HighPeak Energy, Inc. (HPK)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS {START HERE}

The following discussion and analysis should be read in conjunction with the other sections of this Annual Report, including but not limited to “Items 1 and 2. Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.” Historical financial statements and related notes included elsewhere in this Annual Report. This discussion contains “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. 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 and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report. Please read Cautionary Statement Concerning Forward-Looking Statements. Also, please read the risk factors and other cautionary statements described under “Part I, Item 1A. Risk Factors.” We assume no obligation to update any of these forward-looking statements, except as required by applicable law. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on March 6, 2024 for a discussion of the Company’s 2023 results of operations compared with the Company’s 2022 results of operations.

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 December 31, 2024, the assets consisted of two highly contiguous leasehold positions of approximately 154,368 gross (141,907 net) acres, approximately 64% 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% 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, approximately 88% and 12% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2024, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew and expects to average two (2) drilling rigs and approximately one (1) frac crew during 2025 under our current development plan.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2023 and into 2024, 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 in 2022 before cooling off slightly in 2023. However, 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 war in Ukraine, the conflict between Israel and Hamas, elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy’s ability to execute on its capital plan. Despite continuing impacts of these and other factors and future uncertainty, we expect to maintain 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.  Additionally, the impact of inflation as well as elevated interest rates continue to have a negative impact on our cash flows and results of operations.

Recent Events

Share Repurchase Program. In February 2024, the Company’s board of directors approved a common stock repurchase program to acquire up to $75.0 million of the Company’s outstanding common stock, excluding excise taxes and other expenses, which was subject to being suspended from time to time, modified, extended or discontinued by the board of directors at any time. The common stock repurchase program expired on December 31, 2024 (the “2024 Repurchase Program”). On March 6, 2025, the Company’s board of directors extended the program from its original expiration on December 31, 2024 and extended the program through December 31, 2025 (the “Repurchase Extension”). The Repurchase Extension did not alter any of the original terms of the 2024 Repurchase Program nor did it change the total amount provided for under the original 2024 Repurchase Program. HighPeak’s management the authority to repurchase shares opportunistically in the open market from time to time, through block trades, in privately negotiated transactions or by such other means which comply with applicable state and federal laws.  This is the Company’s second authorization for a stock repurchase program since its founding.

The Company intends to fund the repurchases from available working capital, cash provided from operations and borrowings under its Senior Credit Facility Agreement. The timing, number and value of shares repurchased under the program will be at the discretion of management and the Board of Directors and will depend on a number of factors, including general market and economic conditions, business conditions, the trading price of the Company’s common stock, the nature of other investment opportunities available to the Company and compliance with the Company’s debt and other agreements. The stock repurchase program does not obligate HighPeak to acquire any particular dollar amount or number of shares of its common stock and the stock repurchase program may be suspended from time to time, modified, extended or discontinued by the Company’s Board of Directors. The stock repurchase program authority will expire December 31, 2025.

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

Acquisitions. During the year ended December 31, 2024, the Company incurred a total of $14.8 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.

Crude oil sales contract. In September 2024, the Company entered into an amended and restated crude oil marketing contract with DK Trading & Supply, LLC (“Delek”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from the majority of its horizontal wells in Flat Top and Signal Peak where DKL is continually constructing a crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries. The contract contains a minimum volume commitment commencing May 2024 that totals $138.7 million based on the gross piped barrels delivered of 23,500 Bopd for the first ten years of the contract at a certain amount per barrel escalating throughout the term of the contract. However, the Company generally has the ability under the contract to cumulatively bank dollars based on excess volumes delivered to offset the minimum volume commitment. For the period from May 1, 2024 to December 31, 2024, the Company has delivered approximately 31,196 Bopd under the contract. The remaining monetary commitment as of December 31, 2024, if the Company never delivers any additional volumes under the agreement, is approximately $130.3 million.

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Crude Oil and Natural Gas Industry Considerations. Since mid-2020, crude oil prices have improved, with demand steadily increasing.  In addition, 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. In 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, the war between Russia and Ukraine and ongoing conflict 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. Specifically, the Company’s 2023 and 2024 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 December 31, 2024, 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.”

