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  Economics : Rates of Return/ IRR

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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

Appalachia: Overview Miles 0 4 8 Acres PDP Well Count PDP Decline 1Q21 Activity 540,000 Op: 963 2020 TILs: 53% Wells drilled: 16 40% WI, 35% NRI Non-Op: 292 Field: 23% (5-yr avg) Wells TILd: 18 2021E Production Outlook 2021E EBITDAX Outlook 2021E Capital Plan 1,052 1,061 1,061 1,061 653 Appalachia Gulf Coast South Texas Brazos Valley Powder River Basin 2.25 2.50 2.75 3.00 TOTAL (2) Development Locations (PV-20) (2) Development & Appraisal Locations (PV-0) (1) 20% ROR at current spacing assumption, proven development zones. (2) Location counts do not include exploration wells or zones still in early evaluation. 1Q 2021 Earnings May 12, 2021 10
Chesapeake Energy Corp
May 2021

Consolidating the Core of Appalachia Acquisition provides EQT exposure to most of the remaining core Lower Marcellus inventory in NEPA Assets complement EQTs leading SWPA position and AVERAGE WELL PERFORMANCE BY PLAY(1) PREMIER GAS PLAYS already deep combo-development inventory 3.0 Chesapeake (Alta non-op) operates the best geology in NEPA with significant remaining Lower Marcellus inventory 2.7 Bcfe/1000 2.0 2.2 1.9 High margin operated production provides drilling 1.0 economics competitive with, and even superior to, Chesapeake operated acreage 0.0 NEPA Marcellus SWPA Marcellus Haynesville NON-OP INTERESTS ACROSS THE MOST PRODUCTIVE ROCK(1,2) OPERATED ASSETS DELIVER SUPERIOR ECONOMICS 1.4 100% Cum Production - Bcfe/1000 1.2 Non-op Non-op 1.0 75% BTAX IRR 0.8 50% 0.6 0.4 COG 25% CHK (Alta Non-Op) 0.2 COG - By Well CHK Non-Op - By Well 0.0 0 6 12 18 24 30 36 Alta Operated CHK Operated Alta Operated CHK Operated Months on Production - Tier 1 Core - Tier 2 - Tier 1 1. Source: Enverus 7 2. Represents wells turned-in-line during 2018 and onward.
EQT Corp
May 2021

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