Pool 85,618 16% ($0.33) TETCO M3 201
Slide 30: Financial Guidance: 2020E Natural Gas Marketing Mix and Basis
Financial Guidance: 2020E Natural Gas Marketing Mix and Basis Volumes 2020E CY 2020 Michcon Northeast Pipeline Projects Market (000 MMBtu) Gas Sold (%) Basis 2020E Gas: 9% DOM South 53,661 9% ($0.44) CY20 Basis: ($0.18) ETNG Mainline 23,235 4% $0.53 DOM South TCO Pool 77,272 14% ($0.36) TETCO M3 202
Slide 31: Natural Gas Hedging and Basis Protection
Natural Gas Hedging and Basis Protection 550 500 5.6 Gas Volumes Hedged (Bcf) 450 400 1.8 - CNX’s substantial 350 300 10.1 hedge book de-risks 250 200 403.4 484.0 414.2 rates of return and 2.5 150 100 268.0 creates time to adjust 50 142.1 development plans 0 2019 2020 2021 2022 2023 and protect the
Slide 32: Q4 2019E, 2019E, and 2020E Gas Hedging Gain/Loss Projections
Q4 2019E, 2019E, and 2020E Gas Hedging Gain/Loss Projections Q4 2019 CY2019 CY2020 Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted Wtd. Avg. Avg. Forecasted (2) (2) Hedged Volumes Hedged Forward Gain/(Loss) Hedged Volumes Hedged Forward Gain/(Loss) Hedged Volumes Hedged Forward Gain/(Loss)(2) (0
Slide 33: 2019 AMT Credit and Additional Refunds
2019 AMT Credit and Additional Refunds September 30, December 31, 2019 2018 Current Assets Cash and Cash Equivalents $ 5,484 $ 17,198 Combined AMT refund and additional tax refunds to Accounts and Notes Receivable drive total cash tax inflow of ~$138 million in 2019 Trade 96,997 252,424 Other Receiv
Slide 34: SWPA Marcellus: Increased Results and Efficiencies
SWPA Marcellus: Increased Results and Efficiencies Richhill (RHL) Marcellus – 2018 vs. Now Ohio River Water Line (to Richhill) 5.0 9000' Normalized Cumulative (Bcf) 4.0 3.0 2.0 1.0 0.0 - 50 100 150 200 250 300 350 400 450 500 Days 2018 RHL TC Current RHL TC 2018 TIL's 2019 TIL's ▪ Stage spacing was
Slide 35: 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’ 16,000 100% 14,000 90% Cumulative Production (MMcf) 12,000 80% 10,000 % of Initial Reservoir Pressure 70% 8,000 60%
Slide 36: 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 37: 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 $ in millions September 30, 2019 6.4 25.9 Stand-Alone Midstream Total 3.1 8.8 200.0 +1.7 1.0 Shares (millions) Total Long-Term Debt (GAAP) $2,000.3 $639.
Slide 38: YE2018 Type Curve Area and Acreage Update
YE2018 Type Curve Area and Acreage Update Note: As of year-end 2018 as identified in 2018 10-K filed February 7, 2019. 38
Slide 39: YE2018 Acreage and Undeveloped Location Update
YE2018 Acreage and Undeveloped Location Update MARCELLUS UTICA TYPE CURVE AREAS TYPE CURVE AREAS SWPA Central Greater TOTAL SWPA SWPA Central Greater TOTAL SWPA Total Net Acres 98,100 33,700 131,800 Total Net Acres 120,500 55,100 175,600 Net Developed Acres 28,300 2,400 30,800 Net Developed Acres 30
Slide 40: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended September 30, 2019 2018 2019 2018 (1) (1) Stand-alone Stand-alone Total Company Total Company ($ in thousands) Net Income from EBITDAX Reconciliation $102,219 $115,583 $143,960 $146,756 Adjustments Total Pre-tax Adjustments from EBITDAX Reconciliation (153,
Slide 41: Non-GAAP Reconciliation
Non-GAAP Reconciliation Price and Cost Data per Mcfe ($/Mcfe) Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 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 Lease Operating Expense $ 0.23 $ 0.23
Slide 42: Non-GAAP Reconciliation
Non-GAAP Reconciliation Twelve Months Ended September 30, 2019 2019 2019 Stand-alone(1) Midstream Total Company ($ in thousands) Net Income $243,371 $158,047 $401,418 Interest Expense 118,153 29,397 147,550 Interest Income (1,870) - (1,870) Income Tax Expense 54,421 - 54,421 Earnings Before Interest
Slide 43: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended September 30, 2019 2019 2019 (1) Stand-alone Midstream Total Company ($ in thousands) Net Income $102,219 $41,741 $143,960 Interest Expense 30,783 7,622 38,405 Interest Income (1,078) - (1,078) Income Tax Expense 48,902 - 48,902 Earnings Before Interest & T
Slide 44: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended September 30, 2018 2018 2018 Stand-alone(1) Midstream Total Company ($ in thousands) Net Income $115,583 $31,173 $146,756 Interest Expense 28,467 7,256 35,723 Interest Income (42) - (42) Income Tax Expense 56,678 - 56,678 Earnings Before Interest & Taxes (E
Slide 45: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended June 30, 2019 2019 2019 (1) Stand-alone Midstream Total Company ($ in thousands) Net Income $148,281 $44,413 $192,694 Interest Expense 32,467 7,685 40,152 Interest Income (71) - (71) Income Tax Expense 40,791 - 40,791 Earnings Before Interest & Taxes (EBIT)
Slide 46: Non-GAAP Reconciliation
Non-GAAP Reconciliation Three Months Ended Twelve Months Ended Stand-alone(1) March 31, June 30, September 30, December 31, December 31, ($ in thousands) 2018 2018 2018 2018 2018 Net Income $510,012 $33,614 $115,583 $90,106 $749,315 Interest Expense 36,062 31,320 28,467 26,471 122,320 Interest Incom
Slide 47: Non-GAAP Reconciliation
Non-GAAP Reconciliation Twelve Months Attributable to CNX Shareholders Three Months Ended Ended March 31, June 30, September 30, December 31, December 31, ($ 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