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a two (2) drilling rig program for 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 and Wells Fargo Securities, LLC have been retained as a financial advisors 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.

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Financial and Operating Performance

The Company’s financial and operating performance for the year ended December 31, 2024 included the following highlights:

Partially offset by:

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Derivative Financial Instruments

Derivative financial instrument exposure. As of December 31, 2024, 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, 2024 was a net asset of $2.2 million which is included in current assets and current liabilities on the Company’s consolidated balance sheet as of December 31, 2024. During the year ended December 31, 2024, the Company recognized a net derivative loss of $46.5 million, including a $32.2 million mark-to-market loss and $14.3 million in net monthly settlement payments.

Natural gas derivative instruments. In February 2025, the Company entered into the following natural gas derivative instruments, specifically HH fixed price swaps at $4.43 per MMBtu for 30,000 MMBtu per day for March 2025 through February 2026.

Operations and Drilling Highlights

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

The Company's liquids production was 88% of total production on a Boe basis for the year ended December 31, 2024.

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Costs incurred are as follows (in thousands):

Development/service and exploration/extension drilling activity is as follows:

Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on March 6, 2024 for a discussion of the Company’s 2023 results of operations compared with the Company’s 2022 results of operations.

Sources of Revenues

The Company’s revenues, which are entirely originated in the continental United States, are derived from the sale of crude oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. For the years ended December 31, 2024, 2023 and 2022, revenues from our assets were derived approximately 99%, 98% and 95%, respectively, from crude oil sales and 1%, 2% and 5%, respectively, from NGL and natural gas sales.

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2024, sales to the Company’s largest purchaser accounted for approximately 76% of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

The Company’s revenues are presented net of certain gathering, transportation and processing expenses incurred to deliver production of its assets’ crude oil, NGL and natural gas to the market. Cost levels of these expenses can vary based on the volume of crude oil, NGL and natural gas produced as well as the cost of commodity processing. Crude oil, NGL and natural gas prices are inherently volatile and are influenced by many factors outside the Company’s control. To reduce the impact of fluctuations in crude oil, NGL and natural gas prices on revenues, the Company may periodically enter into derivative contracts with respect to a portion of its estimated crude oil, NGL and natural gas production through various transactions that fix or set a floor price for future prices received.

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Principal Components of Cost Structure

Costs associated with producing crude oil, NGL and natural gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells owned. The sections below summarize the primary operating costs typically incurred:

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Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

Crude Oil, NGL and natural gas revenues.

The Company’s revenues are derived from the sales of crude oil, NGL and natural gas production. Increases or decreases in the Company’s revenues, profitability and future production are highly dependent on commodity prices. Prices are market driven and future prices will fluctuate due to supply and demand factors, availability of transportation, seasonality, geopolitical developments and economic factors, among other items.

Crude oil, NGL and natural gas revenues are as follows (in thousands):

Average daily sales volumes are as follows:

The increase in average daily Boe sales volumes for the year ended December 31, 2024, compared with 2023 was due to 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.

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 prices, excluding the effects of derivatives, are as follows:

The slight decrease in prices for crude oil, slight increase in prices for NGL and decrease in prices for natural gas for the year ended December 31, 2024, compared with 2023 was due to an overall lower commodity price environment.

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 year ended December 31, 2024 compared to the same period in 2023 is the result of a 12% decrease in average realized price per Boe partially offset by a 10% increase in average daily sales volumes primarily as a result of the Company’s successful drilling program.

Crude oil and natural gas production costs.

Crude oil and natural gas production costs are as follows (in thousands):

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Crude oil and natural gas production costs per Boe are as follows:

Lease operating expense per Boe for 2024 decreased compared with 2023. This is primarily related to lower chemical and treating costs, lower costs of handling produced water and lower workover costs, partially offset by increased pumper, roustabout and supervision costs, communication expenses, rental equipment and contract services.

Production and ad valorem taxes.

