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  Economics : Rates of Return/ IRR

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Bakken Significant inventory of high return locations Future Locations with IRRs at 15% or Above 2021 Bakken Development Well Plan Gross number of economic locations at various WTI prices1 Beaver Goliath East 3rd rig Sep 2021 1,600 future locations Lodge Nesson and 50 rig years at 50/bbl WTI 2,500 2,400 2,200 Capa 50 new wells online in 2021 1,600 Keene Continued focus on maximizing 800 DSU value Beaver Lodge / Keene East Nesson Capa / Goliath WTI 40/bbl 50/bbl 60/bbl 70/bbl 80/bbl EUR (MBOE) 1,450 1,200 1,150 IP180 Oil (MBO) 150 125 105 Rig IRR (%)2 100% 85% 75% 27 53 73 80 83 Years1 2021 wells online 10 20 20 Table values approximate. Optimized well spacing and completionshigher DSU NPV higher asset value (1) Point forward January 2021, locations generating 15% after tax return. Assumes 30 wells/rig/year. Operating cost assumptions include Hess net tariffs and field G&A. (2) At 50/bbl WTI. 17
Hess Corp
September 2021

2021 guidance, operating statistics and well economics 2021 GUIDANCE(1) WELL ECONOMICS E&D capital spending (CMM)(2) 360-400 BAKKEN - FORT BERTHOLD(1) Total production (Mboe/d) 112-115 WTI oil price US50/bbl US60/bbl Liquids production (Mbbl/d) 69.5-71.5 Payout 1.5 years 0.9 years IRR: 60% 100%+ Avg. royalty & production tax rate 26% Breakeven (10% IRR) US38/bbl WTI Operating expense (/boe) 8.25 MARCELLUS(2) Transportation expense (/boe) 3.85 NYMEX natural gas price US3.00/Mcf US3.50/Mcf Cash G&A expense (/boe) 1.25 Payout 2.0 years 1.4 years Current income tax expense (USMM) 5-7 IRR 50% 90% Bakken oil price differential compared to WTI (US/bbl) (2.35) Breakeven (10% IRR) US2.30/Mcf NYMEX Marcellus natural gas price differential compared to NYMEX (US/Mcf) (0.65) 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. 2) Marcellus well economics are based on the average 2P reserves booked per undeveloped location (18 2021 ASSET DETAILS(3) BAKKEN MARCELLUS CANADA DJ BASIN Bcf/well, 7,400 ft lateral) and a total well cost of US6.3MM. Capital allocation (approx.)(2) 76% 12% 6% 6% Wells drilled (gross) 19-23 54-66 2 - (99% WI) (5% WI) (15% WI) Wells online (gross) 42-50 64-72 2 3 (80% WI) (7% WI) (15% WI) (87% WI) 1) Guidance has not been adjusted for Williston Basin divestment announced Aug 30, 2021 (3 MBOE/d). Closing end of October 2021. 19 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
September 2021

Click toContinues Bakken edit Master title style to Deliver as Economic Potential Expands Continued Repeatability from Bakken Wells 4Q20 Wells Performing in Line with Prior Years Projecting Consistent Well Results in 2021 Step-Outs Expanding Bakken Potential 5 Unit Wells Outperforming Legacy Well Economics Exceeding 30% ROR at 50 WTI 6.4 MM Average CWC per Well Southern Step Out Unit 1. Normalized to 10,000 Lateral Length. PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLY 8
Continental Resources, Inc.
February 2021

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