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1 INVESTOR PRESENTATION MAY 2025
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2 •FORWARD-LOOKING STATEMENTS •The information in this presentation and in any oral statements made in connection herewith contains forward-looking statements that involve risks and uncertainties. When used in connection with this document, the words “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “intends,” “projects,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate” or the negative of such terms and similar expressions as they relate to HighPeak Energy, Inc. (“HighPeak Energy” or the “Company”) are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control. For example, the Company’s review of strategic alternatives may not result in a sale of the Company, a recommendation that a transaction occur or result in a completed transaction, and any transaction that occurs may not increase shareholder value, in each case as a result of such risks and uncertainties. •These risks and uncertainties include, among other things, the results of the strategic review being undertaken by the Company’s Board and the interest of prospective counterparties, the Company’s ability to realize the results contemplated by its 2025 guidance , volatility of commodity prices, political instability or armed conflict in crude oil or natural gas producing regions such as the ongoing war between Russia and Ukraine, the ongoing conflict between Israel and Hamas, OPEC+ policy decisions, potential new trade policies, such as tariffs, could adversely affect the Company’s operations, business and profitability, inflationary pressures on costs of oilfield goods, services and personnel, product supply and demand, the impact of a widespread outbreak of an illness, such as the coronavirusdisease 2019 (“COVID-19”) pandemic, on global and U.S. economic activity, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company’s drilling and operating activities, access to and availability of transportation, processing, fractionation, refining and storage facilities, HighPeak Energy’s ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to any credit facility and derivative contracts entered into by HighPeak Energy, if any, and purchasers of HighPeak Energy's oil, NGL and gas production, uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future, the assumptions underlying forecasts, including forecasts of production, expenses, cash flow from sales of oil and gas and tax rates, quality of technical data, environmental and weather risks, including the possible impacts of climate change, cybersecurityrisks and acts of war or terrorism. These and other risks are described in the Company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on March 10, 2025 (the “Annual Report”), and in its other filings with the SEC. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Risk Factors,” “Business,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk” in the Registration Statement for a description of various factors that could materially affect the ability of HighPeak Energy to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law. •RESERVE INFORMATION •Reserve engineering is a process of estimating the recovery of underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. Reserves estimates included herein may not be indicative of the level of reserves or PV-10 value of oil and natural gas production in the future. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact HighPeak’s strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from thequantities of oil and natural gas that are ultimately recovered. •Estimated Ultimate Recoveries, or “EURs,” refers to estimates of the sum of total gross remaining reserves per well as of a given date and cumulative production prior to such given date for developed wells. “Resource” refers to gross volumes of hydrocarbons without giving effect to recovery efficiency or the economic viability of production. Neither EURs nor resource constitute or represent reserves as defined by the SEC and neither is intended to be representative of anticipated future well results or aggregate production volumes. Each such metric is inherently more uncertain than proved reserve estimates prepared in accordance with SEC guidelines. •USE OF PROJECTIONS •The financial, operational, industry and market projections, estimates and targets in this presentation (including production, operating expenses, capital expenditures, EBITDAX and Free Cash Flow in future periods) are based on assumptions that are inherently subject to significant uncertainties and contingencies, many of which are beyond the Company’s control. The assumptions and estimates underlying the projected, expected or target results are inherently uncertain and are subject to a wide variety of significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the financial, operational, industry and market projections, estimates and targets, including assumptions, risks and uncertainties described in “Cautionary Note Regarding Forward-Looking Statements” above. These projections