~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Exhibit 99.2 HighPoint Resources Cleansing Materials November 9, 2020~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Exhibit 99.2 HighPoint Resources Cleansing Materials November 9, 2020

~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Forward Looking Statements n HPR Forward Looking Statements All statements in this presentation, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Words such as expects, forecast, guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein; however, these are not the exclusive means of identifying forward-looking statements. In particular, the Company is providing 2020 Operating Guidance , which contains projections for certain operational and financial metrics. Additional forward-looking statements in this release relate to, among other things, future production, cash flows, capital expenditures, costs, projects and opportunities. These and other forward-looking statements in this press release are based on management's judgment as of the date of this release and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements. Please refer to HighPoint Resource's Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC, and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all of which are incorporated by reference herein, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you to consider the risks and uncertainties associated with projections and other forward-looking statements and to not place undue reliance on any such statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances 2~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Forward Looking Statements n HPR Forward Looking Statements All statements in this presentation, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Words such as expects, forecast, guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein; however, these are not the exclusive means of identifying forward-looking statements. In particular, the Company is providing 2020 Operating Guidance , which contains projections for certain operational and financial metrics. Additional forward-looking statements in this release relate to, among other things, future production, cash flows, capital expenditures, costs, projects and opportunities. These and other forward-looking statements in this press release are based on management's judgment as of the date of this release and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements. Please refer to HighPoint Resource's Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC, and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all of which are incorporated by reference herein, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you to consider the risks and uncertainties associated with projections and other forward-looking statements and to not place undue reliance on any such statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances 2

~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Undeveloped EURs & Inventory Summary (1) NE Watt Hereford Dev. Case #1 Hereford Dev. Case #2 Central Coffelt 70 Ranch Central T1 Niobrara T1 Codell T1 Niobrara T1 Codell Trans. Reduction EUR Summary Modeled Lat. Length ft 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 EUR, Wellhead Mboe 921 492 424 339 377 329 452 392 Oil Mbbl 311 294 258 207 261 262 313 312 Gas MMcf 3,663 1,189 992 793 696 403 835 479 Spacing Assumptions Spacing Wells/Mile 10 10 10 10 10 6 4 2 Economic Assumptions DC&F $ in millions $4.2 $4.2 $4.2 $4.2 $5.1 $5.1 $5.1 $5.1 (2)(3) Undeveloped