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  Economics : Type Curve

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Assumptions Louisiana 4,600' Lateral Type Curve 100,000 Avg Daily Production (Mcfpd) EUR 13 Bcf (2.8 Bcf/1,000) 10,000 Sales Gas BTU Price 1.020 Adjustment 1,000 Pricing Average - NYMEX less 0.20 / MMBtu Differentials/ Transportation: 0.30 / Mcf Transportation 100 Fixed Opex Fixed Opex: 3,000 / month 0 20 40 60 80 100 120 Months Variable Opex 0.05 / Mcf 4,600' Lateral Severance Tax Severance Tax Abatement Until Payout (Assumed at 12 months), R Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex) thereafter 0.09 / Mcf IRRs Based on Composite Curve from Actual Results EUR Capex Ad Val Tax 0.03 / Mcf (Mmcfe) (M) 90% 100% 110% 90% 100% 110% Royalty Burden 27.0% 2.50 62% 84% 109% 2.50 111% 84% 64% 2.75 88% 117% 152% 2.75 155% 117% 91% Gas Price D&C Capex 7.2 MM 3.00 118% 158% 204% 3.00 209% 158% 122% Facilities/Tubing 3.25 154% 206% 268% 3.25 275% 206% 159% 0.200 MM, included in D&C Capex Capex 3.50 197% 263% 346% 3.50 355% 263% 203% Spud to 1st Sale 60 Days Ownership: WI 100% - NRI 73% PV10 Pricing: Flat Pricing 9.3 Million (Post Capex) (3.00/Mcf Pricing) AFE: Two well pad. Economic EURs vary depending on gas price assumptions. 11
Goodrich Petroleum Corp.
November 2021

Top Tier Well Results Haynesville 7,500 Well Performance(1) Relative to Peers Mid-Bossier 7,500 Well Performance(1) Relative to Peers Top Haynesville rock quality Ideal location for Mid-Bossier co- Superior inventory development 1,750 1,750 Best recoveries in trend Robust economics 1,500 1,500 Top-tier Mid-Bossier performance Vine Vine Cumulative Gas (MMcf/1,000') Cumulative Gas (Mmcf/1,000') 1,250 1,250 1,000 1,000 750 750 500 500 250 250 0 0 0 6 12 18 24 0 6 12 18 24 Normalized Month Months Online With Lower Variability Vine Haynesville & Mid-Bossier Core(2) Marcellus Dry Gas Core(2) P1 Vine P2 SW Marcellus Haynesville P5 P10/P90 = 2.3x P10/P90 = 1.4x P10 Cumulative Probability P20 Shallower slope Vertical slope indicates P30 indicates higher repeatability P40 lower repeatability P50 Low P10/P90 variance P60 Higher P10/P90 exhibits low variability P70 variance exhibits more P80 variability Vine P90 Mid-Bossier P95 NE Marcellus P10/P90 = 1.6x P98 P10/P90 = 3.1x P99 100 1,000 10,000 Source: Enverus as of 11/24/2020. 10 S IMPLE . P URE . F OCUSED . (1) (2) Wells turned-in-line since 2017 normalized to 7,500 lateral. Wells turned-in-line since 2017; Vine Core includes Burgundy & Red Haynesville and Blue & Green Mid-Bossier trend areas, Marcellus Core includes Enverus-defined Core and Tier 1 Dry Gas sub-plays.
Vine Energy Inc.
April 2021

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
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