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Rates Of Return
Bakken Shale
  Economics : Rates of Return/ IRR

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Long-Term Well Performance Delivering Strong Program Results 2023 vs. 2024 Program Highlights Oil Base Decline Rate Below Peer Average2 Conservative spacing and longer laterals support low decline rate Higher concentration of 3-mile wells in 2024 results in lower early time 44% per foot recovery vs. 2023 program; however, 42% 43% Well costs per foot 20% lower 3-mile vs 2-mile 40% 3-mile wells exhibit shallower declines 35% Average well performance at or above expectations 31% 2024 program IRRs comparable to 2023 program IRRs 2024 vs. 2023 Capital Efficiency1 Oil Bopd (per ft) / D&C (per ft) normalizes production rate to well cost A B C D E Cum. Bo (per ft) / D&C (per ft) normalizes recovery to well cost, inverse of F&D per bo Oil Productivity Outpaces Peers Over Time3 Oil Bopd (per ft.) / D&C (per ft.) Longer term production outperforms peers +15% 2023 Program 28% 3-mile 830 D&C/ft 2024 Program Early time production 40% 3-mile 24 program EUR in-line with peers comparable to 23 with lower 703 D&C/ft IPs but shallower decline and better capital efficiency Cum. Bo (per ft.) / D&C (per ft.) Williston Basin Williston Basin 2023 Program 2024 Program 3-Month Cum. (Bo/Ft) 12-Month Cum. (Bo/Ft) 1) Data includes Chord and Enerplus 2023 and 2024 vintage wells. Forecast reflects mgmt. type curve estimates. 3-mile wells reflect 150% EUR of 2-mile wells. D&C costs include AL2, winterization and impacts of design mix. Oil production and capital normalized to lateral length; 2) 8 Source: Enverus, reflects annual oil base decline rates through May 2024, peers include APA, CTRA, MRO, OVV and PR; 3) Source: Enverus, reflects 3Q23+ vintage wells lateral lengths between 12,500 17,499
Chord Energy
November 2024

Major Operating Area Economics US75 WTI & 3.50 AECO CORPORATE PRESENTATION IP30 boe/d EUR Mboe Cost Per Well Payout Area IRR% (Liquids %) (Liquids %) (CMM) (Months) Alberta Montney (Volatile Oil) Gold Creek West 1,025 (58%) 710 (54%) 9.0 125% 10 Gold Creek East 1,370 (57%) 1,245 (47%) 9.5 170% 8 Karr 700 (79%) 850 (76%) 10.5 180% 8 Kaybob Duvernay CRESCENT POINT Volatile Oil 700 1,000 (75%) 700 1,000 (65%) 10.5 140% 7 Liquids-Rich 1,000 1,500 (35 - 75%) 1,000 1,500 (35 65%) 11.0 160% 6 Lean Gas 1,500 (<35%) 1,500 2,000 (<35%) 11.5 75% 12 Viewfield Bakken 95 200 (90%) 60 160 (90%) 1.7 2.2 55 125% 9 16 Shaunavon 60 90 (90%) 60 115 (90%) 1.9 40 100% 11 22 Flat Lake - Torquay 105 140 (90%) 105 140 (90%) 3.4 50 100% 10 17 SK Conventional 80 130 (90%) 70 250 (90%) 1.5 65 175% 6 18 North Dakota Bakken 600 765 (90%) 460 560 (90%) US7.2 50 80% 9 13 All figures are approximates. Payouts are calculated from the initial onstream date. 20 Booked locations are proved and probable locations, as derived from the Companys internal reserves evaluation in accordance with NI51-101 and the COGE Handbook.
Crescent Point Energy Corp.
June 2023

Bakken Significant inventory of high return locations Future Locations with IRRs at 15% or Above 2023 Bakken Development Well Plan Gross number of economic locations at various WTI prices1 Tioga 2,000 future locations 4 rig program and 65 rig years at Goliath 70/BBL WTI 2,100 2,000 1,800 Stony Beaver East 110 new wells Creek Lodge / Nesson online in 2023 Capa 1,300 Keene Buffalo Continued focus Wallow on maximizing 700 DSU value Beaver Lodge / Keene / Stony Creek / Buffalo Wallow / Capa East Nesson / Goliath / Tioga 40/BBL 50/BBL 60/BBL 70/BBL 80/BBL EUR (MBOE) 1,300 1,150 WTI IP180 Oil (MBO) 130 115 Rig IRR 72 WTI(%) 100% 100% 23 43 60 67 70 Years1 2023 wells online 50 60 Table values approximate Optimized well spacing and completions higher DSU NPV higher asset value (1) Point forward January 2023, locations generating 15% after tax return. Assumes 30 wells/rig/year. Operating cost assumptions include Hess net tariffs and field G&A. 19
Hess Corp
June 2023
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