HighPeak Energy, Inc.: Form 10-Q for the period ended Sep 30, 2025

The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and related notes. This discussion contains certain “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. These forward-looking statements involve risks and uncertainties and actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read “Cautionary Statement Concerning Forward‑Looking Statements.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law.

Overview

HighPeak Energy, Inc., a Delaware corporation, formed in October 2019, is an independent crude oil and natural gas exploration and production company that explores for, develops and produces crude oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin. The Company’s assets are located primarily in Howard and Borden Counties, Texas, and to a lesser extent Scurry and Mitchell Counties, which lie within the northeastern part of the crude oil-rich Midland Basin. As of September 30, 2025, the assets consisted of two highly contiguous leasehold positions of approximately 154,650 gross (143,496 net) acres, approximately 70% of which were held by production, with an average working interest of 93%. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern portion of Howard County. We operate approximately 98% of the net acreage across the Company’s assets and more than 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the nine months ended September 30, 2025, approximately 85% and 15% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of September 30, 2025, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew and expects to average one to two (1-2) drilling rigs and approximately one (1) frac crew during the remainder of 2025 under our current development plan.

Recent Events

Recent managements changes. In September 2025, Mr. Jack Hightower, the Company’s Chief Executive Officer and Chairman of the board retired and resigned from the board of directors, and our President, Mr. Michael Hollis, was named Interim Chief Executive Officer. Subsequent to quarter end on November 4, 2025, the board named Mr. Hollis, President and Chief Executive Officer.

Concurrent with these changes, Mr. Jack Hightower also retired from managing HighPeak Energy Partners, LP and HighPeak Energy Partners II, LP (collectively, the “HighPeak Funds”), which collectively own approximately 64.7% of the shares of common stock of the Company. In connection with Mr. Jack Hightower’s retirement, HighPeak Pure Acquisition, LLC (“Pure”), a wholly owned subsidiary of HighPeak Energy Partners, LP will distribute 1,532,478 shares of common stock in full and complete redemption of Mr. Jack Hightower’s interest in Pure. Following Mr. Jack Hightower’s retirement, the HighPeak Funds are managed by a committee comprised of Mr. Hollis, Daniel Silver and Ryan Hightower, each of whom also serve as President and Chief Executive Officer, Executive Vice President and Executive Vice President of the Company, respectively. In addition, pursuant to the Stockholder’s Agreement, dated August 21, 2020, the HighPeak Funds have designated Mr. Silver to serve as their board appointee under the Stockholder’s Agreement, and Mr. Silver was appointed to serve as a director of the Board effective immediately.

Debt amendments. In August 2025, the Company entered into the First Term Loan Amendment and the Second Facility Amendment which amended the Term Loan Credit Agreement and the Senior Credit Facility Agreement whereby, among other things, (i) the maturity dates were extended two years to September 2028, (ii) Term Loan Credit Agreement was upsized to $1.2 billion, providing additional liquidity, and (iii) the Term Loan Credit Agreement quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026.

Dividends and dividend equivalents. In August 2025, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.0 million in dividends being paid in September 2025. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $531,000 in September 2025. In addition, the Company accrued an additional combined $31,000 in September 2025 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In addition, in November 2025, the Company’s Board of Directors declared a quarterly dividend of $0.04 per share, or approximately $5.0 million in dividends, to be paid on December 23, 2025, to stockholders of record on December 1, 2025.

Acquisitions and divestitures. During the nine months ended September 30, 2025, the Company incurred a total of $4.5 million in acquisition costs related to lease extensions and to acquire crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas. In addition, during the nine months ended September 30, 2025, the Company received $570,000 in proceeds from the sale of some non-core non-operated properties.

Crude Oil and Natural Gas Industry Considerations. Our operating results, and those of the crude oil and natural gas industry as a whole, are heavily influenced by commodity prices. Crude oil, NGL and natural gas prices and basis differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term.

In early 2025, OPEC and its non-OPEC allies, known collectively as OPEC+, began unwinding prior voluntary production cuts and subsequent to quarter end announced that they agreed to increase oil production by another 548,000 bopd starting in September 2025, completing the reversal of its prior 2.2 million bopd cutback from 2023. This substantial supply boost contributed to a decline in global crude oil prices during the nine months ended September 30, 2025. OPEC+ also emphasized that the production increases could be paused or reversed depending on how market conditions evolve, maintaining flexibility to support price stability. Concurrently, in March 2025, the U.S. imposed tariffs on energy imports from Canada and Mexico, set at 10% and 25%, respectively, and expanded tariffs to include all steel and aluminum imports, aiming to bolster domestic production. In addition, in early April 2025, the current administration began announcing a substantial number of trade tariffs, including a new universal baseline reciprocal tariff, plus an additional country-specific reciprocal tariff for select trading partners, on all U.S. imports, although imports of crude oil, natural gas and refined products received exemptions from the tariffs. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff applied to China, which the administration increased. The pause was extended to August 1, 2025 based on ongoing negotiations with several trading partners to address U.S. concerns about non-reciprocal trade practices. Furthermore, on July 8, 2025, the United States announced additional sector-specific tariffs, including on copper imports. Concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed further downward pressure on oil prices. With negotiations and countermeasures still ongoing, the situation is fluid, and we expect price volatility to continue. Collectively, these policy changes—OPEC+'s production increase and the U.S. tariffs—are introducing significant volatility to the crude oil and natural gas sector. In addition, tariffs have the potential to significantly increase our operating and capital costs, which could negatively impact our ability to carry out our planned drilling program and future growth projects.

In addition, since being sworn into office, President Trump has issued numerous Executive Orders that aim to increase crude oil production and decrease commodity prices. For example, President Trump declared a “national energy emergency” in January 2025, and gave the executive branch more power to expedite approvals for energy resource infrastructure (including crude oil and natural gas). Additionally, President Trump’s “Unleashing American Energy” Executive Order incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as crude oil and natural gas. More recently, in March 2025, President Trump signed an Executive Order that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices or our operations. These and other factors make it difficult to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings and maintain our hedging program. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized price.

