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  Economics : Break-Even

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Definitions and Footnotes 1) Annualized trailing 3 quarters shareholder distributions, divided by e. OVV: 25% of post base dividend FCF to shareholders; increases to 13) Includes 92MM of changes in operating working capital and 20MM of market capitalization as of 8/1/2022 75% after net debt target reached working capital changes associated with investing activities f. PXD: variable dividend up to 75% of post base dividend FCF; 2) 4.5B of expected 2022 adjusted FCF at 100/bbl WTI, 6.00/MMBtu 14) Gas Capture Percentage: the percentage by volume of wellhead natural opportunistic buybacks HH, and U.S. NGL realizations at 37% of WTI comprised of 6B of net gas captured upstream of low pressure separation and/or storage g. EOG: minimum 60% of FCF to shareholders through base dividend cash provided by operating activities adjusted for working capital less equipment such as vapor recovery towers and tanks and special dividend or opportunistic share repurchase 1.3B of capital expenditures (accrued). Dividing 1.3B by 6B h. CLR: no published return of capital framework 15) Methane intensity: as measured by metric tonnes carbon dioxide equates to a reinvestment rate of 20%. equivalent (CO2e) emissions per thousand barrels of oil equivalent of i. HES: up to 75% of adjusted FCF through base dividend and share 3) Assumes market capitalization as of 8/1/2022 repurchases hydrocarbons produced from Marathon Oil-operated facilities. All percentage reductions are relative to 2019 Methane emissions intensity 4) WTI breakeven price assumes 3.00/MMbtu HH j. MUR: no published return of capital framework 16) 2030 Implied GHG Emissions Intensity Goals based on most recent 5) Capital efficiency defined as cumulative 12 month 20:1 mboe per total 8) Excludes Oklahoma JV rigs and frac crews; minimal MRO capital well cost (TWC) estimate sourced from Enverus; Data set limited to peer disclosures. 2030 targets disclosed for COP, DVN, MUR, OVV, exposure and PXD. 2030 values implied via interpolation between mid-term and U.S. L48 horizontal oil wells with first production in 2018 or later, 12 9) Greenhouse Gas (GHG) intensity: as measured by scope 1 and 2 net zero targets for EOG, CVX, HES, OXY, and XOM. Held near/mid- months of production data and a TWC estimate from Enverus, and metric tonnes carbon dioxide equivalent (CO2e) emissions per term targets flat to 2030 for companies which did not disclose longer- lateral length of at least 2,000 ft. thousand barrels of oil equivalent of hydrocarbons produced from term objectives (APA, FANG, CLR). CLR, EOG, and FANG disclosures 6) Total Recordable Incident Rate (TRIR) measures combined employee Marathon Oil-operated facilities. All percentage reductions are relative and targets only include scope 1 emissions; all other peers include and contractor workforce incidents per 200,000 hours to 2019 GHG emissions intensity scope 1 and 2 emissions 7) Peer CFO returns based on FactSet consensus estimates and market 10) U.S. cash tax commentary based on tax law as of 8/3/2022 17) Global top decile emissions intensity based off IEA data set: IEA, capitalization as of 8/1/2022, MRO estimates, and company disclosed return of capital frameworks; 11) Cumulative adjusted FCF of 8.0B comprised of 14.0B of net cash Spectrum of the well-to-tank emissions intensity of global oil production, provided by operating activities adjusted for working capital less 6.0B 2019, IEA, Paris Peer Return of Capital Framework Assumptions: of capital expenditures (accrued). Dividing 6.0B by 14.0B equates statistics/charts/spectrum-of-the-well-to-tank-emissions-intensity-of- a. APA: at least 60% of FCF to dividends & buybacks to a reinvestment rate of 40% global-oil-production-2019; upstream excludes Refining and refined b. COP: minimum 30% of CFO to shareholders through base dividend, Product Transport source categories stock buyback, and variable dividend 12) Cumulative adjusted FCF of 11.5B comprised of 17.5B of net cash provided by operating activities adjusted for working capital less 6.0B 18) Excludes G&A expense c. DVN: variable dividend of up to 50% of post base dividend FCF; 2B buyback program authorized through May 2023 of capital expenditures (accrued). Dividing 6.0B by 17.5B equates to a reinvestment rate of 35% d. FANG: 50% of FCF to shareholders and 50% of FCF to debt reduction, increasing to 75%/25% from 3Q22 30
Marathon Oil Corp
August 2022