are speculative by their nature and, accordingly, are subject to significant risk of not being actually realized by the Company. Projected results of the Company for 2025 are particularly speculative and subject to change. Actual results may vary materially from the current projections, including for reasons beyond the Company’s control. The projections are based on current expectations and available information as of the date of this release. The Company undertakes no duty to publicly update these projections except as required by law. •In particular, you should be aware that, unless otherwise indicated, projections shown herein are based on management's "flat" commodity price parameters rather than SEC pricing guidelines or current NYMEX forward pricing. HighPeak believes that the useof flat pricing provides useful information as the flat prices reflect what management believes to be reasonable assumptions as to future commodity prices over the projection periods shown. However, HighPeak cautions you that the flat pricing used in preparing its projections is not necessarily a projection of future oil and natural gas prices, and should be carefully considered in addition to, and not as a substitute for, other commodity price assumptions held by third parties. Disclaimer
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3 •USE OF NON-GAAP FINANCIAL MEASURES •This presentation may include non-GAAP financial measures, including EBITDAX and adjusted EBITDAX, free cash flow, unlevered free cash flow, EBITDAX per Boe and unhedged EBITDAX per Boe, and PV-10. HighPeak believes these non-GAAP measures are useful because they allow HighPeak to more effectively evaluate its operating performance and compare the results of its operations from period to period and against its peers without regard to financing methods, capital structure or tax status. HighPeak does not consider these non-GAAP measures in isolation or as alternatives to similar financial measures determined in accordance with GAAP. HighPeak’s computations of these non-GAAP financial measures may not be comparable to other similarly titled measures of other companies. •HighPeak defines EBITDAX as net income before interest expense, income taxes, depreciation, depletion and amortization, exploration and other expenses, impairment and abandonment expenses, non-cash gains or losses on derivatives, stock-based compensation, gain on exchange of debt, gains and losses from the sale of assets, transaction costs and nonrecurring workforce reduction severance payments. HighPeak defines Adjusted EBITDAX as EBITDAX excluding cash G&A expenses. HighPeak’s management believes EBITDAX is useful as it allows them to more effectively evaluate HighPeak’s operating performance and compare the results of its operations from period to period and against its peers without regard to financing methods or capital structure. HighPeak excludes the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within the industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. HighPeak also periodically presents EBITDAX on an “annualized” basis, which represents EBITDAX for a fiscal quarter annualized for a 12-month period as if EBITDAX for each fiscal quarter in such period was equal to the quarter specified. HighPeak defines Adjusted EBITDAX per BOe as realized price less lease operating expenses, gathering, processing and transportation expenses and production taxes, on a per-Boe basis. HighPeak defines EBITDAX per Boe as realized price less lease operating expense, gathering, processing and transportation expenses, cash general and administrative expenses and production taxes, on a per-Boe basis. HighPeak defines unhedged as excluding the effects of derivatives and hedged as including the effects of derivatives. HighPeak defines Free Cash Flow as operating cash flow before working capital changes (i.e. discretionary cash flow) less capex excluding acquisitions. HighPeak defines Unlevered Free Cash Flow as EBITDAX less Capex. HighPeak defines PV-10 as the present value of estimated future net revenues to be generated from the production of proved reserves, without giving effect to non-property related expenses, discounted at 10% per year before income taxes. For reconciliations of each such non-GAAP measure as presented herein to its most comparable measure prepared in accordance with GAAP, see theAppendix to this presentation. •In the case of non-GAAP financial measures presented for future periods, HighPeak advises that it is unable to provide reconciliations of such measures without unreasonable efforts. Accordingly, such measures should be considered in light of the fact that no GAAP measure of performance or liquidity is available as a point of comparison to such non-GAAP measures. •INDUSTRY AND MARKET DATA •This presentation has been prepared by HighPeak and may include market data and other statistical information from sources believed by HighPeak to be reliable, including independent industry publications, governmental publications or other published independent sources. Some data is also based on HighPeak’s good faith