Sanctions and import bans on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. As a result of crude oil and natural gas supply constraints, there have been significant increases in European energy costs, which have resulted in inflationary pressures throughout Europe, increasing prospects of recession in many countries throughout the continent. The ongoing war between Russia and Ukraine and conflicts in the Middle East have resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by recent conflicts in the Middle East as well as the tariffs and proposed tariffs by the current administration. Specifically, the Company’s 2023, 2024 and 2025 capital program has been and continues to be impacted by higher prices for steel, diesel, chemicals and services, among other items.

Global crude oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) general economic conditions and increasing expectations that the world may be heading into a global recession, (ii) the ability of OPEC+ and other crude oil producing nations to manage the global crude oil supply, (iii) the impact of sanctions and import bans on production from Russia and any resulting impact on production from conflicts in the Middle East, (iv) the timing and supply impact of any Iranian or Venezuelan sanction relief on their ability to export crude oil, (v) the global supply chain constraints associated with manufacturing and distribution delays, (vi) oilfield service demand and cost inflation, and (vii) political stability of crude oil consuming countries. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.

Outlook

HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend heavily on prevailing commodity prices. The crude oil and natural gas industry is cyclical and commodity prices are highly volatile and subject to a high degree of uncertainty. For example, during the period from January 1, 2021 through September 30, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35.

The markets for the commodities produced by our industry strengthened in 2021 continuing into 2023. However, they began declining in 2024 and have continued in the first nine months of 2025 due to concerns over trade wars and energy tariffs, among other factors, and has decreased from 2022 levels overall, as a result of increased supply outpacing increased demand for each of the commodities we produce. Although prices for the commodities produced by our industry improved from historic lows in 2020, there are many factors beyond the Company’s control, including commodity markets, unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services or supply constraints remain subject to heightened levels of uncertainty as a result of commodity-specific tariffs and the possibility of trade wars, the ongoing war between Russia and Ukraine and conflicts in the Middle East, elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. For additional information on the risks, see “Part I. Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 10, 2025.

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to average a one to two (1-2) drilling rig program for the remainder of 2025. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. Despite continuing impacts of the factors listed above and future uncertainty, we are focused on maintaining our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.

Strategic Alternatives

On January 23, 2023, the Company announced the intention of its Board to initiate a process to evaluate certain strategic alternatives to maximize shareholder value, including a potential sale of the Company. Texas Capital Securities has been retained as a financial advisor with respect to this strategic alternatives process. The Company has not set a timetable for the conclusion of this review, nor has it made any decisions related to any further actions or potential strategic alternatives at this time. There can be no assurance that the review will progress beyond this exploratory phase or result in any transaction or other strategic change or outcome. The Company does not intend to comment further regarding the strategic alternatives process unless and until our Board has approved a specific course of action or we have otherwise determined that further disclosure is appropriate or required by law.

Financial and Operating Performance

The Company's financial and operating performance for the three months ended September 30, 2025 included the highlights described below and comparative discussion of related drivers for the three months ended September 30, 2024:

• Net loss was $18.3 million ($(0.15) per diluted share) for the three months ended September 30, 2025 compared with net income of $49.9 million for three months ended September 30, 2024. The primary components of the $68.3 million decrease in net income include:
• a $82.7 million decrease in crude oil, NGL and natural gas revenues due to a 25% decrease in average realized commodity prices per Boe, excluding the effects of derivatives, coupled with a 7% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking;
• a $25.4 million loss on extinguishment of debt recognized in the current year period related to the amendment to our Term Loan Credit Agreement in August 2025;
• a $25.4 million decrease in the Company’s derivative instruments gain as a result of its crude oil and natural gas commodity contracts entered into and the change in crude oil and natural gas prices thereafter;
• a $4.4 million increase in the Company’s general and administrative expenses primarily attributable to legal and severance costs related to the retirement of the Company’s Chief Executive Officer in September 2025 and higher wages and benefits as well as an increase in professional fees, all primarily as a result of the growth of the Company;
• a $1.9 million increase in the Company’s exploration and abandonment expenses due to increased plugging and abandonment expenses and abandoned leasehold costs; and
• a $1.0 million decrease in the Company’s interest income due to the decrease in average cash on hand,

partially offset by:

• a $35.9 million decrease in DD&A expense primarily due to a 21% decrease in the DD&A rate from $28.91 to $22.87 per Boe as a result of a significant increase in proved reserves at the end of 2024 and a 7% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking;
• a $19.0 million decrease in the Company’s income tax expense primarily due to a decrease in income before income taxes and a correction in the prior year period related to the reversal of a deferred tax asset related to stock-based compensation;
• a $5.4 million decrease in the Company’s interest expense primarily as a result of a decrease in the principal balance due to quarterly amortization payments, lower discount and debt issuance costs amortization and lower interest rates experienced;
• a $5.4 million decrease in the Company’s production and ad valorem tax expense as a result of a decrease in the revenues of the Company ;
• a $3.6 million decrease in the Company’s stock-based compensation expense primarily due to the majority of stock-based compensation instruments reaching fully vested status and thus having no further stock-based compensation expense to be recognized;
• a $2.1 million decrease in the Company’s crude oil and natural gas production costs primarily as a result of decreased chemical and treating costs related to third party midstream expansions and debottlenecking partially offset by increased expense workover costs with increased well cleanouts and pump changes with our aging well population; and
• a $1.2 million decrease in the Company’s other expense primarily as a result of some production facility repairs recognized in the prior year period.
• During the three months ended September 30, 2025, average daily sales volumes totaled 47,839 Boepd, compared with 51,346 Boepd during the same period in 2024, a decrease of 7%, primarily due to lower crude oil volumes as a result of decreased activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking.
• Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended September 30, 2025 to $65.63, compared with $75.99 for the same period in 2024. Weighted average NGL prices per Bbl decreased during the three months ended September 30, 2025 to $17.40, compared with $21.14 for the same period in 2024. Weighted average natural gas prices per Mcf increased to $1.07 during the three months ended September 30, 2025, compared with $0.42 during the same period in 2024.
• Cash provided by operating activities totaled $120.2 million for the three months ended September 30, 2025, compared with $177.1 million for the three months ended September 30, 2024.

Derivative Financial Instruments

Crude oil derivative financial instrument exposure. As of September 30, 2025, the Company was party to the following open crude oil derivative financial instruments.

Natural gas derivative financial instrument exposure. As of September 30, 2025, the Company was party to the following open natural gas derivative financial instruments.