2020 Outlook Lowering Capital Spending Guidance Improved outlook underpinned by Delaware efficiencies 2020 CAPITAL ACTIVITY New Devon 2020e E&P capital E&P CAPITAL NEW WELLS ONLINE (MM) (Operated) Delaware Basin 1,050 (+15% YoY) 115-125 DELAWARE POWDER Powder River 350 45-55 60% RIVER 20% Eagle Ford 300 95-105(1) E&P CAPITAL +15% CAPITAL 1.70-1.85 STACK 75 (-75% YoY) 10 (VS. 2019) New Devon Total 1,700 - 1,850 BILLION (1) Average working interest for 2020 is 40-45%. Previous Guidance (1.7 - 1.9 billion) LOWERING top-end of 2020 capital guidance by 50 million Driven by improvements in Delaware costs & cycle times Low breakeven funding provides margin of safety (pg. 14) STACK EAGLE FORD Flexibility to tailor activity to market conditions 3% 17% WOLFCAMP success driving capital shift to Delaware (pg. 18) Activity targeting Wolfcamp to double in 2020 REALLOCATING CAPITAL TO DELAWARE BASIN Represents 65% of total Delaware drilling program Q4 2019 Operations Report 11
Devon Energy Corp
March 2020

3 Develop Liquids-Rich Locations Superior Economics vs Dry Gas Antero has significant core drilling inventory with breakeven natural gas prices around 2.00 per MMBtu due to the liquids pricing uplift received Natural Gas Breakeven Price by Region 25% ROR Half Cycle Breakeven Prices(1)(2) AR Locations AR Drilling Rigs Antero has 1,205 locations with a breakeven price averaging 2.07/MMBtu, which AR Undrilled Locations Industry Dry Gas Locations equates to over 10 years of inventory life at (2,623 Premium Locations) the current pace 4.00 Nat Gas Breakeven (/MMBtu) 3.50 3.27 3.34 3.18 3.00 2.79 2.85 2.87 2.40 (2020-2023 Strip) 2.50 2.37 2.07 2.23 2.00 1.50 1.00 0.50 1,205 Undeveloped <2.00 Locations 147 1,271 0.00 Permian / Bakken / DJ / Marcellus 1250+ Btu / NE Marcellus OH Utica Dry Marcellus WV Haynesville Ohio Utica Marcellus Haynesville Eagle Ford SCOOP/STACK Utica (Susquehana Gas 1050 Btu Dry 1050 Btu Core Long Dry Gas SW PA + WV Core Standard Dry 1235 - 1307 Btu County) / Rich Laterals Dry Laterals 1150 Btu Associated Gas (Oily) Appalachia Associated Production: Current Dry Gas Production From Lowest Cost Areas: Gas (NGLs): 19 Bcf/d 10 Bcf/d 41 Bcf/d 75% of current natural gas supply (3) Source: JP Morgan Equity Research breakeven analysis for best industry dry gas drilling locations as of October 2019. Excludes associated gas inventory with 50% liquids. Breakeven analysis for AR prepared by management and excludes AR hedges. AR drilling inventory as of 4/1/20. Assumes midpoint of well cost target range at 830/foot of lateral in the Marcellus. 1) Breakeven price is defined as half cycle pre-tax ROR of 25%. Assumes average 2020-2023 strip WTI oil price of 54.18/Bbl as of 12/31/2019 and C3+ NGL pricing of 27/Bbl for 2020 2023 and 30/Bbl thereafter. Assumes 830/ft budgeted Marcellus well costs. 2) AR half cycle well economics assume 12,000 lateral lengths and 71% of AM gathering and compression fees paid by AR to AM to account for ARs midstream dividend stream from AM (based on 29% ownership of AM). 3) Based on Platts current lower 48 dry marketed natural gas production of 93 Bcf/d at 12/31/2019. 12
Antero Resources
February 2020

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