Locations Gross Operated Count Total Dev. Case #1 107 12 2 85 4 1 3 - - Dev. Case #2 219 13 87 - 4 - - 56 59 Net Operated Count Dev. Case #1 71.5 8.1 1.7 54.8 3.0 1.0 3.0 - - Dev. Case #2 165.0 8.8 56.4 - 3.0 - - 52.9 43.8 Note: Inventory counts shown here reflect locations which are economic at 11/5 NYMEX Strip for Dev. Case #1 and 11/5 Wall St. Consensus pricing for Dev. Case #2. (1) Development Case #2 reflects up-spacing in Hereford to 4 Niobrara and 2 Codell wells per DSU with up-spaced type curves reflective of the modeled spacing. In NE Wattenberg, Central type curve applied to Central Transition location in Development Case #2 to reflect recent outperformance from Central Transition wells that are outperforming Dev Case #1 type curves. (2) Inclusive of DUC locations. (3) Tier 1 Codell undeveloped location count in Hereford Dev. Case #1 and Hereford Dev. Case #2 includes 3 gross / 3.0 net wells scheduled for completion in January 2023, for which only the intermediate casing has been drilled. 3~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Undeveloped EURs & Inventory Summary (1) NE Watt Hereford Dev. Case #1 Hereford Dev. Case #2 Central Coffelt 70 Ranch Central T1 Niobrara T1 Codell T1 Niobrara T1 Codell Trans. Reduction EUR Summary Modeled Lat. Length ft 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 EUR, Wellhead Mboe 921 492 424 339 377 329 452 392 Oil Mbbl 311 294 258 207 261 262 313 312 Gas MMcf 3,663 1,189 992 793 696 403 835 479 Spacing Assumptions Spacing Wells/Mile 10 10 10 10 10 6 4 2 Economic Assumptions DC&F $ in millions $4.2 $4.2 $4.2 $4.2 $5.1 $5.1 $5.1 $5.1 (2)(3) Undeveloped Locations Gross Operated Count Total Dev. Case #1 107 12 2 85 4 1 3 - - Dev. Case #2 219 13 87 - 4 - - 56 59 Net Operated Count Dev. Case #1 71.5 8.1 1.7 54.8 3.0 1.0 3.0 - - Dev. Case #2 165.0 8.8 56.4 - 3.0 - - 52.9 43.8 Note: Inventory counts shown here reflect locations which are economic at 11/5 NYMEX Strip for Dev. Case #1 and 11/5 Wall St. Consensus pricing for Dev. Case #2. (1) Development Case #2 reflects up-spacing in Hereford to 4 Niobrara and 2 Codell wells per DSU with up-spaced type curves reflective of the modeled spacing. In NE Wattenberg, Central type curve applied to Central Transition location in Development Case #2 to reflect recent outperformance from Central Transition wells that are outperforming Dev Case #1 type curves. (2) Inclusive of DUC locations. (3) Tier 1 Codell undeveloped location count in Hereford Dev. Case #1 and Hereford Dev. Case #2 includes 3 gross / 3.0 net wells scheduled for completion in January 2023, for which only the intermediate casing has been drilled. 3

~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Overview of Business Plan Scenarios Overview of Model Cases (3) Development / Business Plan Scenarios Gross Operated Well Count Development Case #1: Remaining operated DUC wells completed starting in March Operated Spud / TIL (1) 2021 with final well completed in January 2022 ; remaining non-operated DUC wells Dec'20 2021 2022 2023 2024 2025+ Total (2) completed in March-June 2021 ; measured operated development program commencing in Q4’21 focused on highest-return inventory at NE Wattenberg (average Tier 1 Nio - / - - / - - / 1 - / - - / - - / - - / 1 ~1 gross rig until Central and Central Transition type curve area inventory is exhausted) (4) Tier 1 Codell - / - - / - - / - - / 3 - / - - / - - / 3 with no development activity in Hereford Hereford Total - / - - / - - / 1 - / 3 - / - - / - - / 4 n Operated Development: (3)(4) □ 26 gross DUC wells 70 Ranch - / - - / 