HighPeak Energy, Inc.: Form 10-Q for the period ended Mar 31, 2025

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

Overview

HighPeak Energy, Inc., a Delaware corporation, 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 March 31, 2025, the assets consisted of two highly contiguous leasehold positions of approximately 154,810 gross (143,098 net) acres, approximately 65% 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 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 three months ended March 31, 2025, approximately 86% and 14% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of March 31, 2025, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew and expects to average one to two (1-2) drilling rigs and approximately one (1) frac crew during the remainder of 2025 under our current development plan.

Recent Events

Dividends and dividend equivalents. In February 2025, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.0 million in dividends being paid in March 2025. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $531,000 in March 2025 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $86,000 in March 2025 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Acquisitions and divestitures. During the three months ended March 31, 2025, the Company incurred a total of $2.5 million in acquisition costs related to lease extensions and to acquire crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas. In addition, during the three months ended March 31, 2025, the Company received $570,000 in proceeds from the sale of some non-core non-operated properties.

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

In early 2025, OPEC began unwinding prior voluntary production cuts, which added approximately 400,000 barrels per day to the global crude oil market. This substantial supply boost contributed to a decline in global crude oil prices during the three months ended March 31, 2025. Concurrently, in March 2025, the U.S. imposed tariffs on energy imports from Canada and Mexico, set at 10% and 25%, respectively, and expanded tariffs to include all steel and aluminum imports, aiming to bolster domestic production. In addition, in early April 2025, the current administration began announcing a substantial number of trade tariffs, including a new universal baseline reciprocal tariff of 10%, plus an additional country-specific reciprocal tariff for select trading partners, on all U.S. imports, although imports of crude oil, natural gas and refined products received exemptions from the tariffs. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff applied to China, which the administration increased. Concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed further downward pressure on oil prices. With negotiations and countermeasures still ongoing, the situation is fluid, and we expect price volatility to continue over the next few months. Collectively, these policy changes—OPEC's production increase and the U.S. tariffs—are introducing significant volatility to the crude oil and natural gas sector. In addition, tariffs have the potential to significantly increase our operating and capital costs, which could negatively impact our ability to carry out our planned drilling program and future growth projects.

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

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

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

Outlook

HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend heavily on prevailing commodity prices. The crude oil and natural gas industry is cyclical and commodity prices are highly volatile and subject to a high degree of uncertainty. For example, during the period from January 1, 2021 through March 31, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2024 and into 2025, although the market has decreased from 2022 levels overall, as a result of increased demand outpacing increased supply for each of the commodities we produce. Prices for the commodities produced by our industry improved from historic lows in 2020, with crude oil and natural gas prices reaching their highest average annual price since 2014. However, there are many factors beyond the Company’s control, including commodity markets, unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services or supply constraints remain subject to heightened levels of uncertainty as a result of the conflicts between Russia and Ukraine 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. Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 10, 2025.

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

Strategic Alternatives

On January 23, 2023, the Company announced the intention of its Board to initiate a process to evaluate certain strategic alternatives to maximize shareholder value, including a potential sale of the Company. Texas Capital Securities has been retained as a financial advisor with respect to this strategic alternatives process. 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.

Financial and Operating Performance

The Company's financial and operating performance for the three months ended March 31, 2025 included the highlights described below and comparative discussion of related drivers for the three months ended March 31, 2024:

• Net income was $36.3 million ($0.26 per diluted share) for the three months ended March 31, 2025 compared with $6.4 million for three months ended March 31, 2024. The primary components of the $29.9 million increase in net income include:
• a $45.1 million decrease in the Company’s derivative instruments loss from $53.0 million in the prior year period compared with $7.9 million in the current year quarter as a result of its crude oil and natural gas commodity contracts entered into and the change in crude oil and natural gas prices thereafter;
• a $21.5 million decrease in DD&A expense due to a 21% decrease in the DD&A rate from $28.92 to $22.86 per Boe as a result of a significant increase in proved reserves at the end of 2024;
• a $6.6 million decrease in the Company’s interest expense as a result of a decrease in the principal balance due to quarterly amortization payments and lower interest rates experienced; and
• a $3.6 million decrease in the Company’s stock-based compensation expense primarily due to a the majority of stock-based compensation instruments reaching fully vested status and thus have no further stock-based compensation expense to be recognized;

Partially offset by:

• a $30.3 million decrease in crude oil, NGL and natural gas revenues due to a 15% decrease in average realized commodity prices per Boe, excluding the effects of derivatives, partially offset by a 7% increase in daily sales volumes resulting primarily from increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking;
• a $7.6 million increase in the Company’s income tax expense primarily due to an increase in income before income taxes;
• a $5.3 million increase in the Company’s crude oil and natural gas production costs primarily as a result of increased expense workover costs with increased well cleanouts and pump changes with our aging well population, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper and roustabout costs also due to the increased number of wells operated;
• a $1.7 million increase in the Company’s general and administrative expenses primarily attributable to higher wages and benefits as well as an increase in professional fees, all primarily as a result of the growth of the Company; and
• a $1.6 million decrease in the Company’s interest income due to the decreased cash on hand.

