What changed in this filing

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Item 5. Market for Registrant’s Common Equity

2025-03-10 compared with 2024-03-06 · 112 added, 88 removed, 409 unchanged (33% of the section changed)

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HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq under the symbols “HPK” and “HPKEW,” respectively.

As of February 29, 2024, there were 41 holders of record of HighPeak Energy common stock and 5 holders of record of HighPeak Energy’s warrants.

As of March 6, 2025, there were 35 holders of record of HighPeak Energy common stock and 5 holders of record of HighPeak Energy’s warrants.

Dividend Policy

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In addition, the Term Loan Credit Agreement and the Senior Credit Facility Agreement place certain restrictions on our ability to pay cash dividends.

Issuer Purchases of Equity Securities

Our common stock repurchase activity for the three months ended December 31, 2024 was as follows:

Purchased (1)

Average Price

of Shares that

May Yet to Be

($ in thousands, except per share amounts and shares)

October 1, 2024 - October 31, 2024

November 1, 2024 - November 30, 2024

December 1, 2024 - December 31, 2024

(1) Such shares are cancelled and retired.

(2) The average price paid per share includes any commissions paid to repurchase stock.

(3) In February 2024, our Board approved a stock repurchase program for up to $75.0 million, excluding excise taxes and other expenses.

The stock repurchase program expired on December 31, 2024.

However, on March 6, 2025, our Board extended the program in its entirety to December 31, 2025.

The program may be suspended, modified, or discontinued by the Board at any time.

(4) The IRA of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022.

All dollar amounts presented exclude such excise taxes, as applicable.

Stock Performance Graph

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The stock price performance included in this graph is not necessarily indicative of future stock price performance.

MANAGEMENT ’ S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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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, 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.

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.

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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.

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.

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The stock repurchase program authority will expire December 31, 2025.

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.

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.

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, 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.

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.

Crude Oil and Natural Gas Industry Considerations.

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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.

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.

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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.

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 recent shift to an anticipated two (2) drilling rig program for 2024.

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.

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a $76.3 million increase in DD&A expense due to an 10% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program, in addition to a 7% increase in the DD&A rate from $25.51 to $27.39 per Boe primarily as a result of significant inflationary pressures on capital costs;

a $27.3 million increase in loss on extinguishment of debt as a result of the Company refinancing its debt which resulted in the recognition of a loss thereon, which included $22.8 million of unamortized debt issuance costs and discounts and a make whole premium on the 10.625% Senior Notes of $4.5 million;

a $97.3 million increase in interest expense due to the increase in the Company’s overall indebtedness and increased amortization of debt issuance costs and discounts;

a $75.8 million increase in lease operating expenses related primarily to the increased well count and production from the Company’s successful horizontal drilling program, increased power and chemical costs, repair and maintenance costs and other inflationary pressures;

a $20.0 million increase in production and ad valorem taxes, primarily attributable to the 86% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program partially offset by 21% lower production taxes on a dollar per Boe basis due to lower overall realized prices of 21%, excluding the effects of derivatives;

an $8.3 million increase in the Company’s other expenses primarily attributable to a contract settlement and repairs made in response to a fire at one of our production facilities;

a $74.1 million increase in the Company’s net derivative instruments loss from a $27.6 million gain to a $46.5 million loss year over year as a result of its crude oil commodity contracts entered into and the change in crude oil prices thereafter;

a $41.9 million decrease in crude oil, NGL and natural gas revenues due to a 12% decrease in average realized commodity prices per Boe, partially offset by a 10% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program, excluding the effects of derivatives;

a $20.8 million increase in interest expense due to the increase in the Company’s average overall indebtedness and the increase in overall interest rates, partially offset by decreased amortization of debt issuance costs and discounts;

a $3.8 million increase in the Company’s general and administrative expenses primarily attributable to increased employee count, salary increases and annual bonuses in addition to increased internal and external audit costs and legal expenses as a result of the growth of the Company;

a $4.1 million increase in exploration and abandonments expense primarily due to an increase in leasehold abandonments and plugging and abandonment expenses related to legacy vertical wells;

a $1.2 million increase in production and ad valorem taxes primarily attributable to an increase in ad valorem taxes, partially offset by lower production taxes as a result of lower revenues recognized by the Company;

