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Type Curves
Cotton Valley
  Economics : Type Curve

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2019 Updated Guidance(1) 4Q 2019 Guidance 2019 Updated Guidance Oil & Condensate Production (MMBbl) 5.7 - 6.0 21.6 - 21.9 Gas Production (Bcf) 7.9 - 8.4 32.4 - 32.9 NGL Production (MMBbl) 1.3 - 1.5 5.0 - 5.2 Total oil equivalent production (MMBoe) 8.3 - 8.9 32.0 - 32.6 Lease operating expense and Adjusted Transportation & Processing Costs (per Boe) 8.50 - 9.25 Depletion, depreciation and amortization (per Boe) 16.75 - 17.75 Production and property taxes (% of field-level revenue) 7.5% (in millions) Total G&A expense (2) 155 - 165 Less: Special G&A expense (3) 54 Total G&A expense (excluding Special G&A) 101 - 111 Capital investment (excluding property acquisitions) Drilling, Completion and Equip(4) 515 - 530 (5) Midstream Infrastructure 50 Corporate 2 Total Capital Investment (excluding property acquisitions) 101 - 116 567 - 582 Wells put on production (net) 3 65 (1) As of October 23, 2019: The Companys fourth quarter and full year 2019 guidance assumes: (1) an oil price of 55 per barrel and a natural gas price of 2.50 per MMBtu, (2) that QEP will elect to recover ethane from its produced gas in the Permian Basin where processing economics support it, (3) no additional property acquisitions or divestitures, other than those already disclosed, (4) includes approximately 10 days of production activity in the Haynesville / Cotton Valley, and (5) the impact of lower flare volume and higher gas and NGL capture in the Permian Basin. (2) The mid-point of G&A expense includes approximately 26.0 million of expenses related to non-cash, share-based compensation and other mark-to-market liabilities. Because these mark-to-market liabilities fluctuate with stock price changes, the amount of actual expense may vary from the forecasted amount. (3) Special G&A expense also includes approximately 54.0 million of estimated expenses associated with our strategic initiative process, primarily related to severance and retention programs, and includes approximately 11.0 million of accelerated shared-based compensation expense that is included in the 26.0 million of expenses related to non-cash, share-based compensation and other mark-to-market liabilities. (4) Drilling, Completion and Equip includes approximately 20.0 million of non-operated well costs. (5) Includes capital expenditures in the Permian Basin associated with (a) water sourcing, gathering, recycling and disposal and (b) crude oil and natural gas gathering systems. 4
QEP Resources, Inc.
October 2019

N. LA 2018 Combined Lower Cotton Valley Production Forecast 4000 3500 3000 2500 MCFED / 1,000' LL 2000 1500 1000 500 0 0 100 200 300 400 500 600 700 Days On Offset Normalized Production CVCombined Combo TCLower Cotton Valley TC 36
Range Resources Corp
December 2018

Continued 3rd Bone Spring Sand Execution Red Rock A Unit T09H and U04H Test Overview Cumulative Oil Production (Mbo) 40 Red Rock A Red Rock A Confirmation well in the 3rd Bone Spring Unit T09H Unit U04H Sand following the successful Weaver C T34H result from Q1 2018 Formation 3rd BS Sand Upper WC A 35 Lateral Length 10,500 11,300 Avalon Initial co-development test of the % in-zone 95% 100% Wolfcamp Upper A (Red Rock U04H) and IP-30 (Boe/d) 1,578 1,268 1st Bone 3rd Bone Spring Sand (Red Rock T09H) 30 % Oil 72% 74% Spring Sand IP-30 (Bo/d) 1,143 940 Cumulative oil production (Mbo) 440 lateral spacing and 200 vertical 2nd Bone spacing between wells 25 Spring Shale Wells drilled 95+% in-zone 2nd Bone Spring Sand Initial production results in-line with FY 20 2017 extended lateral average and 3rd Bone support larger scale development Spring Carb 15 3rd Bone Spring Sand 10 Upper Wolfcamp A 5 Lower Red Rock 9H Wolfcamp A 3rd Bone Spring Sand 0 Wolfcamp B Upper Red Rock 4H 200+ 0 5 10 15 20 25 30 Wolfcamp A Days on Production 440 Wolfcamp C Red Rock A Unit T09H Red Rock A Unit U04H 6
Permian Resources Corp.
August 2018
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