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

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 per Boe are as follows:

Production taxes per Boe for the year ended December 31, 2024, compared with 2023, decreased primarily due to the 12% overall decrease in realized sales prices. The increase in ad valorem taxes per Boe for the year ended December 31, 2024, compared with 2023, was primarily due to the increase in commodity prices in 2023 and a significant number of wells that came on production during 2023 that had no ad valorem tax in 2023. 2024 was the first year these wells were assessed ad valorem taxes. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.

Exploration and abandonments expense.

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

The decrease in exploration and abandonment expenses is primarily the result of $3.3 million less 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. 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.

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Depletion, depreciation and amortization expense.

DD&A expense is as follows (in thousands):

DD&A expense per Boe is as follows:

The increase in DD&A expense is primarily due to the increased production associated with our successful horizontal drilling program in addition to an increase in the DD&A rate primarily attributed to increased infrastructure and associated costs as we test new areas.  Based on year-end 2024 proved reserves, we anticipate our DD&A rate going into 2025 to be in the $23.00 per Boe range, similar to the fourth quarter of 2024.

General and administrative expense.

General and administrative expense and stock-based compensation expense are as follows (in thousands):

General and administrative expense per Boe is as follows:

The increase in general and administrative expense for the year ended December 31, 2024 is primarily as a result of salary increases and annual bonuses in addition to an increase in internal and external audit costs and legal expenses related to the growth of the Company.

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

Interest expense.

Interest expense is as follows (in thousands):

The increase in interest expense can be primarily attributed to higher interest rates in 2024 compared to 2023, but more importantly, to increased borrowings under the Term Loan Credit Agreement beginning in September 2023, partially offset by lower amortization of discounts and debt issuance costs with the longer term on the new debt issuances in 2023.

Derivative loss, net.

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

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The Company primarily utilizes commodity swap contracts, collars, enhanced collars and deferred premium puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (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 natural gas contracts or interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market gains and losses and cash settlements relate to crude oil and natural gas derivative swap, enhanced collars and deferred premium put contracts.

Income tax expense.

The change in income tax expense during the year ended December 31, 2024, compared with 2023, was due to decreased net income during the year ended December 31, 2024 compared with 2023. The effective income tax rate differs from the statutory rate primarily due to a revision on the deferred tax asset related to certain 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 and Capital Resources

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 contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortization 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.

Debt Refinancing. 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 matures on September 30, 2026. 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 contains 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. 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.

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The Term Loan Credit Agreement contains 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.

Simultaneously with the closing of the Term Loan Credit Agreement, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.

The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof.

On November 1, 2023, but included in part of the refinancing of the Company’s overall long-term debt, the Company entered into a Senior Credit Facility Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $100.0 million and effective March 29, 2024 pursuant to the First Facility Amendment, current commitments of $100.0 million and customary debt issuance costs which totaled approximately $1.1 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility 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 without premium or penalty. The Senior Credit Facility 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.

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 - $35 million on one-time infrastructure expenditures. The 2025 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical general and administrative expenses and corporate facilities. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations and borrowings under the Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the year ended December 31, 2024 were $604.3 million, 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, such as policies of the Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, and OPEC and other cooperating countries, 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, 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. As of December 31, 2024, the Company had $1.1 billion in outstanding borrowings under the Term Loan Credit Agreement and approximately $93.1 million available to borrow under the Senior Credit Facility Agreement. The Company also had unrestricted cash on hand of $86.6 million as of December 31, 2024.

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

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Operating activities. The decrease in net cash flow provided by operating activities for the year ended December 31, 2024, compared with 2023, was primarily due to a decrease in cash flow from the statement of operations related mostly to decreased revenues associated with lower commodity prices partially offset by increased production volumes as a result of our successful horizontal drilling program, increased interest expense due to a higher debt balance and increased interest rates, partially offset by lower operating expenses.

Investing activities. The decrease in net cash used in investing activities for the year ended December 31, 2024, compared with 2023, was primarily due to a decrease in additions to crude oil and natural gas properties including drilling and completion operations and a decrease in the change in working capital associated with oil and gas property additions.

