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  Economics : Rates of Return/ IRR

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Marcellus: Premium Scale, Leading Returns 0 3 6 12 Asset overview 1Q22 2Q22E FY22E Miles Net Production (bcf/d) 1.45 1.85 1.95 1.9 2.0 Wells Drilled 14 24 28 80 95 Wells TILd 17 24 28 80 95 Average LL (feet) 11,000 PDP Decline (5 year) 20% 2022 TIL Decline (1 year) 60% Cost assumptions (net) 1Q22 2Q22E FY22E Differential to NYMEX (/mcf) (0.29) (0.50) (0.60) LOE (/mcf) 0.10 0.09 0.11 GP&T (/mcf) 0.55 0.55 0.65 Total Capital (mm) 64 140 150 425 525 22E Production Outlook 22E EBITDAX Outlook 22E Capital Plan 1,575 1,430 1,430 1,435 1,235 Operated Development Locations (PV-10)(1) Operated Development & Appraisal Locations (PV-0) (2) 2.25 2.50 2.75 3.00 Total (1) 10% ROR at current spacing assumption, proven development zones. Location Assumptions: Average Lateral Length = 9,800' (2) Location counts are based on existing acreage and do not include exploration wells or zones still in early evaluation. 1,300' 1,500' Average Spacing (4 WPS) 1Q22 Earnings May 4, 2022 6
Chesapeake Energy Corp
May 2022

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

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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