12 - / - - / - - / - - / - - / 12 □ 2 gross undeveloped locations in the Central type curve area Central - / - 2 / 2 - / - - / - - / - - / - 2 / 2 □ 79 gross undeveloped locations in the Central Transition type curve area Central Transition - / - 7 / 6 38 / 23 34 / 44 - / 12 - / - 79 / 85 n Non-Operated Development: Coffelt Reduction - / - - / 4 - / - - / - - / - - / - - / 4 (5) □ 19 gross DUC wells NE Wattenberg Total - / - 9 / 24 38 / 23 34 / 44 - / 12 - / - 81 / 103 Total Development - / - 9 / 24 38 / 24 34 / 47 - / 12 - / - 81 / 107 Development Case #2: DUC schedule / timing consistent with Development Case #1, followed by modestly accelerated operated development at NE Wattenberg (inventory (6) adjusted to reflect expansion of NE Watt Central type curve area ) and measured Operated Spud / TIL development of operated Tier 1 Hereford inventory commencing in Q1’23 (average ~1 Dec'20 2021 2022 2023 2024 2025+ Total gross rig until Tier 1 Codell and Tier 1 Niobrara type curve area inventory is exhausted); scenario reflects up-spaced type curves in Hereford Tier 1 (based on 2 Codell / 4 Nio Tier 1 Nio - / - - / 1 - / - 15 / 11 22 / 22 18 / 22 55 / 56 per DSU up-spacing) and NE Wattenberg Central type curve applied to Central Tier 1 Codell - / - - / - - / - 9 / 8 11 / 11 36 / 40 56 / 59 Transition locations Hereford Total - / - - / 1 - / - 24 / 19 33 / 33 54 / 62 111 / 115 n Operated Development: (3)(4) □ 27 gross DUC wells 70 Ranch - / - - / 13 - / - - / - - / - - / - - / 13 □ 81 gross undeveloped locations in the Central type curve area Central - / - 9 / 6 59 / 37 13 / 44 - / - - / - 81 / 87 □ 55 gross undeveloped locations in the Tier 1 Niobrara type curve area Central Transition - / - - / - - / - - / - - / - - / - - / - □ 56 gross undeveloped locations in the Tier 1 Codell type curve area Coffelt Reduction - / - - / 4 - / - - / - - / - - / - - / 4 n Non-Operated Development: NE Wattenberg Total - / - 9 / 23 59 / 37 13 / 44 - / - - / - 81 / 104 (5) Total Development - / - 9 / 24 59 / 37 37 / 63 33 / 33 54 / 62 192 / 219 □ 21 gross DUC wells Note: Dev. Case #1 excludes 1 operated and 2 non-operated DUC wells which are uneconomic at 11/5 NYMEX Strip pricing. (1) Excludes 3 wells scheduled for completion in January 2023, for which only the intermediate casing has been drilled. (2) Excludes 1 well with 0.05% WI which is anticipated to be completed in July 2022. (3) Excludes 7 PDP wells producing from ¼ of the lateral for which full completions are modeled. (4) Includes 3 wells for which only intermediate casing has been drilled. (5) Includes 2 wells with royalty interests only. (6) Recent pad development and comparable reservoir quality suggest that the Central type curve is applicable to wells drilled in the Central Transition type curve area when the appropriate completion design is executed. Development Case #2 expands the Central type curve area boundary to reflect these data points. This boundary encompasses all DUC wells and undeveloped locations contemplated in Development Case #2. 4 Development Case #2 Development Case #1~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Overview of Business Plan Scenarios Overview of Model Cases (3) Development / Business Plan Scenarios Gross Operated Well Count Development Case #1: Remaining operated DUC wells completed starting in March Operated Spud / TIL (1) 2021 with final well completed in January 2022 ; remaining non-operated DUC wells Dec'20 2021 2022 2023 2024 2025+ Total (2) completed in March-June 2021 ; measured operated development program commencing in Q4’21 focused on