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  Economics : Rates of Return/ IRR

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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

2021 guidance, operating statistics and well economics 2021 ANNUAL GUIDANCE(1) Q4 2021 GUIDANCE WELL ECONOMICS E&D capital spending (CMM)(2) 380 BAKKEN - FORT BERTHOLD(1) Total production (Mboe/d) 113.75-114.75 Total production (Mboe/d) 124.5-128.5 WTI oil price US50/bbl US60/bbl Liquids production (Mbbl/d) 69.75-70.75 Liquids production (Mbbl/d) 80-83 Payout 1.5 years 0.9 years Operating expense (/boe) 8.80 Operating expense (/boe) 8.80 IRR: 60% 100%+ Cash G&A expense (/boe) 1.15 Breakeven (10% IRR) US38/bbl WTI Transportation expense (/boe) 3.85 MARCELLUS(2) Avg. royalty & prod. tax rate 26% NYMEX natural gas price US3.00/Mcf US3.50/Mcf Current income tax expense (USMM) 3 Payout 2.0 years 1.4 years Bakken oil price diff. vs WTI (US/bbl) (2.00) IRR 50% 90% Marcellus natural gas price diff. vs NYMEX (US/Mcf) (0.55) Breakeven (10% IRR) US2.30/Mcf NYMEX 1) Fort Berthold well economics are based on the average 2P reserves booked per undeveloped location for a 2-mile lateral (730 mboe) and a total well cost of US5.7MM. 2021 ASSET DETAILS(3) BAKKEN MARCELLUS CANADA DJ BASIN 2) Marcellus well economics are based on the average 2P reserves booked per undeveloped location (18 Bcf/well, 7,400 ft lateral) and a total well cost of US6.3MM. Capital allocation (approx.)(2) 80% 10% 5% 5% 18-20 66-72 2 Wells drilled (gross) - (99% WI) (4% WI) (15% WI) 50 77-83 2 3 Wells online (gross) (80% WI) (6% WI) (15% WI) (87% WI) 1) Guidance has been adjusted for Williston Basin divestment which closed Nov 2, 2021 . 21 2) Capital spending includes capitalized G&A. 3) Wells drilled and completed are based on operated activity only except for the Marcellus and Canada which include non-operated activity.
Enerplus Corp
December 2021
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