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

Interest Rate Risk.  We are exposed to market risk due to the floating interest rate associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of December 31, 2024, we had a $1.1 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 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 that 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 conflict between Russia and Ukraine. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 2024 sales volumes and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the year ended December 31, 2024 would have increased (decreased) the Company’s crude oil and NGL revenues by approximately $14.5 million and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2024 would have increased (decreased) the Company’s natural gas revenues by approximately $1.3 million.

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 December 31, 2024, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have changed our net derivative positions for these products by approximately $1.4 million.

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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 8. Financial Statements and Supplementary Data” of this Annual 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, lenders under those agreements would be entitled to exercise all of 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):

Critical Accounting Estimates

The Company prepares its consolidated financial statements for inclusion in this Annual Report in accordance with GAAP. See Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information. The following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP.

Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for crude oil and natural gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for crude oil and natural gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of DD&A expense.

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Proved reserve estimates. Estimates of the Company’s proved reserves included in this Annual Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

The Company’s proved reserve information included in this Annual Report as of December 31, 2024, 2023 and 2022 was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions, positively or negatively, to the estimate of proved reserves. For the year ended December 31, 2024, net upward revisions of our proved reserves totaled approximately 18,017 MBoe and for the years ended December 31, 2023 and 2022, net downward revisions of our proved reserves totaled approximately 16,093 MBoe and 9,211 MBoe, respectively. We cannot predict the amounts or timing of future reserve revisions or removals.

It should not be assumed that the standardized measure included in this Annual Report as of December 31, 2024 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2024 standardized measure on a twelve-month average of commodity prices on the first day of each month in 2024 and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Items 1 and 2. Business and Properties” and Unaudited Supplementary Data included in “Item 8. Financial Statements and Supplementary Data” for additional information.

The Company’s estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which the Company records DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company’s assessment of its proved properties for impairment.

Impairment of proved crude oil and natural gas properties. The Company performs assessments of its long-lived assets to be held and used, including proved crude oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If there is an indication the carrying value of the assets may not be recovered, an impairment loss is recognized if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Proved crude oil and natural gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

Impairment of unproved crude oil and natural gas properties. At December 31, 2024, the Company carried unproved property costs of $70.9 million. Management assesses unproved crude oil and natural gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, management's price outlooks and planned future sales or expiration of all or a portion of such projects.

Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

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Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and economics associated with making a determination of its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predict the hydrocarbon recoverability based on well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found sufficient quantities of proved reserves to sanction the project or is determined to be noncommercial and is impaired. See Note 6 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land at the end of crude oil and natural gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the crude oil and natural gas property or other property and equipment balance. See Note 8 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets will be realized prior to their expiration. HighPeak Energy monitors Company-specific, crude oil and natural gas industry and worldwide economic factors and based on that information, along with other data, reassesses the likelihood that the Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period.

Uncertain tax positions. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefits is sustained upon examination by the taxing authorities, the tax benefit will be recorded as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recorded. As of December 2024, the Company did not have any unrecognized tax benefits. See Note 13 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments of the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note 10 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, and (ii) the closing stock price on the date of grant for the fair value of unrestricted and restricted stock awards. See Note 9 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities the Company measures and records at fair value on a recurring basis include commodity derivative contracts and interest rate contracts. Other assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. The assets and liabilities the Company measures and records at fair value on a nonrecurring basis include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities may require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Recent Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Off-Balance Sheet Arrangements

Commitments and Contingencies are discussed in Note 10 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the other sections of this Annual Report, including but not limited to “Items 1 and 2. Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.” Historical financial statements and related notes included elsewhere in this Annual Report. This discussion contains “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. 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 and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report. Please read Cautionary Statement Concerning Forward-Looking Statements. Also, please read the risk factors and other cautionary statements described under “Part I, Item 1A. Risk Factors.” We assume no obligation to update any of these forward-looking statements, except as required by applicable law. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on March 6, 2023 for a discussion of the Company’s 2022 results of operations compared with the Company’s 2021 results of operations.