The estimated fair value of the outstanding open derivative financial instruments as of September 30, 2025 was a net asset of $19.6 million which is included in current and noncurrent assets and noncurrent liabilities on the Company’s consolidated balance sheet as of September 30, 2025. During the nine months ended September 30, 2025, the Company recognized a net derivative gain of $25.4 million, including a $17.4 million mark-to-market gain and $8.0 million in net monthly settlement receipts.

Operations and Drilling Highlights

Average daily crude oil, NGL and natural gas sales volumes are as follows:

The Company’s liquids production was 85% of total production on a Boe basis for the nine months ended September 30, 2025.

Costs incurred are as follows (in thousands):

The following table sets forth the total number of horizontal producing wells drilled and completed during the nine months ended September 30, 2025:

As of September 30, 2025, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew. The continued threat of a potential recession, commodity-specific tariffs and the possibility of trade wars, the scope, duration and magnitude of the direct and indirect effects of pandemics, the ongoing war between Russia and Ukraine and conflicts in the Middle East and the production cuts and reversals thereof announced by OPEC+ are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility with its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed regularly.

During the nine months ended September 30, 2025, the Company successfully completed and placed on production thirty-six (36) gross (35.7 net) horizontal wells and completed and placed in operation two (2) gross (2.0 net) salt-water disposal wells. As of September 30, 2025, the Company had seventeen (17) gross (17.0 net) horizontal wells that had been drilled and were in various stages of completion. In addition, as of September 30, 2025, the Company was in the process drilling two (2) gross (2.0 net) horizontal wells.

Results of Operations

Three and Nine Months Ended September 30, 2025

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

The decrease in average daily Boe sales volumes for the three and nine months ended September 30, 2025, compared with the same periods in 2024 was primarily due to lower crude oil sales volumes as a result of reduced activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

The crude oil, NGL and natural gas prices that the Company reports are based on the market prices received for each commodity. The weighted average realized prices, excluding the effects of derivatives, are as follows:

Revenue Variance Analysis.

The following table illustrates the variance in revenues attributable to prices versus volumes (in thousands except prices and percentages):

As detailed above, the decrease in total operating revenues for the three and nine months ended September 30, 2025 compared to the same periods in 2024 is the result of a 25% and 22% decrease in average realized price per Boe, respectively, plus 5% and 0% decrease in average daily sales volumes, respectively, primarily as a result of lower crude oil sales volumes as a result of reduced activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

Crude Oil and natural gas production costs.

Crude oil and natural gas production costs in total and per Boe are as follows (in thousands, except percentages and per Boe amounts):

The decrease in crude oil and natural gas production costs for the three months ended September 30, 2025 compared to the same period in 2024 can be attributed primarily to decreased chemical and treating costs related to third party midstream expansions and debottlenecking partially offset by increased expense workover costs with increased well cleanouts and pump changes. The increase in crude oil and natural gas production costs for the nine months ended September 30, 2025 compared to the same period in 2024 can be attributed primarily to increased expense workover costs with increased well cleanouts and pump changes, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper costs also due to the increased number of wells operated partially offset by decreased chemical and treating costs related to third party midstream expansions and debottlenecking partially offset by increased expense workover costs with increased well cleanouts and pump changes with our aging well population.

Production and ad valorem taxes.

Production and ad valorem taxes are as follows (in thousands, except percentages):

In general, production taxes and ad valorem taxes are directly related to commodity sales volumes and price changes; however, Texas ad valorem taxes are based upon an asset valuation assessed by the state as of January 1 of that particular year based on prior year commodity prices, whereas production taxes are based upon current year sales revenues at current commodity prices. Overall, the decrease in production and ad valorem taxes during the three and nine months ended September 30, 2025 compared to the same periods in 2024 can be attributed primarily to the 25% and 22% decrease in overall commodity prices received, respectively, coupled with the aforementioned 7% and 0% decrease in sales volumes, respectively.

Production and ad valorem taxes per Boe are as follows:

The decrease in production taxes per Boe for the three and nine months ended September 30, 2025, compared with the same periods in 2024 can be attributed primarily to the lower commodity prices received thus far in 2025. The change in ad valorem taxes per Boe for the three and nine months ended September 30, 2025, compared with the same periods in 2024, was primarily due to an overaccrual during the early part of 2025 that was adjusted during the three months ended September 30, 2025 and overall for the year, taxes have decreased due to the assessments being lower based on lower overall prices in 2024 as compared to 2023 which is how taxes are assessed.

Exploration and abandonments expense.

Exploration and abandonment expense details are as follows (in thousands, except percentages):

Exploration and abandonment costs increased during the three and nine months ended September 30, 2025 primarily due to increased plugging and abandonment expenses as a result of regulatory requirements and abandoned leasehold costs related to some low value leases in Signal Peak that were not extended due to the fact that they were in low working interest units that were not on the immediate drilling schedule due to the work and cost involved in acquiring enough additional working interest to justify drilling the units.

DD&A expense.

DD&A expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):

The decrease in DD&A during the three and nine months ended September 30, 2025 is primarily due to a decrease in the DD&A rate primarily attributable to increased proved reserves coupled with the decreased production volumes.

General and administrative expense.

General and administrative expense and general and administrative expense per Boe as well as stock-based compensation expense are as follows (in thousands, except percentages and per Boe amounts):

The increase in general and administrative expense in total and per Boe for the three and nine months ended September 30, 2025 compared to the same periods in 2024 is primarily a result of severance and legal costs paid related to the retirement of our former Chief Executive Officer who retired in September 2025 which totaled approximately $3.4 million, increased wages and benefits in addition to higher professional services costs related to the growth of the Company. The decrease in stock-based compensation expense for the three and nine months ended September 30, 2025 compared to the same periods in 2024 is the result of the Company not issuing any significant stock options or restricted stock in the past couple of years. All stock-based compensation has been fully recognized except for the restricted stock issued to outside directors.

Other expense.

During the three and nine months ended September 30, 2025, the Company incurred approximately $29,000 and $2.5 million in rating agency fees, legal and accounting professional fees and other costs related to a proposed refinancing of its existing debt obligations. That specific refinancing transaction was not completed. Accordingly, these costs have been expensed as incurred. During the three and nine months ended September 30, 2024, the Company incurred approximately $1.2 million and $3.2 million, respectively, in costs related to repairs to production facilities.

Interest expense.

36

The decrease in interest expense can be attributed to a lower overall debt balance in 2025 compared with 2024, lower interest rates in 2025 compared with interest rates in 2024, lower amortization of discount and debt issuance costs in 2025 due to the loss on extinguishment of debt recognized during the three and nine months ended September 30, 2025 whereby the unamortized discount and debt issuance costs were expensed upon the closing of the First Term Loan Amendment on August 1, 2025 and fewer calendar days in the nine month period compared to the same period in the prior year.

Gain (loss) on derivative instruments, net.

The Company primarily utilizes commodity swap contracts, costless collars, enhanced collars and deferred premium put option contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budget and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require the Company to hedge certain quantities of its projected crude oil production. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market gain (loss) and cash settlements relate to crude oil derivative swap contracts, costless collars, enhanced collars and deferred premium put option contracts and natural gas derivative swap contracts.

Loss on extinguishment of debt.

On August 1, 2025, the Company entered into the First Term Loan Amendment which, among other things, (i) extended the maturity dates two years to September 2028, (ii) upsized the Term Loan Credit Agreement to $1.2 billion, providing additional liquidity, and (iii) deferred the Term Loan Credit Agreement quarterly amortization payments of $30.0 million for one year such that they begin again in September 2026. This amendment was considered an extinguishment of debt and thus unamortized discounts and debt issuance costs at the time of the amendment were written off to expense as was a premium paid to exiting lenders.

Provision for income taxes.

The change in provision for income taxes during the three and nine months ended September 30, 2025, compared with the same periods in 2024, was primarily due to the change in income before income taxes and the reversal of a $3.0 million deferred tax asset related to a temporary difference from restricted stock being reclassified to a permanent difference during the 2024 periods. The effective income tax rate differs from the statutory rate primarily due to the certain aforementioned stock-based compensation revision, Texas state margin taxes and other permanent differences between GAAP income and taxable income. See Note 12 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)" for additional information.

Liquidity and Capital Resources

Liquidity. The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Senior Credit Facility Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) sales of nonstrategic assets.

The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of other contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortizations of its indebtedness. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity. Although the Company expects its sources of funding will be adequate to fund its 2025 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.

2025 capital budget. The Company’s capital budget for 2025 is expected to be in the range of approximately $375 to $405 million for drilling, completion, facilities and equipping crude oil wells plus $40 to $50 million for field infrastructure buildout and other costs and $33 to $35 million on one-time infrastructure expenditures. The 2025 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses and general and administrative expenses. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its consolidated balance sheet, cash generated by operations and borrowing capacity available under its Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the nine months ended September 30, 2025 were $391.9 million, including the completion and/or continuation of certain one-time infrastructure projects but excluding acquisitions.

However, there are many factors and consequences beyond the Company’s control impacting our capital budget, such as political and regulatory uncertainties associated with the new Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC or OPEC+, and governments in response to pandemics, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors” in the Company’s Annual Report. The Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

Capital resources. Cash flows from operating, investing and financing activities are summarized below (in thousands).

Operating activities. The decrease in net cash flow provided by operating activities for the nine months ended September 30, 2025, compared with 2024, was primarily related to a decrease in discretionary cash flow as a result of a decrease in revenues less operating and general administrative expenses of approximately $190.1 million associated with lower overall commodity prices and lower crude oil production volumes partially offset by increased natural gas and NGL production volumes and increased costs related primarily to increased expense workover costs with increased well cleanouts and pump changes, increased electricity, power and fuel charges with the increased number of wells operated by the Company and increased pumper costs also due to the increased number of wells operated partially offset by changes in operating assets and liabilities that differ from the prior year period.

Investing activities. The decrease in net cash used in investing activities for the nine months ended September 30, 2025, compared with 2024, was primarily due to decreases in additions to crude oil and natural gas properties and acquisitions partially offset by a decrease in working capital related to additions to crude oil and natural gas properties.

Financing activities. The Company's significant financing activities are as follows:

• Nine months ended September 30, 2025: The Company increased borrowings under the Term Loan Credit Agreement on August 1, 2025 upon closing the First Term Loan Amendment by $180.0 million, partially offset by mandatory amortization payments totaling $60.0 million prior to that, borrowed and repaid $30.0 million under the Senior Credit Facility Agreement, paid dividends and dividend equivalents of $15.5 million and $1.6 million, respectively, paid debt issuance costs of $7.7 million primarily related to the First Term Loan Amendment and the Second Facility Amendment, paid $4.8 million in premium on extinguishment of debt and paid $3.8 million for tax withholding on vested equity awards related to the retirement of the Company’s Chief Executive Officer.
• Nine months ended September 30, 2024: The Company made mandatory payments on its Term Loan Credit Agreement totaling $90.0 million, paid $27.2 million to repurchase 1,849,636 shares of its common stock at an average cost of approximately $14.73 per share, excluding any potential excise taxes, and paid dividends and dividend equivalents of $15.1 million and $1.6 million, respectively.

Interest Rate Risk. We are exposed to market risk due to the floating interest rates associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of September 30, 2025, we had a $1.2 billion outstanding balance on the Term Loan Credit Agreement and zero outstanding on the Senior Credit Facility Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the end of each quarter for a period of three months and the Senior Credit Facility Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period of up to six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.

Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing war between Russia and Ukraine andconflicts in the Middle East. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our sales volumes during the nine months ended September 30, 2025 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $13.5 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis.

We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2025, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $7.4 million. Additionally, as of September 30, 2025, a $0.10 increase (decrease) in the forward curves associated with our natural gas commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $1.5 million.

Contractual obligations. The Company's contractual obligations include leases (primarily related to contracted drilling rigs, equipment and office facilities), capital funding obligations and other liabilities. Other joint owners in the properties operated by the Company could incur portions of the costs represented by these commitments.

Non-GAAP Financial Measures

EBITDAX represents net income before interest expense, interest and other income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, noncash derivative gains and losses, other expense, gains and losses on divestitures and certain other items. EBITDAX excludes certain items we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies.

We are also subject to financial covenants under our Term Loan Credit Agreement and Senior Credit Facility Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” of this Quarterly Report. The Term Loan Credit Agreement and Senior Credit Facility Agreement provide a material source of liquidity for us. Under the terms of our Term Loan Credit Agreement and the Senior Credit Facility Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of total net leverage or a minimum permitted ratio of asset coverage, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, they would be entitled to exercise all their remedies for default.

The following table provides a reconciliation of our net income (GAAP) to EBITDAX (non-GAAP) for the periods presented (in thousands):

New Accounting Pronouncements

Our historical condensed consolidated financial statements and related notes to condensed consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done, and judgments made on how the specifics of a given rule apply to us.

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for crude oil and natural gas activities, crude oil, NGL and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes.

Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 2025. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report.

New accounting pronouncements issued but not yet adopted. The effects of new accounting pronouncements are discussed in Note 2 of Notes to Condensed Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)."

The Company’s major market risk exposure is the pricing it receives for its sales of crude oil, NGL and natural gas. Pricing for crude oil, NGL and natural gas has been volatile and unpredictable for several years, and HighPeak Energy expects this volatility to continue in the future.

During the period from January 1, 2021 through September 30, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $13.5 million on an annualized basis, excluding the effects of derivatives, and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis, excluding the effects of derivatives.

Due to this volatility, the Company uses commodity derivative instruments, such as collars, puts, swaps and basis swaps, to hedge price risk associated with a portion of anticipated production. These hedging instruments allow the Company to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in crude oil and natural gas prices and provide increased certainty of cash flows for its drilling program. These instruments provide only partial price protection against declines in crude oil and natural gas prices and may partially limit the Company’s potential gains from future increases in prices. The Company enters into hedging arrangements to protect its capital expenditure budget. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require the Company to hedge certain quantities of its projected crude oil production. The Company does not enter into any commodity derivative instruments, including derivatives, for speculative or trading purposes.

Counterparty and Customer Credit Risk. The Company’s derivative contracts, if any, expose it to credit risk in the event of nonperformance by the counterparties. It is anticipated that if the Company enters into any commodity contracts, the collateral defined in the Collateral Agency Agreement may be used as collateral for the Company’s commodity derivatives. The Company evaluates the credit standing of its counterparties as it deems appropriate. It is anticipated that any counterparties to HighPeak Energy’s derivative contracts would have investment grade ratings.

The Company’s principal exposures to credit risk are through receivables from the sale of crude oil and natural gas production due to the concentration of its crude oil and natural gas receivables with a few significant customers. The inability or failure of the Company’s significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company’s financial results.

The average forward prices based on September 30, 2025 market quotes were as follows:

The average forward prices based on October 31, 2025 market quotes were as follows:

Credit Risk. The Company's primary concentration of credit risk is associated with (i) the collection of receivables resulting from the sale of crude oil and natural gas production and (ii) the risk of a counterparty's failure to meet its obligations under derivative contracts with the Company.

The Company monitors exposure to counterparties primarily by reviewing credit ratings, financial criteria and payment history. Where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. The Company's crude oil and natural gas is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Historically, the Company's credit losses on crude oil and natural gas receivables have not been material.

The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.

The Company entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with right of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative contract, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

Interest Rate Risk. As of September 30, 2025, we had $1.2 billion outstanding under the Term Loan Credit Agreement and had $93.1 million of available borrowing capacity under the Senior Credit Facility Agreement. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement and Senior Credit Facility Agreement. The Company also has fixed rate debt for short periods that is periodically adjusted, but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The impact of a 1% increase in interest rates on our outstanding debt as of September 30, 2025 would have resulted in an annual increase in interest expense of approximately $12.0 million.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, HighPeak Energy has evaluated, under the supervision and with the participation of the Company’s management, including HighPeak Energy’s principal executive officer and principal financial officer, the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the fiscal period covered by this Quarterly Report. Based on that evaluation, HighPeak Energy’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective, as of the end of the period covered by this Quarterly Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2025 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

In addition to the information set forth in this Quarterly Report, the risks that are discussed in the Company’s Annual Report under the headings “Risk Factors,” “Business and Properties,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. Except as set forth below, there has been no material change in the Company's risk factors that were described in the Company’s Annual Report.

We are currently a “controlled company” within the meaning of Nasdaq rules and qualify for exemptions from certain corporate governance requirements. As a result, stockholders do not have the same protections afforded to stockholders of companies that are not exempt from such corporate governance requirements. It is anticipated that we will cease to be a controlled company following the end of year, but that over a majority of our shares will still be held by the HighPeak Funds, the John Paul DeJoria Family Trust and the John Paul DeJoria Dynasty Trust. The HighPeak Funds have and, following the HighPeak II Distribution expected early next year, the John Paul DeJoria Family Trust and John Paul DeJoria Dynasty Trust, will have significant influence over us.

The HighPeak Funds collectively own a majority of HighPeak Energy’s outstanding voting stock. Therefore, HighPeak Energy is a controlled company within the meaning of Nasdaq corporate governance standards. Following Mr. Jack Hightower’s retirement, the HighPeak Funds are managed by a committee comprised of Mr. Hollis, Daniel Silver and Ryan Hightower, each of whom also serve as President and Chief Executive Officer, Executive Vice President and Executive Vice President of the Company, respectively.

Under Nasdaq rules, a company of which more than 50% of the voting power is held by an individual, company or group of persons acting together is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:

• a majority of the Board consist of independent directors under Nasdaq rules;
• the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
• the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

A majority of the HighPeak Energy board members are independent and both the Nominating and Governance Committee and Compensation Committees are composed solely of independent members of the board. These requirements will not apply to HighPeak Energy as long as it remains a controlled company.

In connection with Mr. Jack Hightower’s retirement, the HighPeak Funds have agreed that HighPeak II will likely distribute its shares early next year (the “HighPeak II Distribution”), at which time HighPeak Energy will cease to be a controlled company. Following the HighPeak II Distribution and the distribution of 1,532,478 founder shares to Mr. Jack Hightower, the HighPeak Funds will own approximately 34.2% of our common stock, and approximately 35.8% of our common stock will be owned by the John Paul DeJoria Family Trust and the John Paul DeJoria Dynasty Trust. Such beneficial ownership by HighPeak Funds, the John Paul DeJoria Family Trust and the John Paul DeJoria Dynasty Trust of our voting interests could limit the ability of our other stockholders to approve transactions they may deem to be in the best interests of our Company or delay or prevent changes in control or changes in our management.

As long as the HighPeak Funds and, following the HighPeak II Distribution, the John Paul DeJoria Family Trust and John Paul DeJoria Dynasty Trust continue to own or control a significant percentage of outstanding voting power, they may have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our Second Amended and Restated Certificate of Incorporation or our Amended and Restated Bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets. Moreover, this concentration of stock ownership by our significant stockholders may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with stockholders who own such a significant percentage of our voting securities.

Further, following the HighPeak II Distribution, because HighPeak Energy will cease to be a controlled company, any action required or permitted to be taken by the stockholders of the Company must be taken at a duly held annual or special meeting of stockholders and may not be taken by any consent in writing of such stockholders.

Crude oil, NGL and natural gas prices are volatile. Sustained volatility, or declines in, crude oil, NGL and natural gas prices could adversely affect HighPeak Energy’s business, financial condition and results of operations and its ability to meet its capital expenditure obligations and other financial commitments.

The prices we receive for our crude oil, NGL and natural gas production heavily influence its revenue, profitability, access to capital, future rate of growth and the carrying value of its properties. The markets for crude oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period from January 1, 2021 through September 30, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35. One of the factors which caused the fall in prices was OPEC and its non-OPEC allies, known collectively as OPEC+, being unable to reach an agreement on production levels for crude oil, which resulted in Saudi Arabia and Russia initiating efforts to increase production. The convergence of these events, along with the significantly reduced demand because of the COVID-19 pandemic, created an unprecedented global crude oil and natural gas supply and demand imbalance, reduced global crude oil and natural gas storage capacity, caused crude oil and natural gas prices to decline significantly and resulted in continued volatility in crude oil, NGL and natural gas prices. Prices have recovered to pre-pandemic levels, with the calendar month average NYMEX WTI crude oil price of $63.53 per Bbl and the last trading day NYMEX natural gas price of $2.867 per MMBtu for the month of September 2025. However, there can be no certainty that commodity prices will sustain at these levels or continue to increase. In addition, the current U.S. presidential administration has signaled it will encourage increased domestic production of crude oil, which could lead to declines in crude oil, NGL and natural gas prices.

Likewise, NGL, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and pricing characteristics, have also fluctuated widely during this period. The prices HighPeak Energy receives for its production, and the levels of HighPeak Energy’s production, will depend on numerous factors beyond HighPeak Energy’s control, which include the following:

• worldwide and regional economic conditions, including elevated interest rates and associated policies of the Federal Reserve, impacting the global supply and demand for crude oil, NGL and natural gas;
• the price and quantity of foreign imports of crude oil, NGL and natural gas;
• domestic and global political and economic conditions, such as the change in U.S. presidential administration, the ongoing war between Russia and Ukraine, conflicts in the Middle East, socio-political unrest and instability, terrorism or hostilities in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;
• the occurrence or threat of epidemic or pandemic diseases, such as COVID-19, or any government response to such occurrence or threat;
• actions of OPEC or OPEC+, its members and other state-controlled crude oil companies relating to crude oil price and production controls;
• the level of global exploration, development and production;
• the level of global inventories;
• prevailing prices, and expectations regarding future prices, on local price indexes in the areas in which HighPeak Energy operates;
• the proximity, capacity, cost and availability of gathering and transportation facilities;
• localized and global supply and demand fundamentals and transportation availability;
• the cost of exploring for, developing, producing and transporting reserves;
• weather conditions and natural disasters;
• technological advances affecting energy consumption;
• the price and availability of alternative fuels, including the potential acceleration of the development of alternative fuels as a result of the IRA 2022 or otherwise;
• expectations about future commodity prices; and
• U.S. federal, state and local and non-U.S. governmental regulation and taxes.

Lower commodity prices may reduce HighPeak Energy’s cash flow and access to capital markets. If HighPeak Energy is unable to obtain needed capital or financing on satisfactory terms, its ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with lower crude oil and natural gas prices may adversely affect drilling economics and HighPeak Energy’s ability to raise capital, which may require it to re-evaluate and postpone or eliminate its development program, and result in the reduction of some proved undeveloped reserves and related standardized measure. If HighPeak Energy is required to curtail its drilling program, HighPeak Energy may be unable to hold leases that are scheduled to expire, which may further reduce reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect HighPeak Energy’s future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

Tariffs and other trade measures could adversely affect our operations, profitability and business.

On April 2, 2025, the United States announced a baseline tariff on all foreign goods, with goods imported from specified nations, including China and those in the European Union, subject to higher tariff rates. Since then, there have been delays of imposition of tariffs while the United States negotiates with those countries, as well as litigation seeking to restrict and/or delay the implantation of such tariffs, and the extent of such delays and the ultimate outcome and impacts cannot be predicted at this time. It remains unclear to what extent, upon which countries, and upon which terms, tariffs may be levied and, to the extent that such trade policies impact our supply chain, we may not be able to fully mitigate the impact of these increased costs or pass price increases on to our customers.

We may be materially adversely impacted by tariffs if we are not able to adapt our supply chain strategy. We may also face unanticipated costs in developing our domestic supply chain and increased competition for materials and components in the United States, which also would impact our business and results of operations. The imposition of tariffs has and may create uncertainty in our industry. Increases in costs to drill and develop reserves as a result of tariffs coupled with lower commodity prices from increased domestic production could make producing such reserves no longer economically viable or technically feasible. Additionally, existing or future tariffs may negatively affect our customers, suppliers, and manufacturing partners. Such outcomes could adversely affect the amount or timing of our revenues, results of operations or cash flows, and continuing uncertainty could cause sales volatility and price fluctuations.

Tariffs, the adoption and expansion of trade restrictions, the occurrence of a trade war, or other governmental action related to tariffs, trade agreements or related policies have the potential to adversely impact our supply chain and access to equipment, and our costs and ability to economically serve certain markets. Any such cost increases or decreases in availability could slow our growth and cause our financial results and operational metrics to suffer. There is current uncertainty about the future relationship between the United States and other countries with respect to trade policies, taxes, government regulations, and tariffs and we cannot predict whether, and to what extent, U.S. trade policies will change in the future.

HighPeak Energy’s development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, including as a result of recent increases in the cost of capital resulting from Federal Reserve policies or otherwise, which could reduce its ability to access or increase production and reserves.

The crude oil and natural gas industry is capital-intensive. We have evaluated multiple development scenarios under multiple potential commodity price assumptions. Under its current 2025 development program, we would expect to incur approximately $375 to $405 million of capital expenditures for drilling, completion, facilities and equipping costs, $40 to $50 million for field infrastructure and $33 to $35 million on one-time infrastructure expenditures. The ability to make these capital expenditures will be highly dependent on the price of crude oil and available funding of HighPeak Energy. Commodity prices have declined in the first nine months of 2025, with the calendar month average NYMEX WTI price of $63.53 per Bbl and last trading day NYMEX natural gas price of $2.867 per MMBtu for the month of September 2025. We ran a two-rig program for the majority of 2024. We expect to average one to two (1-2) drilling rigs and one (1) frac crew during 2025. We recognize that commodity prices remain highly volatile and that its liquidity is limited, and as a result, there is no certainty that we will operate a two (2) rig development program in the future.

We expect to fund our forecasted capital expenditures with cash on its balance sheet, cash generated by operations and, depending on market circumstances, potential future debt or equity offerings.

Cash flows from operations are subject to significant uncertainty. As a result, the amount of liquidity that we will have in the future is uncertain.

Our financing needs may require it to alter or increase its capitalization substantially through the issuance of debt or equity securities or the sale of assets. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. For example, due to the high levels of inflation in the United States, the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023, and began decreasing rates with three rate cuts toward the end of 2024. The Federal Reserve kept interest rates steady in 2025 citing the unknown effects of the Trump Administration’s trade policies on inflation, but it resumed such decreases in September 2025, although uncertainty remains as to when or if such elevated rates may be decreased further. Such increased interest rates have increased the cost of capital and may prevent us from being able to obtain debt financing at favorable rates, or at all, which would materially impact our operations. In addition, conditions in the global capital markets have been volatile due to uncertainty around tariff rates and trade policies, the ongoing war between Russia and Ukraine, conflicts in the Middle East or otherwise, making terms for certain types of financing difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. Further, the issuance of additional indebtedness would require that an additional portion of cash flow from operations be used for the payment of interest and principal on its indebtedness, thereby further reducing its ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to existing stockholders. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in actual capital expenditures, which would negatively impact our ability to increase production.

Our cash flow from operations and access to capital are subject to several variables, including:

• the prices at which our production is sold;
• proved reserves;
• the amount of hydrocarbons we are able to produce from our wells;
• Our ability to acquire, locate and produce new reserves;
• the amount of our operating expenses;
• cash settlements from our derivative activities;
• production interruptions or curtailments from time-to-time related to third-party infrastructure downtime or delays in third-party installation of infrastructure, including electrical power supply, that affects our ability to produce our crude oil and natural gas;
• the duration and scope of the ongoing war between Russia and Ukraine and conflicts in the Middle East;
• Our ability to obtain storage capacity for the crude oil we produce;
• restrictions in the instruments governing our debt on our ability to incur additional indebtedness; and
• Our ability to access the public or private capital markets.

Should our revenues decrease as a result of lower crude oil, NGL and natural gas prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain operations at expected levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to it, if at all, due to elevated interest rates and associated policies of the Federal Reserve, or otherwise. If cash flow generated by our operations or available debt financing are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in reserves and production and could materially and adversely affect our business, financial condition and results of operations. If we seek and obtain additional financing, subject to the restrictions in the instruments governing its existing debt, the addition of new debt to existing debt levels could intensify the operational risks that we will face. Further, adding new debt could limit our ability to service existing debt service obligations.

Hedging transactions expose HighPeak Energy to counterparty credit risk and may become more costly or unavailable.

Hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when there is an increase in the differential between the underlying price in the derivative instrument and actual prices received or there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in an adverse manner, our cash otherwise available for use in operations would be reduced which could limit our ability to make future capital expenditures and make payments on indebtedness. Future collateral requirements will depend on arrangements with counterparties, highly volatile crude oil, NGL and natural gas prices and interest rates.

In addition, derivative arrangements could limit the benefits to be received from increases in the prices for crude oil, NGL and natural gas, which could also have an adverse effect on HighPeak Energy’s financial condition. If crude oil, NGL and natural gas prices upon settlement of derivative swap contracts exceed the price at which commodities have been hedged, we will be obligated to make cash payments to counterparties, which could, in certain circumstances, be significant.

HighPeak Energy experiences periods of higher costs when commodity prices rise and inflation may adversely affect our operating results, which could negatively impact our profitability, cash flow and ability to complete development activities as planned. Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

Historically, capital and operating costs have risen during periods of increasing crude oil, NGL and natural gas prices. Inflationary factors such as increases in labor costs, material costs and overhead costs may adversely affect our operating results. These cost increases have resulted from a variety of factors that we will be unable to control, such as increases in the cost of electricity, steel and other raw materials; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting its profitability, cash flow and ability to complete development activities as scheduled and on budget. A high rate of inflation may have an adverse effect on our operating results and this impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by its derivative activities.

Although inflation rates moderated in 2024 and the first half of 2025, inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Due to the high levels of inflation, the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023, and began decreasing rates with three rate cuts toward the end of 2024. The Federal Reserve kept interest rates steady in 2025 citing the unknown effects of the Trump Administration’s trade policies on inflation, but resumed such decreases in September 2025, although uncertainty remains as to when or if such rates may be decreased further.

Higher crude oil and natural gas prices, continued inflation and supply chain issues as well as an increase in demand for services may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher crude oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations.

Volatility in the political, legal and regulatory environments as a result of the change in the U.S. presidential administration and political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine, conflicts in the Middle East and OPEC+ policy decisions could have a material adverse impact on our business, financial condition or future results.

Our business, financial condition and future results are subject to political and economic risks and uncertainties, including volatility in the political, legal and regulatory environments as a result of the imposition of and changes in tariffs and instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in crude oil or natural gas producing areas such as the ongoing war between Russia and Ukraine and conflicts in the Middle East.

The United States and other countries and certain international organizations have imposed broad-ranging and severe economic sanctions on Russia and certain Russian individuals, banking entities and corporations as a response, and additional sanctions may be imposed in the future. This conflict and the resulting sanctions and concerns regarding global energy security have contributed to increases and volatility in the prices for crude oil and natural gas. The length, impact, and outcome of the ongoing war between Russia and Ukraine is highly unpredictable, and such events or any further hostilities in Ukraine or elsewhere could severely impact the world economy and may adversely affect our financial condition. Furthermore, escalations of conflicts in the Middle East may result in heightened geopolitical risks for crude oil and natural gas markets, given the significant share of global oil supply in the Middle East. While the Company does not have operations overseas, these conflicts elevate the likelihood of supply chain disruptions, heightened volatility in crude oil and natural gas prices and negative effects on our ability to raise additional capital when required and could have a material adverse impact on our business, financial condition or future results.

Currently, global crude oil inventories are low relative to historical levels and supply from OPEC+ and other crude oil producing nations are not expected to be sufficient to meet forecasted crude oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental crude oil supplies over the past few years. OPEC+ began phasing out a 2.2 million Bopd reduction in oil production in April 2025, which it had previously postponed due to a slowdown in global demand and rising output surrounding the global economic and crude oil market outlooks, and approved another crude oil production increase of 137,000 Bopd in October 2025. Furthermore, sanctions and import bans on Russian crude oil have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. Still, crude oil and natural gas prices have declined from the highs experienced in second quarter of 2022 and could decrease or increase with any changes in demand due to, among other things, uncertainty and volatility from global supply chain disruptions attributable to the pandemic, the ongoing war between Russia and Ukraine, conflicts in the Middle East, international sanctions, speculation as to future actions by OPEC+, increasing inflation and government efforts to reduce inflation, and possible changes in the overall health of the global economy, including a prolonged recession. Further, the volatility in crude oil and natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over the longer term. To what extent these and other external factors (such as government action with respect to climate change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors, including future developments, which are not within our control and cannot be accurately predicted.

We are evaluating strategic alternatives, including a possible sale of our business, and there can be no assurance that we will be successful in identifying or completing any strategic alternative transactions, that any such strategic alternative transactions will result in additional value for our shareholders or that the process will not have an adverse impact on our business and shareholders.

Our Board continues to evaluate a range of strategic alternative transactions to maximize shareholder value, including a potential sale of the Company. These transactions could include, but are not limited to, acquisitions, debt refinancing transactions, asset divestitures, monetization of intellectual property, and mergers, reverse mergers or other business combinations. Because we have publicly approved the undertaking of this process, the market price of our common stock may reflect an expectation that shares of our common stock may be acquired at a premium in the near future.

There can be no assurance that the review of strategic alternative transactions will result in the identification or consummation of any transaction. Our Board may also determine that our most effective strategy is to continue to effectuate our current business plan. The process of reviewing strategic alternative transactions may be time consuming and disruptive to our business operations and, if we are unable to effectively manage the process, our business, financial condition and results of operations could be adversely affected. We could incur substantial expenses associated with identifying and evaluating potential strategic alternative transactions. No decision has been made with respect to any transaction and we cannot assure you that we will be able to identify and undertake any transaction that allows our shareholders to realize an increase in the value of their common stock or provide any guidance on the timing of such action, if any.

We also cannot assure you that any potential transaction or other strategic alternatives, if identified, evaluated and consummated, will provide greater value to our shareholders than that reflected in the current price of our common stock. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, but not limited to, market conditions, industry trends, the interest of third parties in our business and the availability of financing to potential buyers on reasonable terms. We do not intend to comment regarding the evaluation of strategic alternative transactions until such time as our Board has determined the outcome of the process or otherwise has deemed that disclosure is appropriate or required by applicable law. As a consequence, perceived uncertainties related to our future may result in the loss of potential business opportunities and volatility in the market price of our common stock and may make it more difficult for us to attract and retain qualified personnel and business partners. Volatility in the trading price of our common stock could also adversely affect the trading market for and the trading price of the notes.

The Principal Stockholder Group has significant influence over HighPeak Energy.

The Principal Stockholder Group owns approximately 65% of our common stock as of September 30, 2025. As long as the Principal Stockholder Group owns or controls a significant percentage of our outstanding voting power, subject to the terms of the Stockholders’ Agreement, they will have the ability to influence certain corporate actions requiring stockholder approval. Under the Stockholders’ Agreement, the Principal Stockholder Group will be entitled to nominate a specified number of directors for appointment to the Board so long as the Principal Stockholder Group meets certain ownership criteria outlined in the Stockholders’ Agreement.

If one of our former executive officers were forced to sell shares of our common stock that he has pledged to secure certain personal loan obligations, such sales could cause our stock price to decline.

Certain banking institutions have made extensions of credit to Jack Hightower, our former Chief Executive Officer, a portion of which was used to purchase shares of common stock in the public market and in certain of our public offerings and private placements at the same prices offered to third-party participants in such offerings and placements. We are not a party to these loans, which are primarily secured by pledges of shares of our common stock currently owned directly by Mr. Jack Hightower and shares of HighPeak common stock held indirectly by Mr. Jack Hightower via his interests in the HighPeak Funds and HPK GP. If the price of our common stock were to decline or such loans were to reach maturity without renewal, Mr. Jack Hightower may be forced by one or more of the banking institutions to sell, or the applicable banking institution may elect to sell, shares of HighPeak common stock or interests in the HighPeak Funds to satisfy his applicable loan obligations if he could not do so through other means. Any such sales could adversely affect the trading market and trading price of our common stock, as well as significantly reduce Mr. Jack Hightower’s ownership in the Company.

Recent management changes could disrupt our operations and impair our ability to attract and retain key personnel.

We have experienced recent changes to our senior management team, including the departure of our Chief Executive Officer, Jack Hightower, in September 2025 when our President, Michael Hollis, was named Interim Chief Executive Officer. Subsequent to quarter end on November 4, 2025, the Board named Michael Hollis President and Chief Executive Officer. Changes in our senior management and uncertainty regarding pending changes may disrupt our operations, impact customer and partner relationships, and impair our ability to recruit and retain other needed personnel. Any such disruption or impairment could have an adverse effect on our business.