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  Economics : Break-Even

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Definitions and Footnotes 1) 900MM includes share repurchases settled and share repurchases h. EOG: no published return of capital framework; debt repayment and 15) 2022E hedge sensitivities based on company disclosures executed with settlement pending special dividends 16) 772MM of share repurchases executed in 4Q21, of which 724MM i. HES: up to 75% of adjusted FCF through base dividend and share 2) 4.5B of expected 2022 adjusted FCF at 100/bbl WTI, 6.00/MMBtu was cash settled repurchases HH, and U.S. NGL realizations at 37% of WTI comprised of 6B of net j. MUR: no published return of capital framework 17) 2030 Implied GHG Emissions Intensity Goals based on most recent cash provided by operating activities adjusted for working capital less peer disclosures. 2030 targets disclosed for COP, DVN, MUR, OVV, 1.3B of capital expenditures (accrued). Dividing 1.3B by 6B 7) Includes (213)MM of changes in operating working capital and 16MM and PXD. 2030 values implied via interpolation between mid-term and equates to a reinvestment rate of 20%. of working capital changes associated with investing activities net zero targets for EOG, XOM, OXY, and CVX. Held near/mid-term 3) Capital efficiency defined as cumulative 12 month 20:1 mboe per total 8) Greenhouse Gas (GHG) intensity: as measured by scope 1 and 2 targets flat to 2030 for companies which did not disclose longer-term well cost (TWC) estimate sourced from Enverus; Data set limited to metric tonnes carbon dioxide equivalent (CO2e) emissions per objectives (FANG, HES, APA, CLR). FANG, EOG, and CLR disclosures U.S. L48 horizontal oil wells with first production in 2018 or later, 12 thousand barrels of oil equivalent of hydrocarbons produced from and targets only include scope 1 emissions; all other peers include months of production data and a TWC estimate from Enverus, and Marathon Oil-operated facilities. All percentage reductions are relative scope 1 and 2 emissions lateral length of at least 2,000 ft. to 2019 GHG emissions intensity 18) Global top decile emissions intensity based off IEA data set: IEA, 4) WTI breakeven price assumes 3.00/MMbtu HH 9) Excludes Oklahoma JV rigs and frac crews; minimal MRO capital Spectrum of the well-to-tank emissions intensity of global oil production, exposure 2019, IEA, Paris https://www.iea.org/data-and- 5) Total Recordable Incident Rate (TRIR) measures combined employee 10) Adjusted FCF Yield assumes market capitalization as of 05/02/2022 statistics/charts/spectrum-of-the-well-to-tank-emissions-intensity-of- and contractor workforce incidents per 200,000 hours global-oil-production-2019; upstream excludes Refining and refined 6) Peer CFO returns based on FactSet consensus estimates and market 11) Gas Capture Percentage: the percentage by volume of wellhead natural Product Transport source categories capitalization as of 05/02/2022, MRO estimates, and company gas captured upstream of low pressure separation and/or storage disclosed return of capital frameworks; equipment such as vapor recovery towers and tanks 19) Relative to 2020 before temporary reductions Peer Return of Capital Framework Assumptions: 20) RSUs are restricted stock units; TSR PSUs are relative total 12) Methane intensity: as measured by metric tonnes carbon dioxide shareholder returns performance stock units; FCF PSUs are free cash a. APA: at least 60% of FCF to dividends & buybacks equivalent (CO2e) emissions per thousand barrels of oil equivalent of flow performance stock units b. COP: minimum 30% of CFO to shareholders through base dividend, hydrocarbons produced from Marathon Oil-operated facilities. All stock buyback, and variable dividend 21) Governance risk rating score of 3 based on September 1, 2021 ISS percentage reductions are relative to 2019 Methane emissions intensity Governance Quality Score c. DVN: variable dividend of up to 50% of post base dividend FCF; 13) Cumulative adjusted FCF of 8.0B comprised of 14.0B of net cash 2B buyback program authorized through May 2023 22) Excludes G&A expense provided by operating activities adjusted for working capital less 6.0B d. FANG: 50% of FCF to debt reduction; 50% of FCF to shareholders of capital expenditures (accrued). Dividing 6.0B by 14.0B equates e. OVV: 25% of post base dividend FCF to shareholders; increases to to a reinvestment rate of 40% 75% after net debt target reached 14) Cumulative adjusted FCF of 11.5B comprised of 17.5B of net cash f. PXD: variable dividend up to 75% of post base dividend FCF; opportunistic buybacks provided by operating activities adjusted for working capital less 6.0B of capital expenditures (accrued). Dividing 6.0B by 17.5B equates g. CLR: no published return of capital framework to a reinvestment rate of 35% 33
Marathon Oil Corp
May 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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