estimates, which are derived from its review of internal sources aswell as the independent sources described above. Although HighPeak believes these sources are reliable, they have not independently verified the information and cannot guarantee its accuracy and completeness. •DRILLING LOCATIONS •The Company has estimated its drilling locations based on well spacing assumptions and upon the evaluation of its drilling results and those of other operators in its area, combined with its interpretation of available geologic and engineering data. Thedrilling locations actually drilled on the Company’s properties will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities conducted on these identified locations may not be successful and may not result in additional proved reserves. Further, to the extent the drilling locations are associated with acreage that expires,the Company would lose its right to develop the related locations. Disclaimer (Cont’d)
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4 •Midland Basin Pure Play Company Overview Sub $50 Breakeven Locations Net Acres Q1 Production 53 MBoe/D >143,000 >1,000 $41.90 Q1 Unhedged EBITDAX/BOE Q1 EBITDAX1 $197.3 MM •1. EBITDAX is a non-GAAP financial measure. See appendix for reconciliation. Narrowing & Raising Production Guidance 48–50.5 MBoe/D MIDLAND BASIN
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5 (1) Represents Q4’24 thru Q1’25 average daily footage drilled per rig compared to Q2’23 thru Q3’24 average daily footage drilled per rig. (2) Represents rig released wells with average lateral lengths of 13,250’. (3) Spud to spud normalized to average per well lateral lengths of 13,250’. Q1 2025 Operational Efficiencies 2025 Guided Pace 2025 Q1 Achieved Pace 14 days 11 days ~3 fewer days/well Spud to Spud3 Continued improvements in drilling efficiencies resulting in more wells drilled per rig Recent activity demonstrating 26% increase in average daily footage drilled per rig1 25 wells 33 wells Single Rig Output/Yr Faster pace translates to ~33 wells drilled/year/rig2
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6 $55 $60 $65 $70 $75 $80 $85 01/01/25 02/01/25 03/01/25 04/01/25 05/01/25 Oil Price 0% 25% 50% 75% 100% Year Wells Spud Infra. $ Total $ •Outsized Portion of 2025 Development Activity Accomplished in Q1 Q1 2025 Budget Update Q1 Actuals/Planned FY 2025 Activity 40% 38%60%Q1 2025 Total Capital Guide $448 - 490 MM 01 ▪ Spudded 20 wells ▪ Rig released & completed 16 wells (vs 12 initially planned) ▪ Costs in line with 2025 expectations 02 ▪ 2025 Infrastructure projects were Q1 weighted ▪ Connected to additional takeaway outlets 03 ▪ 2nd spot frac crew completed a 4 well pad ▪ Q1’25 capex includes accelerated projects that were initially scheduled later in 2025 01 02 03 03
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7 •Modifying Drilling Program to Remain Within 2025 Guided Activity Levels (1) Represents Rig-Released wells. Go Forward 2025 Development Plan ▪ Dropping one rig from May through August ▪ Planned return of 2nd rig in September ▪ No change to 2025 guided TILs and Capex budget Wells drilled1 ~50 wells/yr ~65 wells/yr +15 wells/yr ~50 wells/yr Original 2-Rig Plan Q1 2-Rig Pace Revised Rig Plan If negative macro-economic conditions continue, HPK has the flexibility to run one rig until the market improves, which would not have a significant effect on 2025 production guidance. Revised Rig Plan J S M F O J M J N A A D
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8 HPK Starting to See Costs Softening in Certain Large Ticket Items D,C&E Costs Update D R I L L I N G C O M P L E T I O N S Drilling Rig OCTG/Casing Equip. / Rentals Stimulation Equip. / Rentals Artificial Lift Fuel Cased Hole Serv. Expect low to mid-single digit decreases in overall costs moving forward Drilling Completions
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9 •3-Year Reserve Replacement Ratio 1 •Profitable development @ $60/Bbl (WTI)2,3 1. 3-Year Reserve Replacement Ratio calculated as the total additions during 2022-2024 from extensions/discoveries plus acquired reserves plus revisions less divested reserves divided by the total production during the same period. 2. Op. Cost (YE24) and 3-yr All-in F&D (incl. revisions) calculated from company filings. Adj Revenue assumes YE24 SEC realized oil price adjusted to $60/Bbl (WTI) with YE24 SEC realized gas & NGL prices. 3. Peers include: APA, CHRD, CIVI, CTRA, DVN, EXE, FANG, MGY, MNR, MUR, OVV, OXY, PR and SM. Profitable Reserve Growth and Development ◼3-year reserve replacement ratio of >400% driven by drill bit reserve additions ◼HPK is one of few E&P companies able to deliver profitable development at current oil prices Profit/BOE Profitable Unprofitable Realized Price / Boe
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10 Ahead of the Curve Enverus PF2024 Outline1 Enverus PF2025 Outline1 HighPeak has consistently been ahead of the industry due to extensive basin experience and specialized geologic research 355 gross operated wells drilled ~80 million BOEs produced2 >4.3 million lateral feet drilled Targeting 6 different benches •1. Map outlines per Enverus 2024 and 2025 Permian Play Fundamentals reports. •2. Represents 2-stream gross operated horizontal well production.