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 December 31, 2023, the assets consisted of two highly contiguous leasehold positions of approximately 143,187 gross (131,636 net) acres, approximately 64% 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 year ended December 31, 2023, approximately 93% and 7% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2023, HighPeak Energy was developing its properties using three (3) drilling rigs and one (1) frac crew and expects to average two (2) drilling rigs and one (1) frac crew during 2024 under our current development plan.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2023 and into 2024, 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 in 2022 before cooling off slightly in 2023. However, 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 war in Ukraine, the conflict between Israel and Hamas, elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy’s ability to execute on its capital plan. Despite continuing impacts of these and other factors and future uncertainty, we expect to maintain 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.  Additionally, the impact of inflation as well as elevated interest rates continue to have a negative impact on our cash flows and results of operations.

Recent Events

Share Repurchase Program. In February 2024, the Board approved a repurchase program of up to $75 million of the Company’s common stock.  The approval grants HighPeak’s management the authority to repurchase shares opportunistically in the open market from time to time, through block trades, in privately negotiated transactions or by such other means which comply with applicable state and federal laws.  This is the Company’s first authorization for a stock repurchase program since its founding.

The Company intends to fund the repurchases from available working capital, cash provided from operations and borrowings under its Senior Credit Facility Agreement.  The timing, number and value of shares repurchased under the program will be at the discretion of management and the Board of Directors and will depend on a number of factors, including general market and economic conditions, business conditions, the trading price of the Company’s common stock, the nature of other investment opportunities available to the Company and compliance with the Company’s debt and other agreements.  The stock repurchase program does not obligate HighPeak to acquire any particular dollar amount or number of shares of its common stock and the stock repurchase program may be suspended from time to time, modified, extended or discontinued by the Company’s Board of Directors.  The stock repurchase program authority will expire December 31, 2024.

Debt Refinancing. 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 matures on September 30, 2026. 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.

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The Term Loan Credit Agreement also contains 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. 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 contains 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.

Simultaneously with the closing of the Term Loan Credit Agreement, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.

The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof.

On November 1, 2023, but included in part of the refinancing of the Company’s overall long-term debt, the Company entered into a Senior Credit Facility Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $100.0 million with current commitments of $75.0 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility 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 without premium or penalty. The Senior Credit Facility 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.

Underwritten equity offering.  In July 2023, we completed an underwritten equity offering of 14,835,000 shares of common stock at a price of $10.50, netting proceeds to the Company of approximately $151.2 million that was used for working capital and to otherwise enhance near-term liquidity. Certain of our existing stockholders, including the John Paul DeJoria Family Trust, a holder of approximately 12% of our common stock, and Jack Hightower, our Chief Executive Officer and Chairman of our Board of Directors, and entities and individuals associated with them, purchased an aggregate 10,029,070 shares in the offering. The underwriters in such offering received a reduced underwriting discount on such shares purchased by these persons or entities compared with the other shares sold to the public in the offering.

Dividends and dividend equivalents. In January, April, July and October 2023, the Board declared a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.8 million, $2.8 million, $3.2 million and $3.2 million, respectively, in dividends being paid on February 24, 2023, May 25, 2023, August 25, 2023 and November 22, 2023, respectively. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $282,000 in February 2023, $286,000 in May 2023, $334,000 in August 2023 and $348,000 in November 2023 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 $53,000 in February 2023, $53,000 in May 2023, $54,000 in August 2023 and $54,000 in November 2023 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Acquisitions. During the year ended December 31, 2023, the Company incurred a total of $15.1 million in acquisition costs primarily to acquire additional bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas.

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Crude Oil and Natural Gas Industry Considerations. Since mid-2020, crude oil prices have improved, with demand steadily increasing.  In addition, 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. In 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, the war between Russia and Ukraine and ongoing conflict 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. Specifically, the Company’s 2023 and 2024 capital program has been and continues to be impacted by higher inflation in steel, diesel, chemical prices 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, 2020 through December 31, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2023 and into 2024, 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 in Russia and Ukraine and in 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.”

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its recent shift to an anticipated two (2) drilling rig program for 2024.  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 and Wells Fargo Securities, LLC have been retained as a financial advisors 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.