Partially offset by:

a $355.6 million increase in crude oil, NGL and natural gas revenues due to an 86% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program, partially offset by a 21% decrease in average realized commodity prices per Boe, excluding the effects of derivatives;

a $87.6 million increase in the Company’s net derivative instruments gain from a $60.0 million loss to a $27.6 million gain year over year as a result of its crude oil commodity contracts entered into and the decrease in crude oil prices thereafter;

a $30.1 million decrease in the Company’s income tax expense primarily due to the net income realized during 2024 being less than the net income realized during 2023;

a $7.4 million decrease in the Company’s stock-based compensation expense as a result of fewer stock options being issued relative to the prior period;

a $2.6 million increase in the Company’s interest income due to the increased cash on hand (interest-bearing) subsequent to the closing of the Term Loan Credit Agreement.

a $27.3 million decrease in loss on extinguishment of debt as a result of the Company refinancing its debt in 2023 which resulted in the recognition of a loss thereon, which included $22.8 million of unamortized debt issuance costs and discounts and a make whole premium on the 10.625% Senior Notes of $4.5 million;

a $13.3 million decrease in the Company’s stock-based compensation expense as a result of fewer restricted stock and stock options being issued relative to the prior period;

a $13.1 million decrease in lease operating expenses related primarily 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;

a $5.8 million increase in the Company’s interest income due to the increased cash on hand (interest-bearing) subsequent to the closing of the Term Loan Credit Agreement in September 2023;

a $4.5 million decrease in the Company’s other expense primarily as a result of the settlement of a water treatment contract in the prior year;

a $3.8 million decrease in the Company’s exploration and abandonment expense due to a decrease in the amount of leasehold abandonments experienced in 2024 compared to 2023.

During the year ended December 31, 2024, average daily sales volumes totaled 49,960 Boepd, an increase of 10% over 2023, due to the Company’s successful horizontal drilling program in the Permian Basin.

Weighted average realized crude oil prices per Bbl decreased during the year ended December 31, 2024 to $76.42, excluding the effects of derivatives, compared with $78.26 for 2023.

Weighted average realized NGL prices per Bbl decreased during the year ended December 31, 2023 to $21.51, compared with $35.67 for 2022.

Weighted average realized NGL prices per Bbl increased during the year ended December 31, 2024 to $22.06, compared with $21.51 for 2023.

Weighted average realized natural gas prices per Mcf decreased to $0.49 during the year ended December 31, 2024, compared with $1.56 during 2023.

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As of December 31, 2024, the Company was a party to the following open crude oil derivative financial instruments.

Enhanced Collars &

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.

Weighted Average

Differential per Bbl

Argus WTI Midland

Collars, Enhanced Collars

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.

Settlement Month

Operations and Drilling Highlights

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For example, power costs are incurred in connection with various production-related activities, such as pumping to recover crude oil and natural gas and separation and treatment of water produced in connection with crude oil and natural gas production.

The Company monitors the operation of its assets to ensure that it is incurring LOE at an acceptable level.

The Company monitors the operation of its assets to determine whether it is incurring LOE at an acceptable level.

For example, it monitors LOE per Boe to determine if any wells or properties should be shut-in, recompleted or sold.

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Natural Gas (Mcf)

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 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.

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Total per Boe

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.

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):

Total operating revenues

Average daily sales volumes (Boe)

Realized price per Boe

Revenue change from prior period due to prices

Revenue change from prior period due to volumes

Total change from prior period revenues

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.

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Workover costs

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.

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.

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Year Ended December 31,

Abandoned leasehold costs

Geologic and geophysical personnel costs

Plugging and abandonment expense

Abandoned leasehold costs

Geologic and geophysical data costs

Exploration and abandonments expense

The increase in exploration and abandonment expenses is primarily the result of $3.4 million 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.

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 $745,000 on plugging various old vertical wells across our acreage position in accordance with applicable regulations.

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.

Depletion, depreciation and amortization expense.

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DD&A expense per Boe

The increase in DD&A expense is primarily due to the increased production associated with our successful horizontal drilling program.

The increase in DD&A expense per Boe can be primarily attributed to inflationary pressures and lower well performance as we test new areas and new geologic horizons.

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.

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General and administrative expense per Boe

The increase in general and administrative expense for the year ended December 31, 2023 is primarily as a result of increased employee count, 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 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.