highest-return inventory at NE Wattenberg (average Tier 1 Nio - / - - / - - / 1 - / - - / - - / - - / 1 ~1 gross rig until Central and Central Transition type curve area inventory is exhausted) (4) Tier 1 Codell - / - - / - - / - - / 3 - / - - / - - / 3 with no development activity in Hereford Hereford Total - / - - / - - / 1 - / 3 - / - - / - - / 4 n Operated Development: (3)(4) □ 26 gross DUC wells 70 Ranch - / - - / 12 - / - - / - - / - - / - - / 12 □ 2 gross undeveloped locations in the Central type curve area Central - / - 2 / 2 - / - - / - - / - - / - 2 / 2 □ 79 gross undeveloped locations in the Central Transition type curve area Central Transition - / - 7 / 6 38 / 23 34 / 44 - / 12 - / - 79 / 85 n Non-Operated Development: Coffelt Reduction - / - - / 4 - / - - / - - / - - / - - / 4 (5) □ 19 gross DUC wells NE Wattenberg Total - / - 9 / 24 38 / 23 34 / 44 - / 12 - / - 81 / 103 Total Development - / - 9 / 24 38 / 24 34 / 47 - / 12 - / - 81 / 107 Development Case #2: DUC schedule / timing consistent with Development Case #1, followed by modestly accelerated operated development at NE Wattenberg (inventory (6) adjusted to reflect expansion of NE Watt Central type curve area ) and measured Operated Spud / TIL development of operated Tier 1 Hereford inventory commencing in Q1’23 (average ~1 Dec'20 2021 2022 2023 2024 2025+ Total gross rig until Tier 1 Codell and Tier 1 Niobrara type curve area inventory is exhausted); scenario reflects up-spaced type curves in Hereford Tier 1 (based on 2 Codell / 4 Nio Tier 1 Nio - / - - / 1 - / - 15 / 11 22 / 22 18 / 22 55 / 56 per DSU up-spacing) and NE Wattenberg Central type curve applied to Central Tier 1 Codell - / - - / - - / - 9 / 8 11 / 11 36 / 40 56 / 59 Transition locations Hereford Total - / - - / 1 - / - 24 / 19 33 / 33 54 / 62 111 / 115 n Operated Development: (3)(4) □ 27 gross DUC wells 70 Ranch - / - - / 13 - / - - / - - / - - / - - / 13 □ 81 gross undeveloped locations in the Central type curve area Central - / - 9 / 6 59 / 37 13 / 44 - / - - / - 81 / 87 □ 55 gross undeveloped locations in the Tier 1 Niobrara type curve area Central Transition - / - - / - - / - - / - - / - - / - - / - □ 56 gross undeveloped locations in the Tier 1 Codell type curve area Coffelt Reduction - / - - / 4 - / - - / - - / - - / - - / 4 n Non-Operated Development: NE Wattenberg Total - / - 9 / 23 59 / 37 13 / 44 - / - - / - 81 / 104 (5) Total Development - / - 9 / 24 59 / 37 37 / 63 33 / 33 54 / 62 192 / 219 □ 21 gross DUC wells Note: Dev. Case #1 excludes 1 operated and 2 non-operated DUC wells which are uneconomic at 11/5 NYMEX Strip pricing. (1) Excludes 3 wells scheduled for completion in January 2023, for which only the intermediate casing has been drilled. (2) Excludes 1 well with 0.05% WI which is anticipated to be completed in July 2022. (3) Excludes 7 PDP wells producing from ¼ of the lateral for which full completions are modeled. (4) Includes 3 wells for which only intermediate casing has been drilled. (5) Includes 2 wells with royalty interests only. (6) Recent pad development and comparable reservoir quality suggest that the Central type curve is applicable to wells drilled in the Central Transition type curve area when the appropriate completion design is executed. Development Case #2 expands the Central type curve area boundary to reflect these data points. This boundary encompasses all DUC wells and undeveloped locations contemplated in Development Case #2. 4 Development Case #2 Development Case #1