30

• During the three months ended March 31, 2025, average daily sales volumes totaled 53,128 Boepd, compared with 49,729 Boepd during the same period in 2024, an increase of 7%, primarily due to increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking.
• Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended March 31, 2025 to $71.64, compared with $77.65 for the same period in 2024. Weighted average NGL prices per Bbl decreased during the three months ended March 31, 2025 to $24.21, compared with $24.94 for the same period in 2024. Weighted average natural gas prices per Mcf increased to $2.34 during the three months ended March 31, 2025, compared with $1.33 during the same period in 2024.
• Cash provided by operating activities totaled $157.1 million for the three months ended March 31, 2025, compared with $171.4 million for the three months ended March 31, 2024.

Derivative Financial Instruments

Crude oil derivative financial instrument exposure. As of March 31, 2025, the Company was a party to the following open crude oil derivative financial instruments.

Natural gas derivative financial instrument exposure. As of March 31, 2025, the Company was a party to the following open natural gas derivative financial instruments.

The estimated fair value of the outstanding open derivative financial instruments as of March 31, 2025 was a net liability of $2.7 million which is included in current assets and current liabilities on the Company’s consolidated balance sheet as of March 31, 2025. During the three months ended March 31, 2025, the Company recognized a net derivative loss of $7.9 million, including a $4.8 million mark-to-market loss and $3.1 million in net monthly settlement payments.

Operations and Drilling Highlights

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

The Company’s liquids production was 86% of total production on a Boe basis for the three months ended March 31, 2025.

Costs incurred are as follows (in thousands):

The following table sets forth the total number of horizontal producing wells drilled and completed during the three months ended March 31, 2025:

As of March 31, 2025, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew. The continued threat of an extensive recession, the scope, duration and magnitude of the direct and indirect effects of pandemics, the war between Russia and Ukraine, the Israel-Hamas conflict and the production cuts 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 three months ended March 31, 2025, the Company successfully completed and placed on production thirteen (13) gross (12.9 net) horizontal wells, all in the Flat Top area. As of March 31, 2025, the Company had twenty-one (21) gross (21.0 net) horizontal wells that had been drilled and were in various stages of completion and two (2) gross (2.0 net) salt-water disposal wells in progress, all in the Flat Top area. In addition, as of March 31, 2025, the Company was in the process of drilling seven (7) gross (7.0 net) horizontal wells, all in the Flat Top area.

Results of Operations

Three Months Ended March 31, 2025

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

The increase in average daily Boe sales volumes for the three months ended March 31, 2025, compared with the same period in 2024 was primarily due to increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

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

Revenue Variance Analysis.

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

As detailed above, the decrease in total operating revenues for the three months ended March 31, 2025 compared to the same period in 2024 is the result of a 15% decrease in average realized price per Boe partially offset by a 7% increase in average daily sales volumes primarily as a result of increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

Crude Oil and natural gas production costs.

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

The increase in crude oil and natural gas production costs compared to the first quarter 2024 can be attributed primarily to increased expense workover costs with increased well cleanouts and pump changes with our aging well population, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper and roustabout costs also due to the increased number of wells operated.

Production and ad valorem taxes.

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

In general, production taxes and ad valorem taxes are directly related to commodity sales volumes and price changes; however, Texas ad valorem taxes are based upon an asset valuation assessed by the state as of January 1 of that particular year based on prior year commodity prices, whereas production taxes are based upon current year sales revenues at current commodity prices. Overall, the increase in production and ad valorem taxes during the three months ended March 31, 2025 compared to the same period in 2024 can be attributed primarily to an increase in ad valorem taxes due to an over-accrual that was reversed during the three months ended March 31, 2024 that was not realized in the current year partially offset by the 15% decrease in overall commodity prices received partially offset by the aforementioned 7% increase in sales volumes.

Production and ad valorem taxes per Boe are as follows:

The decrease in production taxes per Boe for the three months ended March 31, 2025, compared with the same period in 2024 can be attributed primarily to the lower commodity prices received thus far in 2025. The increase in ad valorem taxes per Boe for the three months ended March 31, 2025, compared with the same period in 2024, was primarily due to the aforementioned reversal of an over-accrual from 2023 during the three months ended March 31, 2024 that was not realized during the current year.

Exploration and abandonments expense.

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

Exploration and abandonment costs decreased during the three months ended March 31, 2025 primarily due to less plugging and abandonment expenses, geologic and geophysical data costs and abandoned leasehold costs.

DD&A expense.

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

The decrease in DD&A during the three months ended March 31, 2025 is primarily due to a decrease in the DD&A rate primarily attributable to increased proved reserves partially offset by the increased production.

General and administrative expense.

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

The increase in general and administrative expense and general and administrative expense per Boe for the three months ended March 31, 2025 is primarily a result of increased wages and benefits related to the growth of the Company in addition to higher professional services costs related to the growth of the Company.

Interest expense.

35

The decrease in interest expense can be attributed to a lower overall debt balance in 2025 compared with 2024, lower interest rates in 2025 compared with interest rates in 2024, and fewer calendar days compared to the same period in the prior year.

Loss on derivative instruments, net.

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

Provision for income taxes.

The change in provision for income taxes during the three months ended March 31, 2025, compared with the same period in 2024, was primarily due to the change in income before income taxes and the reversal of a deferred tax asset related to a temporary difference from restricted stock being reclassified to a permanent difference. The effective income tax rate differs from the statutory rate primarily due to certain aforementioned stock-based compensation revisions, Texas state income taxes and other permanent differences between GAAP income and taxable income. See Note 12 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)" for additional information.

Liquidity and Capital Resources

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

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

2025 capital budget. The Company’s capital budget for 2025 is expected to be in the range of approximately $375 to $405 million for drilling, completion, facilities and equipping crude oil wells plus $40 to $50 million for field infrastructure buildout and other costs and $33 to $35 million on one-time infrastructure expenditures. The 2025 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses, general and administrative expenses and corporate facilities. 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 three months ended March 31, 2025 were $179.8 million, excluding acquisitions.

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

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

Operating activities. The decrease in net cash flow provided by operating activities for the three months ended March 31, 2025, compared with 2024, was primarily related to a decrease in discretionary cash flow as a result of a decrease in revenues less operating and general administrative expenses of approximately $38.0 million associated with lower overall commodity prices partially offset by increased production volumes and increased costs related primarily to increased expense workover costs with increased well cleanouts and pump changes with our aging well population, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper and roustabout costs also due to the increased number of wells operated partially offset by changes in operating assets and liabilities that differ from the prior year period.

Investing activities. The increase in net cash used in investing activities for the three months ended March 31, 2025, compared with 2024, was primarily due to increases in additions to crude oil and natural gas properties.

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

• Three months ended March 31, 2025: The Company made a mandatory amortization payment on its Term Loan Credit Facility totaling $30.0 million and paid dividends and dividend equivalents of $5.0 million and $531,000, respectively.
• Three months ended March 31, 2024: The Company made a mandatory amortization payment on its Term Loan Credit Facility of $30.0 million, paid $8.8 million to repurchase 565,540 shares of its common stock at an average cost of approximately $15.50 per share, excluding any potential excise taxes, and paid dividends and dividend equivalents of $5.1 million and $530,000, respectively.

Interest Rate Risk. We are exposed to market risk due to the floating interest rates associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of March 31, 2025, we had a $1.05 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 six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.

Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing armed conflicts between Russia and Ukraine, Israel and Hamas and Israel and Iran. 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 three months ended March 31, 2025 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the three months ended March 31, 2025 would have increased (decreased) the Company’s revenues by approximately $14.7 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the three months ended March 31, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis.

We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of March 31, 2025, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $4.7 million. Additionally, as of March 31, 2025, a $0.10 increase (decrease) in the forward curves associated with our natural gas commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $1.0 million.

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

Non-GAAP Financial Measures

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

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

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

New Accounting Pronouncements

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

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

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

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2025. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report.

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

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

During the period from January 1, 2021 through March 31, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the three months ended March 31, 2025 would have increased (decreased) the Company’s revenues by approximately $14.7 million on an annualized basis, excluding the effects of derivatives, and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the three months ended March 31, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis, excluding the effects of derivatives.

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

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

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

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

The average forward prices based on May 8, 2025 market quotes were as follows:

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

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

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

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

Interest Rate Risk. As of March 31, 2025, we had $1.05 billion outstanding under the Term Loan Credit Agreement and had $93.1 million of available borrowing capacity under the Senior Credit Facility Agreement. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement and Senior Credit Facility Agreement. The Company also periodically has fixed rate debt but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The impact of a 1% increase in interest rates on our outstanding debt as of March 31, 2025 would have resulted in an annual increase in interest expense of approximately $10.5 million.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2025 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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

Potential new trade policies, such as tariffs, could adversely affect our operations, profitability and business.

There is currently significant uncertainty regarding the future relationship between the United States and various other countries arising from changes that may be implemented by the United States federal government, including with respect to trade policies, treaties, tariffs, taxes and other limitations on cross-border operations. Any actions taken by the United States’ federal government that restrict or could impact the economics of trade—including additional tariffs, trade barriers, and other similar measures—could have the potential to disrupt existing supply chains and trigger retaliatory efforts by other countries, including the imposition of tariffs, raising taxation, setting foreign exchange or capital controls, or establishing embargos, sanctions, or other import/export restrictions, thereby negatively impacting our business, both directly and indirectly. These developments, or the perception that more of them could occur, may create or increase business uncertainty and could materially adversely affect the global economy and stability of global financial markets, potentially reducing trade and depressing economic activity. Such changes in international trade policies may result in direct impacts to our business or indirectly to our customers or suppliers through increased costs, changes in business prospects or operating results, which could materially adversely affect our financial condition. The extent of such impacts cannot be predicted at this time.