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Interest expense on Term Loan Credit Agreement

Interest expense on Senior Credit Facility Agreement

Interest expense on Prior Credit Agreement

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Interest expense on 10.000% Senior Notes

Interest expense on Senior Credit Facility Agreement

Amortization of discounts

Amortization of debt issuance costs

The increase in interest expense can be primarily attributed to higher interest rates in 2023 compared to 2022, but more importantly, to increased borrowings under the Term Loan Credit Agreement beginning in September 2023, increased borrowings under the Prior Credit Agreement throughout 2023 until September 2023 when it was paid in full and the issuance of $250.0 million of the Company’s 10.625% Senior Notes in late-2022 that were also paid off in September 2023.

In addition, the Company also experienced an increase in both amortization of discounts and debt issuance costs with the increase in debt issuances from year to year.

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.

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Gain (loss) on derivative instruments, net

The Company primarily utilizes commodity swap contracts, 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 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.

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Liquidity and Capital Resources

The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, including remaining cash proceeds from our recent $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 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.

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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.

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%.

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.

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.

The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty.

2025 capital budget .

The Company’s capital budget for 2024 is expected to be in the range of approximately $450 to $525 million for drilling, completion, facilities and equipping crude oil wells plus $50 to $60 million for field infrastructure buildout and other costs.

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, 2023 were $1.0 billion, excluding acquisitions.

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 Biden 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.

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.

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Operating activities.

The increase in net cash flow provided by operating activities for the year ended December 31, 2023, compared with 2022, was primarily due to an increase in cash flow from the statement of operations related mostly to increased revenues associated with increased production volumes as a result of our successful horizontal drilling program, coupled with a positive working capital change of $52.5 million.

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 slight decrease in net cash used in investing activities for the year ended December 31, 2023, compared with 2022, was primarily due to a decrease in additions to crude oil and natural gas properties including drilling and completion operations and acquisitions in total.

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:

The Company (i) repaid $120.0 million of the Term Loan Credit Agreement, (ii) repurchased $35.2 million of its common stock and (iii) paid dividends to its common stockholders of $20.1 million and dividend equivalents to certain holders of vested stock options of $2.1 million.

The Company (i) borrowed $1.4 billion and repaid $1.0 billion for a net increase in long-term debt related to the now refinanced debt in the form of the Term Loan Credit Agreement of $425.0 million, (ii) received $155.8 million from the issuance of 14,835,000 shares of common stock in a public offering, (iii) received $4.2 million in proceeds from the exercises of warrants and stock options of the Company, (iv) paid dividends to its common stockholders of $11.9 million and dividend equivalents to certain holders of vested stock options of $1.3 million, (v) spent $28.4 million on debt issuance costs primarily related to the issuance of the Term Loan Credit Agreement and to a lesser extent the new Senior Credit Facility Agreement and amendments to increase its borrowing capacity under the Prior Credit Agreement, (vi) spent $5.4 million in stock offering costs related to the public offering and (vii) spent $4.5 million in make whole payments to retire the 10.625% Senior Notes early.

The Company (i) borrowed $925.0 million and repaid $755.0 million for a net increase in long-term debt related to the Prior Credit Agreement of $170.0 million, (ii) issued an aggregate principal amount of $225.0 million ($210.2 million net of discounts) of its 10.000% Senior Notes and an aggregate principal amount of $250.0 million ($230.0 million net of discounts) of its 10.625% Senior Notes, (iii) received $85.0 million from the issuance of 3,933,376 shares of common stock in a private placement, (iv) received $7.9 million in proceeds from the exercises of warrants and stock options of the Company, (v) paid dividends to its common stockholders of $10.4 million and dividend equivalents to certain holders of vested stock options of $1.2 million and (vi) spent $17.1 million on debt issuance costs related to amendments to increase its borrowing capacity under the Prior Credit Agreement and the issuance of the 10.000% Senior Notes and 10.625% Senior Notes.

Interest Rate Risk.

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The realized prices we receive for our production also depend on numerous factors that are typically beyond our control.

Based on our 2023 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, 2023 would have increased (decreased) the Company’s crude oil and NGL revenues by approximately $14.3 million and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2023 would have increased (decreased) the Company’s natural gas revenues by approximately $722,000.

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.

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Interest expense

Interest and other income

Interest income

Income tax expense

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Derivative related noncash activity

Loss on extinguishment of debt

Other expense

Loss on extinguishment of debt

Critical Accounting Estimates

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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 years ended December 31, 2023, 2022 and 2021, net downward revisions of our proved reserves totaled approximately 16,093 MBoe, 9,211 MBoe and 1,658 MBoe, respectively.

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity