HPK 10-K & 10-Q changes, risk factors and insider trading

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, including as a result of changes by the incoming U.S. presidential administration.

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. HighPeak Energy has evaluated multiple development scenarios under multiple potential commodity price assumptions. Under its current 20252026 development program, HighPeak Energy would expect to incur approximately $375$255 to $405$285 million of capital expenditures for drilling, completion, facilities and equipping costs, $40 - $50 million for field infrastructure, landinfrastructure and other costscosts, andexcluding $33 - $35 million on one-time infrastructure expenditures.acquisitions. 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 recovered,fallen, with the calendar month average NYMEX WTI price of $71.69$57.87 per Bbl and last trading day NYMEX natural gas price of $3.43$4.424 per MMBtu for the month of December 2024.2025. HighPeak Energy ran a two-rigone to two-rig, one frac crew program for the majority of 2024.2025. HighPeak Energy expects to average twoone (21) drilling rigsrig and one (1) frac crew during 2025.2026 depending on certain market conditions. However, HighPeak Energy recognizes that commodity prices remain highly volatile and that its liquidity is limited, and as a result, there is no certainty that HighPeak Energy will operate a twoone (21) rig development program in the future.

HighPeak Energy’s 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 U.S., 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 followed by three rate cuts in 2025 and although the Federal Reserve has indicated that such decreases should continue in 2025,2026, 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 the conflict in Ukraine, the Israel-Hamas conflict 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 HighPeak Energy’s ability to increase production.

HighPeak Energy’s ability to meet its expenses and its current and future debt obligations and comply with the covenants and restrictions contained therein will depend on its future performance, which will be affected by financial, business, economic, industry, regulatory and other factors, many of which are beyond HighPeak Energy’s control. If market or other economic conditions deteriorate, HighPeak Energy’s ability to comply with these covenants may be impaired. HighPeak Energy cannot be certain that its cash flow will be sufficient to enable it to pay the principal and interest on its debt and meet its other obligations. If HighPeak Energy does not have enough money, HighPeak Energy may be required to refinance all or part of its debt, sell assets, borrow more money or raise equity. HighPeak Energy may not be able to refinance its debt, sell assets, borrow more money or raise equity on terms acceptable to it, or at all. For example, HighPeak Energy’s future debt agreements may require the satisfaction of certain conditions, including coverage and leverage ratios, to borrow money. HighPeak Energy’s future debt agreements may also restrict the payment of dividends and distributions by certain of its subsidiaries to it, which could affect its access to cash. In addition, HighPeak Energy’s ability to comply with the financial and other restrictive covenants in the agreements governing its indebtedness will be affected by the levels of cash flow from operations and future events and circumstances beyond HighPeak Energy’s control. Breach of these covenants or restrictions could result in an event of default under HighPeak Energy’s existing and/or future financing arrangements, which, if not cured or waived, could permit the lenders to accelerate all indebtedness outstanding thereunder. Upon acceleration, the debt would become immediately due and payable, together with accrued and unpaid interest, and any lenders’ commitment to make further loans to HighPeak Energy may terminate. Even if new financing were then available, it may not be on terms that are acceptable to HighPeak Energy. Additionally, upon the occurrence of an event of default under HighPeak Energy’s financing agreements, the affected lenders may exercise remedies, including through foreclosure, on the collateral, if any, securing any such secured financing arrangements. Moreover, any subsequent replacement of HighPeak Energy’s financing arrangements may require it to comply with more restrictive covenants which could further restrict business operations.

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 policypolicy, including tariffs, 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.

Elevated inflation rates throughout 2023 and 2024 and inflationary pressures have resulted in and may continue to 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 in the U.S., 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 andfollowed althoughby three rates cuts in 2025. Although the Federal Reserve has indicatedpaused thatrate suchcuts decreasesbeginning couldin continue into 2025,2026, uncertainty remains as to when or if such elevated rates may be decreased further. To the extent rates remain high, this could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases.

Volatility in the political, legal and regulatory environments as a result of the change in 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 Israel-HamasMiddle conflictEast, U.S. intervention in Venezuela 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 change in U.S. presidential administration 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 UkraineUkraine, conflicts in the Middle East and theU.S. Israel-Hamasintervention conflict.in Venezuela.

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, escalationsconflicts ofin the Israel-HamasMiddle conflictEast 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. Itit 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. In Decemberthe 2024,first quarter of 2026, OPEC+ postponedagreed plannedto reductionsslight production increases to help mitigate the impact on crude oil prices of 2.2disrupted millionshipments Bopdin ofthe oilMiddle East, after pausing production until April 2025,increases due to a slowdown in global demand and rising output surrounding the global economic and crude oil market outlooks. 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 conflict in Ukraine, the Israel-Hamas conflict, U.S. intervention in Venezuela, 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.

During 2020, thea reduction in global demand caused by COVID-19,demand, coupled with the actions of foreign crude oil producers such as Saudi Arabia and Russia, materially decreased global crude oil prices and generated a surplus of crude oil. This significant surplus created a saturation of storage and caused imminent crude storage constraints, which led to, and in the future may further lead to the shut-in of production of our wells due to the lack of sufficient markets or the lack of availability and capacity of processing, gathering, storing and transportation systems. Additionally, several state crude oil and natural gas authorities, including the TRRC, implemented or considered implementing crude oil and natural gas production limits in an effort to stabilize declining commodity prices. To the extent adopted, such production limits could not only reduce our revenue, but also, if wells are required to be shut-in for extended periods of time due to such production limits, result in expenditures related to well plugging and abandonment. Cost increases necessary to bring wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in HighPeak Energy’s proved reserve estimates and potential impairments and associated charges to its earnings. As of December 31, 2024,2025, HighPeak Energy was running a two-rig program and expects to average twoone (21) drilling rigsrig and approximately one (1) frac crew during 20252026 under our current development plan.plan depending on certain market conditions. HighPeak Energy will continue to monitor the extent by which prices continue to increase and/or stabilize as we execute our capital expenditure program. Any shut-in or curtailment of the crude oil, NGL and natural gas produced from HighPeak Energy’s fields could adversely affect its financial condition and results of operations.

Certain of the undeveloped leasehold acreage of HighPeak Energy’s assets is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended or renewed.

As of December 31, 2024,2025, approximately 64%72% of HighPeak Energy’s acreage was held by production. Generally, the leases for net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases or the leases are extended or renewed. From 20252026 through 2027,2028, approximately 54%,49%, 31%43% and 11%,4%, respectively, of the net undeveloped acreage associated with the leases are set to expire. In particular, if the Company is unable to comply with the financial covenants under its Term Loan Credit Agreement and Senior Credit Facility Agreement and is required to reduce its capital expenditures as a result, it may be unable to pursue the drilling and development activities necessary to maintain these leases, which could result in the loss of a significant portion of its undeveloped acreage, including the proved undeveloped reserves associated therewith. If the leases expire and HighPeak Energy is unable to extend or renew the leases, HighPeak Energy will lose its right to develop the related properties. Although HighPeak Energy intends to hold substantially all these leases through its development drilling program or extend substantially all the net acreage associated with identified drilling locations through a combination of exploratory and development drilling, a portion of such leases may be extended or renewed. Additionally, any payments related to such extensions or renewals may be more than anticipated. Please see “Items 1 and 2: Business and Properties—Reserve Data—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for extending our acreage. HighPeak Energy’s ability to drill and develop its acreage and establish production to maintain its leases depends on a number of uncertainties, including crude oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing, frac sand and distribution systems, regulatory approvals and other factors.

If HighPeak Energy has insufficient production to meet the minimum volume commitments under anythis of these agreements or if HighPeak Energy fails to take delivery of supplies which it committed to,agreement, HighPeak Energy’s cash flow from operations will be reduced, which may require HighPeak Energy to reduce or delay its planned investments and capital expenditures, or seek alternative means of financing, all of which may have a material adverse effect on HighPeak Energy’s results of operation.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our businesses.business.

The CFTC has finalized rules that place limits on positions in certain core futures and equivalent swaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. We currently do not expect such rules will have a material impact on us. The CFTC has also adopted a final rule regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief—until August 12, 2025 or the effective date of any codifying rulemaking—from various conditions and requirements in the final aggregation rules.rules until the effective date of any codifying rulemaking. With the implementation of the final aggregation rules and upon the effectiveness of the final CFTC position limits rule, our ability to execute our hedging strategies described above could be limited.

HighPeak Energy expects to sell its production to a relatively small number of customers, as is customary in the crude oil and natural gas business. For the years ended December 31, 2025, 2024 and 2023, there were two purchasers that accounted for approximately 90%, 94% and 96% of our revenue, respectively (one at approximately 82%, 76% and 82%, respectively, and one at approximately 8%, 18% and 14%, respectively), and for the year ended December 31, 2022, there was one purchaser that accounted for approximately 88% of our revenue.. No other purchaser accounted for 10% or more of such revenues during such period. The loss of any such greater than 10% purchaser could adversely affect HighPeak Energy’s revenues in the short term. See the section entitled “Items 1 and 2: Business and Properties—Operations—Marketing and Customers” for additional information. HighPeak Energy expects to depend upon these or other significant purchasers for the sale of most of its crude oil and natural gas production. HighPeak Energy cannot ensure that it will continue to have ready access to suitable markets for its future crude oil and natural gas production.

HighPeak Energy may incur increasingincreased attention to ESG matters that may impact its business.

Moreover, while we may create and publish mandatory or voluntary disclosures regarding ESG matters from time to time, certain statements in those voluntary disclosures may be based on expectations and assumptions or hypothetical scenarios that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many ESG matters. We may also announce participation in, or certification under, various third-party ESG frameworks in an attempt to improve our ESG profile, but such participation or certification may be costly and may not achieve the desired results. Additionally, while we may announce various voluntary ESG targets, such targets are often aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our business operations. Some of these arrangements may receive scrutiny from certain constituencies. Also, despite these aspirational goals and any other actions taken, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to pursuepursue, implement or implementmake progress against such goals because of potential costs or technicaltechnical, inaccurate assumptions or operational obstacles.

Certain statements or initiatives with respect to ESG matters that we may pursue or assert are increasingly subject to heightened scrutiny from the public and governmental authorities, as well as other parties. For example, the SEC hasand recentlyvarious state agencies have taken enforcement action against companies for ESG-related misconduct, including alleged “greenwashing,” (i.e., the process of conveying misleading information or making false claims that overstate potential ESG benefits). CertainSuch regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actorsactors, have filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, goals or standards were misleading, false or otherwise deceptive. Certain socialemployment andor inclusionbusiness initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various government agencies. Such sentiment may focus on the Company’s environmental or social commitments (such as reducing GHG emissions) or its pursuit of certain employment or business practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Company’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties. As a result, the Company may be subject to pressure in the media or through other means, such as governmental investigations, enforcement actions, or other proceedings, all of which could adversely affect our reputation, business, financial performance, market access and growth. Accordingly, there may be increased costs related to reviewing, implementing and managing such policies, as well as compliance and litigation risks based both on positions we do or do not take, or work we do or do not perform.

In addition, organizations that provided information and ratings to investors on ESG and related matters have developed rating processes for evaluating business entities on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations has become more broadly accepted by investors and shareholders. Such ratingsassessments are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scoresassessments to benchmark businesses against their peers and if a business entity is perceived as lagging, these investors may engage with such entities to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a business entity’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of HighPeak Energy’s stock from consideration by certain investment funds, restrictions on our ability to obtain insurance, and engagement by investors seeking to improve such scoresassessments and a negative perception of HighPeak Energy’s operation by certain investors. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. ESG matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.

In addition, ESG efforts related to employment practices and social initiatives are the subject of scrutiny by stakeholders, regulators and other third-parties. The complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. To the extent any enforcement actions or other litigation is brought against us as a result of emerging viewpoints and legal interpretations, our business, financial condition and access to financing may be materially and adversely affected.

The success of completed acquisitions will depend on HighPeak Energy’s ability to integrate effectively the acquired business into its then-existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of its managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that it will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. HighPeak Energy’s failure to achieve consolidation savings, to integrate the acquired businesses and assets, including those from the Hannathon and Alamo Acquisitions,assets into its then-existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on its financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services due to commodity price volatility or supply constraints as a result of the conflict in Ukraine,Ukraine and the Israel-HamasMiddle conflict,East and U.S. intervention in Venezuela, elevated interest rates and associated policies of the Federal Reserve could adversely affect HighPeak Energy’s ability to execute its development plans within its budget and on a timely basis and consequently could materially and adversely affect our cash flows and results of operations.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the crude oil and natural gas industry, can fluctuate significantly, often in correlation with crude oil, NGL and natural gas prices, causing periodic shortages of equipment, supplies and needed personnel. The incomingcurrent U.S. presidential administration has signaled it will encourage increased domestic exploration and production activity, which could lead to a reduction in crude oil, NGL and natural gas prices. Additionally, supply constraints due to the conflict in Ukraine,Ukraine and the Israel-HamasMiddle conflict,East and U.S. intervention in Venezuela, elevated interest rates and associated policies of the Federal Reserve has increased the cost of oilfield services. HighPeak Energy’s operations are concentrated in areas in which oilfield activity levels have previously increased rapidly. If that were to happen again, demand for drilling rigs, equipment, supplies and personnel may increase the costs for these services. Access to transportation, processing and refining facilities in these areas may become constrained resulting in higher costs and reduced access for those items. Historically, crude oil, NGL and natural gas prices have been volatile. For example, during the period from January 1, 2021 through December 31, 2024,2025, 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. To the extent commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase and HighPeak Energy could encounter delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for it to resume or increase HighPeak Energy’s development activities, which could result in production volumes being below its forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on cash flow and profitability. Furthermore, if it is unable to secure a sufficient number of drilling rigs at reasonable costs, HighPeak Energy may not be able to drill all its acreage before its leases expire.

Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act of 1938 to impose penalties for current violations of up to $1,584,648 per day for each violation (annually adjusted for inflation) for 2025 soon to be adjusted for 2026 and disgorgement of profits associated with any violation. While our operators’ operations have not been regulated by the FERC as a natural gas company under this law, the FERC has adopted regulations that may subject certain of our operators’ otherwise non-FERC jurisdictional facilities to the FERC annual reporting requirements. Our operators also must comply with the anti-market manipulation rules enforced by the FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Additionally, the FTC has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1,510,803 per day (annually adjusted for inflation) for 2025 soon to be adjusted for 2026 and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1,487,712 per day (annually adjusted for inflation) for 2025 soon to be adjusted for 2026 or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject our operators to civil penalty liability, as described in “Items 1 and 2: Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.”

In the United States, no comprehensive climate change legislation has been implemented. However,Under previous presidential administrations, the EPA has adopted rules that, among other things, established construction and operating permit reviews for GHG emissions from certain large stationary sources, required the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implemented GHG emissions limits on vehicles manufactured for operation in the United States. However, fromfollowing timethe tochange in presidential administration, in February 2026, the EPA formally rescinded its “Endangerment Finding”, which provided the support underpinning the majority of the agency’s GHG-related regulations. At this time, certainit administrationsremains uncertain what impacts the rescission will have takenupon current regulations and whether any further actions towill repealbe ortaken reviseby suchPresident climate-related actions. For example, the regulation of methane from crude oil and natural gas facilities has been subject to uncertainty in recent years.Trump. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Regulation of Greenhouse Gas Emissions.” Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, in 2021, President Biden recommitted the United States to the Paris Agreement, which requires member states to submit non-binding, individually determined reduction goals every five years. In December 2024, President Biden unveiled a new emissions target, seeking to cut emissions by 61-66% from 2005 levels by 2035. Subsequent United Nations climate conferences have called for additional action to transition away from fossil fuels and control or otherwise reduce GHG emissions, though none have been legally binding. However, the Trump Administration has formally begun the process of re-withdrawing from the Paris Agreement, and the United States’ participation in future United Nations climate-related conferences is unclear. Therefore, the full impact of these actions cannot be predicted at this time.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates in public office.States. Litigation risks are also increasing, as a number of entities have sought to bring suit against crude oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There have also recently been increasing financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies or seek to require more aggressive action with respect to climate-related risks.risks, Therealthough isthis alsotrend ahas riskbeen that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector.declining. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Regulation of Greenhouse Gas Emissions.”

In addition, a number of lawsuits have been filed in some states, including Texas, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states arehave seeking to imposeimposed additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, Texas has imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. In some instances, regulators may also order that disposal wells be shut-in. For example, in December 2023, the TRRC issued a notice to suspend the permits of all deep disposal wells within the Northern Culberson-Reeves Seismic Response Area and in May 2024, the TRRC released a seismicity response plan curtailing permitted injection volumes for certain wells in the Stanton Seismic Response Area. Most recently, in May 2025, the TRRC released updated guidance for disposal well permits in the Permian Basin that placed new limits on maximum injection pressure and volumes to ensure safety.

Crude oil and natural gas operations in HighPeak Energy’s operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit HighPeak Energy’s ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay HighPeak Energy’s operations or materially increase its operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species, other protected species (such as migratory birds), or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where HighPeak Energy operates as threatened or endangered could cause it to incur increased costs arising from species protection measures or could result in limitations on its activities that could have a material and adverse impact on its ability to develop and produce reserves. For example, in May 2024, the dunes sagebrush lizard was listedlisted, and,although this decision has been challenged. And, in November 2022, the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA, although thisin decisionMarch has2025, beenthe challenged.U.S. District Court for the Western District of Texas vacated the rule for the northern distinct population segment. If these species or others are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Endangered Species Act and Migratory Birds.”

HighPeak Energy mayhas notsuspended bethe ablepayment to payof dividends on our common stock.stock and may not resume paying dividends in the future.

Beginning in the first quarter of 2026, we suspended the payment of quarterly dividends on our common stock. There can be no assurance that we will resume paying dividends, and any decision to resume paying dividends will be solely within the discretion of, and subject to approval by, our Board of Directors. Our Board of Directors may elect to declare cash dividends on our common stock, subject to our compliance with applicable law and the Credit Agreements. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board of Directors, and we have no obligation to pay any dividends at any time. Our Board of Director’sDirector's determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the Board of Directors deems relevant at the time of such determination. We may determine not to resume paying dividends, or to pay dividends at reduced levels, depending on prevailing market conditions, our financial performance and liquidity needs, and other considerations.

TheIn Principaladdition, Stockholderuntil Groupthe collectivelyHighPeak ownsFunds Distributions are completed, we are currently a majority of HighPeak Energy’s outstanding voting stock. Therefore, HighPeak Energy is a “controlled company” within the meaning of Nasdaq rules and qualify for exemptions from certain corporate governance standards.requirements. 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:

HighPeak Energy, Inc., a Delaware corporation, was 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 December 31, 2024,2025, the assets consisted of two highly contiguous leasehold positions of approximately 154,368154,472 gross (141,907142,560 net) acres, approximately 64%72% of which were held by production, with an average working interest of 92%. 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 97%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 year ended December 31, 2024,2025, approximately 88%85% and 12%15% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2024,2025, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew and expects to average twoone (21) drilling rigsrig and approximately one (1) frac crew during 20252026 under our current development plan.plan, depending on certain market conditions.

Dividends and dividend equivalents. In February, May, August and November 2024,2025, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.1$5.0 million, $5.0 million, $5.0 million and $5.0 million, respectively, in dividends being paid on March 25, 2024,2025, June 25, 2024,2025, September 25, 20242025 and December 23, 2024,2025, respectively. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $530,000$531,000 in March 2024,2025, $538,000$531,000 in June 2024,2025, $534,000$531,000 in September 20242025 and $531,000$502,000 in December 2024.2025. In addition, the Company accrued an additional combined $84,000$86,000 in March 2024,2025, $84,000 in June 2024,2025, $86,000$31,000 in September 20242025 and $86,000$3,000 in December 20242025 in dividends on the restricted stock issued to directors, management directors and certain employees that was paid or will be payable upon vesting, assuming no forfeitures.

Crude Oil and Natural Gas Industry Considerations. Since mid-2020, crude oil prices have improved, with demand steadily increasing. In addition, sanctionsSanctions 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. InThe April 2023, OPEC announced production cuts of around 1.16 million Bopd. On June 4, 2023, OPEC agreed to extend these previously announced production cuts through the end of 2024. On July 3, 2023, Saudi Arabia announced it was extending voluntary cuts through August 2023. However, as a result of current global supply and demand imbalances, crude oil and natural gas prices remain strong, although down from the prior year. In addition, theongoing war between Russia and UkraineUkraine, and ongoing conflict between Israel and Hamas and other tensionsconflicts in the Middle EastEast, and U.S. intervention in Venezuela have resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by recentthe developmentstariffs inand proposed tariffs by the Israel-Hamascurrent conflict.administration. Specifically, the Company’s 20232023, 2024 and 20242025 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 Israel-HamasMiddle conflict,East and U.S. intervention in Venezuela, (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.

The markets for the commodities produced by our industry strengthened in 2021 continuing into 2023. However, they began declining in 2024 and continued to remaindecline strongin through 20242025 and intoearly 2025,2026 althoughdue theto marketconcerns over trade wars and energy tariffs, among other factors, and has decreased from 2022 levels overall, as a result of increased demandsupply outpacing increased supplydemand for each of the commodities we produce. PricesThis fordecline in commodity prices through 2025 and into 2026 contributed to the commoditiesCompany's producedneed byto ourenter industryinto improvedamendments fromto historicits lowsTerm Loan Credit Agreement and Senior Credit Facility Agreement to address potential financial covenant compliance issues. There can be no assurance that commodity prices will improve sufficiently to enable the Company to comply with the financial covenants under its credit facilities when the required asset coverage ratio and total net leverage ratio levels reset to more stringent levels in 2020,the withSecond crudeQuarter oilof and2026. natural gas prices reaching their highest average annual price since 2014. However, thereThere 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 conflictspossibility of trade wars, the ongoing war between Russia and UkraineUkraine, conflicts in the Middle East, U.S. intervention in Venezuela, and between Israel and Hamas, 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,I. Item 1A. Risk Factors.”

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a twoone (21) drilling rig program for 2025.2026 depending on certain market conditions. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. If the Company is unable to maintain compliance with its financial covenants or obtain further amendments or waivers from its lenders, it may be required to reduce its capital expenditures, which could adversely impact its ability to develop its acreage, maintain its leasehold positions and grow its production. 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.

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 and Wells Fargo Securities, LLC have beenwas retained as a financial advisorsadvisor with respect to this strategic alternatives process. To date, however, this process has been exploratory in nature and accordingly remains in preliminary stages, with our discussions to date with prospective counterparties generally excluding substantive discussions regarding potential valuation, structure or other key transaction terms. 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.

Derivative financial instrument exposure. As of December 31, 2024,2025 and factoring in derivative instruments entered into subsequent to year end, the Company was a party to the following open crude oil derivative financial instruments.

The estimated fair value of the outstanding open derivative financial instruments as of December 31, 20242025, excluding those contracts entered into subsequent to December 31, 2025, was a net asset of $2.2$33.0 million which is included in current and noncurrent assets and current and noncurrent liabilities on the Company’s consolidated balance sheet as of December 31, 2024.2025. During the year ended December 31, 2024,2025, the Company recognized a net derivative lossgain of $46.5$44.9 million, including a $32.2$30.8 million mark-to-market lossgain and $14.3$14.1 million in net monthly settlement payments.receipts.

The increasedecrease in average daily Boe sales volumes for the year ended December 31, 2024,2025, compared with 20232024 was due to the natural decline on its producing properties and decreased drilling and completion activities, partially offset by the Company tying in all of its existing production facilities into natural gas gathering, processing and treating facilities and maintaining relatively flat crude oil production utilizing only a two-rig drilling program throughout 2024.facilities.

As detailed above, the decrease in total operating revenues for the year ended December 31, 20242025 compared to the same period in 20232024 is the result of a 12%20% decrease in average realized price per Boe partiallyin offsetaddition byto a 10%3% increasedecrease in average daily sales volumes primarily as a result of thenatural Company’sdecline successfuland decreased drilling program.and completion activities of the Company due to the lower commodity price environment.

In general, production taxes and ad valorem taxes are directly related to production and commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices and valuations as of the first of the year, whereas production taxes are based upon current year commodity prices and sales volumes. Production and ad valorem taxes are as follows (in thousands):

Production taxes per Boe for the year ended December 31, 2024,2025, compared with 2023,2024, decreased primarily due to the 12%20% overall decrease in realized sales prices.prices and 3% decrease in average daily sales volumes in addition to a $10.0 million natural gas severance tax refund that was realized by taking advantage of previously unrealized marketing deductions allowed by the State of Texas. The increasedecrease in ad valorem taxes per Boe for the year ended December 31, 2024,2025, compared with 2023,2024, was primarily due to the increasesuccessful in commodity prices in 2023 and a significant numberefforts of wellsthe thatCompany cameto reduce the taxable valuation by the state on productionnumerous duringproperties 2023throughout thatour had no ad valorem tax in 2023. 2024 was the first year these wells were assessed ad valorem taxes.portfolio. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.

The decreaseincrease in exploration and abandonment expenses is primarily the result of $3.3an $11.1 million lessunsuccessful exploratory well that was realized in 2025, $2.4 million in additional plugging and abandonment expenses over the prior year due to more wells failing fluid tests and requiring plugging according to state regulations, $1.3 million more in abandoned leasehold costs related to undeveloped acreage that was not in an area where the Company had current plans to drill and thus the leases were allowed to expire in 2023.2025 and $416,000 in increased geologic and geophysical personnel costs. This is the first unsuccessful well drilled by the Company in its history and was a step out to the furthest northeast portion of its acreage. While other wells in the area were successful, one well was written off because it never achieved commercial volumes of crude oil and natural gas after attempting interventions to reduce anomalous water inflows. The Company remains committed to maintaining as much of its undeveloped acreage leasehold position as possible, but from time to time, certain acreage is not able to be extended at reasonable prices and we are not able to get a drilling rig in the area in time to save the leases for a multitude of reasons. In addition, the Company spent $194,000 less in 2024 on plugging various old vertical wells across our acreage position in accordance with applicable regulations.

The increasedecrease in DD&A expense is primarily due to the increaseddecreased production associated with the natural decline of our successfulwells horizontaland decreased drilling programand incompletion additionactivities tocoupled anwith increasea decrease in the DD&A rate primarily attributed to increased infrastructureproved andreserves associatedat coststhe asend weof test2024, newreducing areas.the rate that was recognized during the first three quarters of 2025. Based on year-end 20242025 proved reserves, we anticipate our DD&A rate going into 20252026 to be in the $23.00$27.52 per Boe range, similar to the fourth quarter of 2024.2025.

The increase in general and administrative expense for the year ended December 31, 20242025 is primarily as a result of salarythe increasesresignation and annualretirement bonusesof inour additionformer toChief anExecutive Officer which accounted for approximately $3.4 million of the increase and the increase in internallegal, insurance and external audit costs and legal expenses related to the growth of the Company.expenses.

The decrease in noncash stock-based compensation expense is due to fewer awards granted in 2024 compared with 2023.recently.

The increasedecrease in interest expense can be primarily attributed to higherlower interest rates in 20242025 compared to 2023, but more importantly, to increased borrowings under the Term Loan Credit Agreement beginning2024 in Septemberaddition 2023, partially offset byto lower amortization of discounts and debt issuance costs with the longeramendment termof onTerm theLoan newCredit debt issuancesAgreement in 2023.September 2025.

Derivative loss,gain (loss), net.

Derivative loss,gain (loss), net is as follows (in thousands):

IncomeProvision taxfor expense.income taxes.

The change in provision for income tax expensetaxes during the year ended December 31, 2024,2025, compared with 2023,2024, was due to decreased net income during the year ended December 31, 20242025 compared with 2023.2024. The effective income tax rate differs from the statutory rate primarily due to a revision on the deferred tax asset related to certain wage and stock-based compensation and permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information.

Liquidity. The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, including remaining cash proceeds from our $1.2 billion Term Loan Credit Agreement, (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) other sources, such as 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 amortizationamortizations 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 20252026 planned capital expenditures and provide adequate liquidity to fund other needs, however this may be subject to significant uncertainty due to changes in crude oil, NGL and natural gas pricing and potential covenant compliance issues under its debt instruments described below and no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.

Debt Refinancing.Refinancing and Recent Amendments. In September 2023, we completed a refinancing of our long-term debt in its entirety by entering into an agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement matureswas set to mature on September 30, 2026.2026 prior to the amendments discussed below. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00% of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.

The Term Loan Credit Agreement also containscontained certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter.quarter prior to the amendments discussed below. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio.

The Term Loan Credit Agreement containscontained customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.

20252026 capital budget. The Company’s capital budget for 20252026 is expected to be in the range of approximately $375$255 to $405$285 million for drilling, completion, facilities and equipping crude oil wells plus $40 to $50 million forwells, field infrastructure buildout and other costscosts, andexcluding $33 - $35 million on one-time infrastructure expenditures.acquisitions. The 20252026 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses and general and administrative expenses and corporate facilities.expenses. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its consolidated balance sheet, cash generated by operations and borrowingsborrowing capacity available under theits Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the year ended December 31, 20242025 were $604.3$511.8 million, including the completion and/or continuation of certain one-time infrastructure projects but excluding acquisitions.

The budget above assumes that the Company will operate an average of two (2) drilling rigs and an average of one (1) frac crew during 2025. However, there are many factors and consequences beyond the Company’s control,control impacting our capital budget, such as policiespolitical ofand regulatory uncertainties associated with the new Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, andOPEC or OPEC+, and othergovernments cooperatingin countries,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.” Given the dynamic nature of this situation, theThe 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.

HighPeak Energy, Inc., a Delaware corporation, was 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 MarchJune 31,30, 2026, the assets consisted of two highly contiguous leasehold positions of approximately 152,201153,627 gross (140,439139,833 net) acres, approximately 74% of which were held by production, with an average working interest of 92%.91%. 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 threesix months ended MarchJune 31,30, 2026, approximately 84%83% and 16%17% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of MarchJune 31,30, 2026, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew and expects to average one (1) drilling rig and less than one (1) frac crew during the remainder of 2026 under our current development plan, depending on certain market conditions.

Transactions and Recent EventsDevelopments

Debt amendments and actions taken to bolster covenant compliance. 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 date was extended two years to September 2028, (ii) the 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.

Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company has entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things (i) the Company willhas bebeen required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourthfourth Quarterquarter of 2025 and the Firstfirst Quarterquarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company willhas bebeen required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the Fourthfourth Quarterquarter of 2025 and the Firstfirst Quarterquarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations willhas bebeen increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026Company’s reserve report as of December 31, 2025 and (iv) the Company will beis prohibited from making quarterly dividends on its common stock until September 30, 2026. For the Second Quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels currently in effect for such quarters prior to this amendment. It is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the Second Quarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. Any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder.

Acquisitions. During the threesix months ended MarchJune 31,30, 2026, the Company incurred a total of $127,000$2.6 million in acquisition costs related to lease extensions and to acquire additional crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage to its Flat Top and Signal Peak operating areas.

GivenIn response to the dynamicgrowing natureglobal crude oil supply constraints and the improved commodity pricing environment that began in March of this2026 situation,that we consider temporary, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a one (1) drilling rig program for 2026 depending on certain market conditions. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. If the Company is unable to maintain compliance with its financial covenants or obtain further amendments or waivers from its lenders, it may be required to reduce its capital expenditures, which could adversely impact its ability to develop its acreage, maintain its leasehold positions and grow its production. 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.

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. ToEvercore date,Group however, this processL.L.C. has been exploratoryretained inas naturea andfinancial accordingly remains in preliminary stages,advisor with our discussionsrespect to datethis withongoing prospectivestrategic counterpartiesalternatives generally excluding substantive discussions regarding potential valuation, structure or other key transaction terms.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.

The Company's financial and operating performance for the three months ended MarchJune 31,30, 2026 included the highlights described below and comparative discussion of related drivers for the three months ended MarchJune 31,30, 2025:

Crude oil derivative financial instrument exposure. As of MarchJune 31,30, 2026 and factoring in derivative instruments entered into subsequent to quarter end, the Company was party to the following open crude oil derivative financial instruments.

Natural gas derivative financial instrument exposure. As of MarchJune 31,30, 2026,2026 and factoring in derivative financial instruments entered into subsequent to quarter end, 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 MarchJune 31,30, 2026 was a net liabilityasset of $106.5$1.6 million which is included in current assets and current and noncurrent liabilities on the Company’s condensed consolidated balance sheet as of MarchJune 31,30, 2026. During the threesix months ended MarchJune 31,30, 2026, the Company recognized a net derivative loss of $157.0$103.6 million, including a $139.5$31.4 million mark-to-market loss and $17.5$72.2 million in net monthly settlement payments.

The Company’s liquids production was 84%83% of total production on a Boe basis for the threesix months ended MarchJune 31,30, 2026.

The following table sets forth the total number of horizontal producing wells drilled and completed during the threesix months ended MarchJune 31,30, 2026:

As of MarchJune 31,30, 2026, HighPeak Energy was developing its properties using one (1) drilling rig.rig and one (1) frac crew. The continued threatconflict ofin a potential recession,Iran, 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 other 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 threesix months ended MarchJune 31,30, 2026, the Company successfully completed and placed on production twelvetwenty (1220) gross (12.019.6 net) horizontal wells. As of MarchJune 31,30, 2026, the Company had sixteen (16) gross (15.915.6 net) horizontal wells that had been drilled and were in various stages of completion. In addition, as of MarchJune 31,30, 2026, the Company was in the process of drilling twofive (25) gross (1.94.8 net) horizontal wells. The frac crew which was reassigned in early March returned in early April to begin fracing the Company’s wells once again. This is part of a program of frac pauses planned throughout the year given that one frac crew can outpace one drilling rig.

Three and Six Months Ended MarchJune 31,30, 2026

The decrease in average daily Boe sales volumes for the three and six months ended MarchJune 31,30, 2026, compared with the same periodperiods in 2025 was primarily due to lower crude oil sales volumes as a result of reduced development activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

As detailed above, the decreaseincrease in total operating revenues for the three months ended MarchJune 31,30, 2026 compared to the same periodsperiod in 2025 is the result of a 14%35% increase in average realized price per Boe partially offset by a 7% decrease in average daily sales volumes primarily as a result of lower crude oil sales volumes as a result of reduced development activity and natural decline. Also detailed above, the decrease in total operating revenues for the six months ended June 30, 2026 compared to the same period in 2025 is the result of a 11% decrease in average daily sales volumes primarily as a result of lower crude oil sales volumes as a result of reduced development activity and natural decline pluspartially anoffset 8%by decreasea 12% increase in average realized price per Boe.

The decrease in crude oil and natural gas production costs for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in 2025 can be attributed primarily to decreased expense workover costs and chemical and treating costs related to third party midstream expansions and debottlenecking.debottlenecking and communication expenses.

Gathering, processing and transportation expenses per Boe for the three and six months ended MarchJune 31,30, 2026 increased compared to the same periodperiods in 2025. This is primarily related to connecting more natural gas to processing facilities that were not previously connected, thereby enhancing the Company’s ability to maximize returns from its wells by increasing sales volumes. The slightly higher increase in the per Boe amounts can be attributed to the increase in NGL and natural gas as a total component of our product mix when calculating Boe.

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 decreaseincrease in production and ad valorem taxes during the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 can be attributed primarily to the aforementioned 14%26% increase in operating revenues partially offset by lower ad valorem taxes and the decrease in salesproduction volumesand coupledad withvalorem taxes during the 8%six decreasemonths ended June 30, 2026 compared to the same period in overall2025 commoditycan pricesbe received.primarily attributed to lower ad valorem taxes.

The decreaseincrease in production taxes per Boe for the three and six months ended MarchJune 31,30, 2026, compared with the same periodperiods in 2025 can be attributed primarily to the increased commodity prices and the lower sales volumes thus far in 2026. The change in ad valorem taxes per Boe for the three and six months ended MarchJune 31,30, 2026, compared with the same periodperiods in 2025, was primarily due to naturalthe declineexpected from wells put on linedecrease in recentad yearsvalorem coupledtaxes withexpected thefor decreased activity of the Company.2026.

The increase in DD&A during the three and six months ended MarchJune 31,30, 2026 is primarily due to an increase in the DD&A rate primarily attributable to decreased proved reserves partially offset by decreased sales volumes.

The decreaseincrease in general and administrative expense in total for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in 2025 is primarily a result of higher cash compensation to independent members of our Board of Directors and increased legal and audit expenses partially offset by decreased wages and benefits primarily related to the retirement of the Company’s former chief executive officer in September 2026.2025. The increase in stock-based compensation expense for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in 2025 is the result of restricted stock issued to certain employees of the Company in January 2026.

The decrease in interest expense can be attributed to a decrease in amortization of discounts and debt issuance costs related to the refinancing of the Company’s debt in August 2025 and lower interest rates in 2026 compared with interest rates in 2025 partially offset by an increased outstanding debt balance.balance in 2026 compared to 2025.

The Company primarily utilizes commodity swap contracts, costless collars, roll swaps and basis swaps 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 lossgains and losses and cash settlements relate to crude oil derivative swap contracts, costless collarscollars, roll swaps and basis swaps and natural gas derivative swap contracts.contracts and basis swaps.

The change in provision for income taxes during the three and six months ended MarchJune 31,30, 2026, compared with the same periodperiods in 2025, was primarily due to the change in income (loss) before income taxes mainly due to the significant increase in derivative losses.gains and losses as well as the reversal of an annualized loss limitation during the three months ended June 30, 2026 that was recognized during the three months ended March 31, 2026 which was reversed primarily due to the large increase in commodity prices that resulted in an increase in income before income taxes. The effective income tax rate differs from the statutory rate primarily due to Texas state margin taxes and other permanent differences between GAAP income and taxable income. See Note 13 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” for additional information.

As of MarchJune 31,30, 2026, the Company was in compliance with the financial covenants under its Term Loan Credit Agreement and Senior Credit Facility Agreement, as amended. In particular, we recently entered into credit facility amendments described below to ensure our continued compliance with covenants in our debt instruments, but it is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the Secondthird Quarterquarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. If the Company is unable to maintain compliance with its financial covenants or successfully implement the measures described above, its liquidity and capital resources would be materially and adversely affected. Specifically, the Company's borrowing availability under its Senior Credit Facility Agreement, which was approximately $92.1 million as of MarchJune 31,30, 2026, could be reduced or eliminated, and the Company may be unable to access additional debt or equity financing on acceptable terms or at all. In addition, any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder. If such amounts were accelerated and became immediately due and payable, the Company does not expect it would have sufficient liquidity to repay such indebtedness and would likely need to pursue a restructuring, refinancing or other strategic alternatives, which may not be available on acceptable terms or at all.

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 date was extended two years to September 2028, (ii) the 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.

Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company has entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things, (i) the Company willhas bebeen required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourthfourth Quarterquarter of 2025 and the Firstfirst Quarterquarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company willhas bebeen required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the Fourthfourth Quarterquarter of 2025 and the Firstfirst Quarterquarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations willhas bebeen increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026Company’s reserve report as of December 31, 2025 and (iv) the Company will beis prohibited from making quarterly dividends on its common stock until September 30, 2026. For the Second Quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to these amendments.

2026 capital budget. The Company’s capital budget for 2026 is expected to be in the range of approximately $255 to $285 million for operated and non-operated drilling, completion, facilities and equipping crude oil wells, field infrastructure buildout and other costs, excluding acquisitions. The 2026 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 year ended December 31, 2025 were $511.8 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,uncertainties, 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,II, Item 1A. Risk Factors.Factors” of this Quarterly 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.

Operating activities. The decrease in net cash flow provided by operating activities for the threesix months ended MarchJune 31,30, 2026, compared with the same period in 2025, was primarily related to a decrease in discretionary cash flow as a result of a decrease in revenuesderivative less operating and general administrative expensessettlements of approximately $49.4$76.5 million associated with lowerhigher overall commodity prices and loweran salesincreased volumesamount of derivative transactions entered into by the Company in accordance with its Term Loan Credit Agreement and Senior Credit Facility Agreement coupled with changesan overall increase in operatingaccounts assetsreceivable andchanges liabilitiesof that$41.3 differmillion fromrelated theto priorincreased yearcommodity period.prices.

Investing activities. The decrease in net cash used in investing activities for the threesix months ended MarchJune 31,30, 2026, compared with 2025, 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.

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 MarchJune 31,30, 2026, 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 but are significantly down from the past two years. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing war between Russia and Ukraine, conflicts in the Middle East, and U.S. intervention in Venezuela. 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 threesix months ended MarchJune 31,30, 2026 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the threesix months ended MarchJune 31,30, 2026 would have increased (decreased) the Company’s revenues by approximately $11.7$11.5 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the threesix months ended MarchJune 31,30, 2026 would have increased (decreased) the Company’s revenues by approximately $1.6$1.7 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 MarchJune 31,30, 2026, 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 $7.9$6.8 million. Additionally, as of MarchJune 31,30, 2026, 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 $1.0 million.$729,000.

There have been no material changes in our critical accounting policies and procedures during the three months ended MarchJune 31,30, 2026. 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.