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11 Positioned for sustainable long-term success Strong balance sheet with reasonable leverage and liquidity Peer leading margins driven by operational efficiency and life of field infrastructure • Positioned for Value Creation Large contiguous acreage position with oil-weighted, multi-zone inventory Long runway of high-value inventory relative to peers 1) Primary zones include Lower Spraberry and Wolfcamp A & B. Primary zones exclude >200 potential Middle Spraberry locations. 2) Represents first quarter 2025 unhedged EBITDAX per Boe. 3) Represents first quarter 2025 Net Debt / first quarter 2025 EBITDAX on an annualized basis. ✓ ✓ ✓ ✓ ✓ >143,000 net acres >1,000 sub $50/Bbl break-even in primary zones1 $41.90/BOE Q1’25 EBITDAX Per BOE2 1.26x Q1’25 LQA Leverage Ratio3
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12 HIGHPEAK ENERGY , INC. Appendix
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13 In Progress . HighPeak Well Activity As of 3/31/2025 Gross Net OP 28 28.0 Non-Op 0 0.0 Total 28 28.0 SWD 2 2.0 Rig Released Wells Turned in Line 1Q25 Gross Net OP 16 16.0 Non-Op 0 0.0 Total 16 16.0 SWD 1 1.0 1Q25 Gross Net OP 13 12.9 Non-Op 0 0.0 Total 13 12.9 SWD 0 0.0
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14 Hedge Profile Summary 2Q25 – 4Q25 Avg. Oil Hedged Average Daily Oil Hedged 2Q25 – 4Q25 Avg. Gas Hedged Hedge Profile OIL SWAPS OIL PUTS OIL COLLARS HENRY HUB GAS SWAP VOL (Mbbl) Price VOL (Mbbl) Price VOL (Mbbl) Low High Daily (bopd) VOL (BBtu) Price 2025/Q2 501 $76.37 819 $65.78 727 $64.38 $88.55 2,730 $4.43 2025/Q3 276 $75.85 828 $65.78 644 $65.00 $90.08 2,760 $4.43 2025/Q4 460 $60.00 $72.80 Avg Swap Avg Put Avg Collar 2,760 $4.43 2025 777 $76.19 1,647 $65.78 1,831 $63.50 $85.13 2,824 5,989 6,658 8,250 $4.43 2026/Q1 450 $60.00 $72.80 18% 39% 43% 2,700 $4.39 2026/Q2 2,730 $4.30 2026/Q3 2,760 $4.30 2026/Q4 2,760 $4.30 2026 450 $60.00 $72.80 5,000 10,950 $4.32 2027/Q1 100% 1,770 $4.30 2027/Q2 2027/Q3 2027/Q4 2027 1,770 $4.30 15.4 MBo/d 30,000 MMBtu/d
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15 (1) Excludes acquisitions. (2) Rig Released / Turn in Line includes gross operated wells. Rig Released excludes 1 SWD. Q1 2025 Summary Production 1Q’25 Total sales volumes (MBoe) 4,781.5 Total daily sales volumes (MBoe/d) 53.1 Oil percentage 72% Liquids percentage 86% Realized Pricing Oil per Bbl $71.64 NGL per Bbl $24.21 Gas per Mcf $2.34 Total per Boe (excluding derivatives) $53.84 Total per Boe (including derivatives) $53.20 Costs (per Boe) LOE $6.61 Workover expenses $0.83 Production & Ad Valorem taxes $3.17 G&A (Cash) $1.33 Total cash costs $11.94 EBITDAX per Boe (excluding derivatives) $41.90 EBITDAX per Boe (including derivatives) $41.26 Earnings 1Q’25 Net Income ($MM) $36.3 Earnings Per Diluted Share $0.26 EBITDAX ($MM) $197.3 EBITDAX Per Diluted Share $1.40 Adjusted Net Income ($MM) $42.7 Adjusted Earnings Per Diluted Share $0.31 Free Cash Flow ($MM) $10.7 Other Capex ($MM) (1) $179.8 Rig Released / Turn in Line (2) 16 / 13
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16 •Reconciliation of Net Income to EBITDAX Non-GAAP Financial Measures Reconciliations (in thousands) Quarters Ended Q1'25 Q4'24 Q3'24 Q2'24 Q1'24 Net income $36,335 $8,981 $49,933 $29,717 $6,438 Interest expense $36,988 $39,508 $42,579 $42,991 $43,634 Interest and other income ($810) ($1,721) ($2,172) ($2,400) ($2,392) Income tax expense (benefit) $9,939 $3,866 $15,438 $14,250 $2,297 Depletion, depreciation and amortization $109,325 $105,631 $136,578 $127,693 $130,850 Accretion of discount $244 $244 $241 $242 $239 Exploration and abandonment expense $264 $449 $362 $167 $498 Stock based compensation $177 $1,375 $3,753 $3,775 $3,798 Derivative-related noncash activity $4,856 $20,704 ($33,775) ($2,606) $47,895 Other expense $0 $390 $1,404 $2,000 $1 EBITDAX $197,318 $179,427 $214,341 $215,829 $233,258
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17 Non-GAAP Financial Measures Reconciliations •Free Cash FlowNet Debt ($mm) As of 31-Mar-25 Long-term debt $ 1,050 Cash and cash equivalents (52) Net debt $ 998 Adjusted Net Income Reconciliation 1Q’25 ($mm) 1Q’25 ($/Diluted Share) Net Income $ 36.3 $ 0.26 Derivative loss 7.9 0.06 Stock-based compensation 0.2 0.00 Income tax adj. for above items (1.7) (0.01) Adjusted net income $ 42.7 $ 0.31 (in thousands) Quarters Ended Q1'25 Q4'24 Q3'24 Q2'24 Q1'24 Net cash provided by operations $157,052 $139,518 $177,103 $202,331 $171,439 Add back: net change in operating assets and liabilities $8,288 $6,642 ($729) ($24,754) $24,249 Operating cash flow before working capital changes $165,340 $146,160 $176,34 $177,577 $195,688 Additions to crude oil and natural gas properties ($179,819) ($152,680) ($140,251) ($164,199) ($147,698) Changes in working capital associated with crude oil and natural gas property additions $25,172 $14,508 ($7,988) ($6,931) $1,705 Free cash flow $10,693 $7,988 $28,135 $6,447 $49,695