~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Detailed HPR Financial Projections Development Case #1 @ NYMEX Strip ($ in millions, unless otherwise noted) 2020E 2021E 2022E 2023E 2024E 2025E Benchmark Prices (NYMEX Strip) WTI ($/Bbl) $38.53 $41.06 $42.56 $43.34 $43.99 $44.69 HHub ($/MMBtu) $2.12 $3.02 $2.77 $2.54 $2.50 $2.51 (1) Gross / Net Wells TIL NE Wattenberg (Operated) 17 / 12 24 / 18 28 / 22 44 / 30 12 / 1 - / - Hereford (Operated) 7 / 7 - / - 3 / 3 3 / 3 - / - - / - Net Production Profile (MBoe/d) PDP 29.8 18.2 14.3 11.5 9.5 8.1 DUC - 2.8 3.7 2.6 1.5 1.1 Undeveloped - 0.0 4.0 9.6 7.8 4.2 Total Net Production 29.8 20.9 22.0 23.8 18.7 13.4 % Oil 55% 56% 58% 60% 55% 51% Revenue Commodity Revenue $245 $198 $223 $245 $186 $131 Hedging Gain / (Loss) 112 39 (0) - - - Total Revenue $357 $238 $222 $245 $186 $131 Operating Expenses Production Taxes ($1) ($11) ($13) ($15) ($11) ($8) LOE & Workover (34) (31) (29) (29) (27) (25) (2) (35) (18) (7) (6) (5) (4) GP&T Cash G&A (37) (28) (24) (20) (16) (14) (3) Other (2) - - - - - Adjusted EBITDAX $247 $149 $150 $175 $127 $81 Capital Expenditures NE Wattenberg - DC&F $76 $70 $98 $116 $4 - Hereford - DC&F 40 - 21 - - - (4) 3 2 2 2 2 2 Other Capex Total Capex $119 $72 $121 $118 $6 $2 Unlevered Free Cash Flow $128 $78 $29 $57 $121 $78 Cumulative Unlevered FCF $128 $206 $235 $292 $413 $491 Note: NYMEX Strip as of 11/5/2020. 2020E shown reflects full-year projections with actuals through September 2020. (1) Includes 7 PDP wells producing from ¼ of the lateral for which full completions are modeled. (2) Includes FT deficiency fees. (3) Includes gain / (loss) on sale of properties and dry hole & abandonment costs. (4) Includes asset retirement obligations. 5~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Detailed HPR Financial Projections Development Case #1 @ NYMEX Strip ($ in millions, unless otherwise noted) 2020E 2021E 2022E 2023E 2024E 2025E Benchmark Prices (NYMEX Strip) WTI ($/Bbl) $38.53 $41.06 $42.56 $43.34 $43.99 $44.69 HHub ($/MMBtu) $2.12 $3.02 $2.77 $2.54 $2.50 $2.51 (1) Gross / Net Wells TIL NE Wattenberg (Operated) 17 / 12 24 / 18 28 / 22 44 / 30 12 / 1 - / - Hereford (Operated) 7 / 7 - / - 3 / 3 3 / 3 - / - - / - Net Production Profile (MBoe/d) PDP 29.8 18.2 14.3 11.5 9.5 8.1 DUC - 2.8 3.7 2.6 1.5 1.1 Undeveloped - 0.0 4.0 9.6 7.8 4.2 Total Net Production 29.8 20.9 22.0 23.8 18.7 13.4 % Oil 55% 56% 58% 60% 55% 51% Revenue Commodity Revenue $245 $198 $223 $245 $186 $131 Hedging Gain / (Loss) 112 39 (0) - - - Total Revenue $357 $238 $222 $245 $186 $131 Operating Expenses Production Taxes ($1) ($11) ($13) ($15) ($11) ($8) LOE & Workover (34) (31) (29) (29) (27) (25) (2) (35) (18) (7) (6) (5) (4) GP&T Cash G&A (37) (28) (24) (20) (16) (14) (3) Other (2) - - - - - Adjusted EBITDAX $247 $149 $150 $175 $127 $81 Capital Expenditures NE Wattenberg - DC&F $76 $70 $98 $116 $4 - Hereford - DC&F 40 - 21 - - - (4) 3 2 2 2 2 2 Other Capex Total Capex $119 $72 $121 $118 $6 $2 Unlevered Free Cash Flow $128 $78 $29 $57 $121 $78 Cumulative Unlevered FCF $128 $206 $235 $292 $413 $491 Note: NYMEX Strip as of 11/5/2020. 2020E shown reflects full-year projections with actuals through September 2020. (1) Includes 7 PDP wells producing from ¼ of the lateral for which full completions are modeled. (2) Includes FT deficiency fees. (3) Includes gain / (loss) on sale of properties and dry hole & abandonment costs. (4) Includes asset retirement obligations. 5

~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Internal Reserve Report Summary 3/1/2021 Effective Date ($ in millions, unless otherwise noted) (1) Dev Case #1 @ NYMEX Strip Dev Case #2 @ WSC (2) Net Modeled Resource Locations Net DC&F NPV - 0% NPV - 10% NPV - 0% NPV - 10% Oil Gas NGL Equivalent Capex Gross Net (MMBbl) (Bcf) (MMBbl) (MMBoe) PDP (3) Operated 439 382 22.4 78.3 10.3 45.8 $38 $595 $373 $778 $475 Non-Operated 120 19 0.9 4.2 0.6 2.2 - 26 15 33 19 Total PDP 559 401 23.3 82.5 10.9 48.0 $38 $621 $388 $811 $494 DUC Operated 26 20 3.3 8.9 1.2 5.9 $60 $49 $26 $86 $49 Non-Operated 19 2 0.4 2.3 0.3 1.1 6 10 5 14 7 Total DUC 45 22 3.6 11.3 1.5 7.0 $66 $59 $31 $100 $56 Total Proved Developed 604 423 27.0 93.8 12.4 55.0 $104 $680 $419 $912 $550 Undeveloped Inventory NE Wattenberg (Operated) 81 51 10.6 26.3 3.5 18.5 $229 $185 $63 $357 $166 Hereford (Operated) - - - - - - - - - 599 251 Total Undeveloped Inventory 81 51 10.6 26.3 3.5 18.5 $229 $185 $63 $956 $417 E&P Asset Value 685 474 37.6 120.1 15.9 73.5 $333 $865 $482 $1,868 $967 Less: Ruby / WIC FT Deficiency Fees ($8) ($8) ($8) ($8) Pre-Tax, Pre-G&A Asset Total $857 $475 $1,860 $960 Note: Pricing as of 11/5/2020. Incremental Ruby / WIC FT deficiency fees presented separately since not included in reserves values shown. Note: PDP PV-0 values net of ARO of $25M and PDP PV-10 values net of ARO of $13M. (1) WSC in 2021-2023 and held flat thereafter. WSC pricing: $46/Bbl WTI | $2.70/MMBtu HHUB in 2021, $49.5/Bbl WTI | $2.70/MMBtu HHUB in 2022, $52/Bbl WTI | $2.78/MMBtu in 2023. (2) Reflects locations that are economic at 11/5/2020 NYMEX Strip in Dev Case #1. (3) PDP values shown net of incremental transportation costs to move NE Wattenberg oil volumes to Hereford to satisfy TPXP FT commitments and net of UET letter of credit support fees. Net DC&F capex shown inclusive of ARO of $25M. 6~ Strictly Confidential and Subject to Existing Confidentiality Agreement; Preliminary and Subject to Material Revision ~ Internal Reserve Report Summary 3/1/2021 Effective Date ($ in millions, unless otherwise noted) (1) Dev Case #1 @ NYMEX Strip Dev Case #2 @ WSC (2) Net Modeled Resource Locations Net DC&F NPV - 0% NPV - 10% NPV - 0% NPV - 10% Oil Gas NGL Equivalent Capex Gross Net (MMBbl) (Bcf) (MMBbl) (MMBoe) PDP (3) Operated 439 382 22.4 78.3 10.3 45.8 $38 $595 $373 $778 $475 Non-Operated 120 19 0.9 4.2 0.6 2.2 - 26 15 33 19 Total PDP 559 401 23.3 82.5 10.9 48.0 $38 $621 $388 $811 $494 DUC Operated 26 20 3.3 8.9 1.2 5.9 $60 $49 $26 $86 $49 Non-Operated 19 2 0.4 2.3 0.3 1.1 6 10 5 14 7 Total DUC 45 22 3.6 11.3 1.5 7.0 $66 $59 $31 $100 $56 Total Proved Developed 604 423 27.0 93.8 12.4 55.0 $104 $680 $419 $912 $550 Undeveloped Inventory NE Wattenberg (Operated) 81 51 10.6 26.3 3.5 18.5 $229 $185 $63 $357 $166 Hereford (Operated) - - - - - - - - - 599 251 Total Undeveloped Inventory 81 51 10.6 26.3 3.5 18.5 $229 $185 $63 $956 $417 E&P Asset Value 685 474 37.6 120.1 15.9 73.5 $333 $865 $482 $1,868 $967 Less: Ruby / WIC FT Deficiency Fees ($8) ($8) ($8) ($8) Pre-Tax, Pre-G&A Asset Total $857 $475 $1,860 $960 Note: Pricing as of 11/5/2020. Incremental Ruby / WIC FT deficiency fees presented separately since not included in reserves values shown. Note: PDP PV-0 values net of ARO of $25M and PDP PV-10 values net of ARO of $13M. (1) WSC in 2021-2023 and held flat thereafter. WSC pricing: $46/Bbl WTI | $2.70/MMBtu HHUB in 2021, $49.5/Bbl WTI | $2.70/MMBtu HHUB in 2022, $52/Bbl WTI | $2.78/MMBtu in 2023. (2) Reflects locations that are economic at 11/5/2020 NYMEX Strip in Dev Case #1. (3) PDP values shown net of incremental transportation costs to move NE Wattenberg oil volumes to Hereford to satisfy TPXP FT commitments and net of UET letter of credit support fees. Net DC&F capex shown inclusive of ARO of $25M. 6