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Financial and Operating Performance

The Company’s financial and operating performance for the year ended December 31, 2023 included the following highlights:

Partially offset by:

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Derivative Financial Instruments

Derivative financial instrument exposure. As of December 31, 2023, 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, 2023 was a net asset of $34.4 million which is included in current assets, noncurrent assets, current liabilities and noncurrent liabilities on the Company’s consolidated balance sheet as of December 31, 2023. During the year ended December 31, 2023, the Company recognized a net derivative gain of $27.6 million, including a $51.8 million mark-to-market gain partially offset by $24.2 million in net monthly settlement payments.

Subsequent to yearend, the Company entered into fixed price basis swaps for the spread between the Cushing, Oklahoma crude oil price and the Midland WTI crude oil price. The weighted average differential represents the amount of premium to the Cushing, Oklahoma crude oil price for the notional volumes covered by the basis swap contracts as shown below.

Operations and Drilling Highlights

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

The Company's liquids production was 93% of total production on a Boe basis for the year ended December 31, 2023.

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Costs incurred are as follows (in thousands):

Development/service and exploration/extension drilling activity is as follows:

Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on March 6, 2023 for a discussion of the Company’s 2022 results of operations compared with the Company’s 2021 results of operations.

Sources of Revenues

The Company’s revenues, which are entirely originated in the continental United States, are derived from the sale of crude oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. For the years ended December 31, 2023, 2022 and 2021, revenues from our assets were derived approximately 98%, 95% and 96%, respectively, from crude oil sales and 2%, 5% and 4%, respectively, from NGL and natural gas sales.

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2023, sales to the Company’s largest purchaser accounted for approximately 82% of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

The Company’s revenues are presented net of certain gathering, transportation and processing expenses incurred to deliver production of its assets’ crude oil, NGL and natural gas to the market. Cost levels of these expenses can vary based on the volume of crude oil, NGL and natural gas produced as well as the cost of commodity processing. Crude oil, NGL and natural gas prices are inherently volatile and are influenced by many factors outside the Company’s control. To reduce the impact of fluctuations in crude oil, NGL and natural gas prices on revenues, the Company may periodically enter into derivative contracts with respect to a portion of its estimated crude oil, NGL and natural gas production through various transactions that fix or set a floor price for future prices received.

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Principal Components of Cost Structure

Costs associated with producing crude oil, NGL and natural gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells owned. The sections below summarize the primary operating costs typically incurred:

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Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

Crude Oil, NGL and natural gas revenues.

The Company’s revenues are derived from the sales of crude oil, NGL and natural gas production. Increases or decreases in the Company’s revenues, profitability and future production are highly dependent on commodity prices. Prices are market driven and future prices will fluctuate due to supply and demand factors, availability of transportation, seasonality, geopolitical developments and economic factors, among other items.

Crude oil, NGL and natural gas revenues are as follows (in thousands):

Average daily sales volumes are as follows:

The increase in average daily Boe sales volumes for the year ended December 31, 2023, compared with 2022 was due to the Company’s successful horizontal drilling program. This increase could have been more significant had we not had a portion of our production curtailed during the year primarily due to a combination of extended maintenance downtime and start-up delays at gas processing plants owned by one of our primary gas midstream providers which resulted in periodic takeaway and processing constraints. This amounted to approximately 2,000 Boe in daily production that we were not able to sell for the year ended December 31, 2023.

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 prices, excluding the effects of derivatives, are as follows:

The decrease in prices for crude oil, NGL and natural gas for the year ended December 31, 2023, compared with 2022 was due to a lower commodity price environment.

Crude oil and natural gas production costs.

Crude oil and natural gas production costs are as follows (in thousands):

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Crude oil and natural gas production costs per Boe are as follows:

Lease operating expense per Boe for 2023 increased slightly compared with 2022. This is largely due to the aforementioned curtailed production during 2023. The increase in workover costs year over year can be attributed to wells getting older and beginning to need more repair and maintenance from time to time.

Production and ad valorem taxes.

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

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 per Boe are as follows: