Economics : Break-Even

Showing 3 Results


(1) PREMIER, DIVERSIFIED ASSET BASE MARCELLUS 1 rig POWDER RIVER BASIN 4 rigs 1.60 2.20/mcf Breakeven Acreage 577,000 (86% Held) 4.7 million 25 35/bbl Breakeven Net acres Acreage 275,000 (72% Held) UTICA 2 rigs 1.35 1.80/mcf Breakeven Acreage 938,000 (87% Held) 13,300 Undrilled locations MID-CONTINENT 150 1 rig 30 40/bbl Breakeven TIL Count 125 Acreage 806,000 (97% Held) 100 75 50 HAYNESVILLE 25 3 rigs 2.00 2.50/mcf Breakeven Acreage 358,000 (90% Held) 0 Q1 2018 Q2 2018 Q3 2018 Q4 2018 EAGLE FORD Gulf Coast Rockies 4 rigs Appalachia North Appalachia South 30 40/bbl Breakeven Mid-Continent South Texas Acreage 245,000 (97% Held) (1) Net acreage at December 31, 2017 is proforma for announced Mid-Continent asset divestitures and excludes approximately 1.5 million of Other net acreage; 2018 estimated average rig count; PV10 breakeven with oil held flat at 55/bbl and gas held flat at 3/mcf Q4 2017 EARNINGS 6
Chesapeake Energy Corp
February 2018

Acquisition Further Extends Deep Inventory of Economic Locations Net Horizontal Locations by Area Inventory Breakevens (10% Pre-tax IRR) Net Locations(1) Net Locations Multiple decades of drilling 3,299 Net Locations 3,500 3,500 inventory across Eagle Ford and North Louisiana based 155 2,927 2,996 2,998 on net locations(1) 3,000 3,000 648 493 655 646 648 591 2,500 238 2,500 2,129 1,996 417 949 2,000 2,000 219 763 763 763 711 711 1,500 1,500 1,000 1,996 1,000 1,702 1,573 1,587 1,587 1,285 1,199 500 Existing Eagle Ford Locations 500 Acquisition Locations North Louisiana Locations 0 0 Eagle Ford Other RCT Other Total 35.00 / 2.00 45.00 / 2.50 55.00 / 3.00 65.00 / 3.50 EUR (91 Boe/ft) Locations Eagle Ford North Louisiana Existing Eagle Ford Acquisition North Louisiana Additional upside locations in: 130,000 Eagle Ford net acres with no locations assigned under evaluation Austin Chalk in Burleson County; Buda, Woodbine, Georgetown and Pecan Gap across much of our Eagle Ford acreage Northern Louisiana Additional Cotton Valley intervals 1. As of May 11, 2017, we identified 3,299 net horizontal drilling locations, which includes 949 locations associated with our pending acquisition. The locations were specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators across our acreage, combined with our interpretation of available geologic and engineering data. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Of our 3,299 estimated drilling locations, 201, 342 and 1,156 are associated with proved, probable and possible reserves as of December 31, 2016. Accordingly, 1,599 of these locations do not have any reserves assigned to them which includes 949 locations associated with the pending acquisition. There are no assurances that these 6 locations will perform like we expect. All of our assumptions with respect to our drilling locations, including estimated ultimate recoveries, expected costs to drill and complete, internal rates of return and economic break-even prices are speculative in nature and may prove to be inaccurate.
WildHorse Resource Development
June 2017

Single Well Economics Internal Type Curves NLA NLA NLA NLA Caddo Caddo Bossier ETX ETX ETX DeSoto X-Unit Standard X-Unit Shelby Highlander Highlander Unit Core Lateral Lateral Lateral HSVL HSVL BSSR 1 Target Lateral Length Ft 4,500 7,500 4,500 7,500 7,500 6,500 6,500 2 Gross Locations 20 46 23 168 63 57 65 3 Net Locations 9 12 9 78 25 13 17 4 WI % 43 25 37 46 39 23 26 5 NRI % 33 19 28 36 31 18 20 6 Spacing Acres 136 227 136 227 241 221 223 Type Curve 7 IP Mcf/d or Boe/d 14,000 17,600 13,200 10,900 9,300 11,500 9,500 8 Phase I Duration Month Month 16 16 16 12 12 18 16 9 Phase I B Factor x 0 0 0 0 0 0 0 10 Phase I Initial Decline % 50.00 40.00 52.00 41.00 22.00 22.00 22.00 11 Phase II Duration Month Month 10 10 10 14 15 54 56 12 Phase II B Factor x .6 .6 .6 .6 .6 .6 .6 13 Phase II Initial Decline % 51.04 51.82 51.04 36.77 41.60 41.60 40.81 14 Phase III Duration Month Month 16 16 16 16 9 24 24 15 Phase III B Factor x 1 1 1 1 1 1 1 16 Phase III Initial Decline % 42.33 42.33 42.33 37.42 38.83 24.73 24.73 17 Phase IV Initial Decline % 32.34 32.34 32.34 26.29 35.98 22.34 22.34 18 Terminal Decline % 6 6 6 6 6 6 6 19 Wellhead EUR Bcf/Mbo 9.9 14.9 8.9 12 11.3 14.1 11.7 20 EUR per 1,000 (lateral length) Bcf or Mbo 2.20 1.98 1.98 1.60 1.50 2.20 1.80 21 D&C/Pumping Unit MM 6.8 9.3 6.8 11.2 9.5 10.0 9.6 22 LOE Fixed /month 1,770 1,770 1,770 1,770 3,034 2,690 2,690 23 Variable/Gathering Expense /mcf,/bbl .02/.47 .02/.47 .02/.47 .02/.47 0.03/0.29 0.02/0.31 0.02/0.31 24 SWD Expense /mcf .03 .03 .03 .04 .05 .04 .04 Single Well Returns 25 NPV10 (8/8ths)1 MM 6.9 10.7 5.5 3.5 4.9 8.4 5.5 1 26 IRR % 100 100 95 26 40 62 42 27 Breakeven Flat Price (25%) /MMBTU or /BBL 2.33 2.23 2.49 3.23 2.86 2.46 2.78 28 PV/I, Disc x 2.03 2.16 1.82 1.32 1.52 1.85 1.58 1. Economics based on NYMEX futures prices as of December 30, 2016, including natural gas prices per MMBtu of 3.63 for 2017, 3.14 for 2018, 2.87 for 2019, 2.88 for 2020, 2.90 for 2021, 2.93 for 2022, 3.02 for 2023, 3.16 for 2024 and 3.31 thereafter. 13
Exco Resources Inc.
March 2017

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