HighPeak Energy, Inc.: Form 10-Q for the period ended Sep 30, 2024

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

Overview

HighPeak Energy, Inc., a Delaware corporation, which 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 September 30, 2024, the assets consisted of two generally contiguous leasehold positions of approximately 147,795 gross (137,207 net) acres, approximately 65% of which were held by production, with an average working interest of approximately 93%. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern portion of Howard County. We operate approximately 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 nine months ended September 30, 2024, approximately 89% and 11% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of September 30, 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 one (1) frac crew for the remainder of 2024.

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 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. During the nine months ended September 30, 2024, the Company repurchased 1.8 million shares of its common stock at an average cost of $14.73 per share for a total of approximately $27.2 million, excluding any potential excise taxes. The stock repurchase program authority will expire December 31, 2024.

Dividends and dividend equivalents. In August 2024, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.0 million in dividends being paid in September 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $534,000 in September 2024 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $86,000 in September 2024 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Acquisitions. During the nine months ended September 30, 2024, the Company incurred a total of $10.4 million in acquisition costs related to lease extensions and to acquire crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas.

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 September 30, 2024, the Company has delivered approximately 28,255 Bopd under the contract. The remaining monetary commitment as of September 30, 2024, if the Company never delivers any additional volumes under the agreement, is approximately $133.9 million.

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. In June 2024, OPEC announced it would extend cuts of 3.66 million Bopd through the end of 2025, while gradually phasing out 2.2 million Bopd of voluntary cuts beginning in October 2024. However, as a result of current global supply and demand imbalances, crude oil prices remain strong, although down from the prior year. In addition, the war between Russia and Ukraine and ongoing conflicts between Israel and Hamas, Israel and Iran and other tensions in the Middle East have resulted in global supply chain disruptions, which has led to significant cost inflation.

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 and the Israel-Iran conflicts, (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 September 30, 2024, 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 market for crude oil strengthened in 2021 from historic lows in 2020 and continued to remain strong in 2023 and continuing in 2024, although the market has decreased from 2022 levels overall, as a result of increased supply outpacing increased demand. 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, Israel and Hamas and Israel and Iran, elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. For additional information on the risks, see “Part I, Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on March 6, 2024 (the “Annual Report”).

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its anticipated two (2) drilling rig program for the remainder of 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 or key transaction terms. The Company has not set a timetable for the conclusion of this review, nor has it made any decisions related to any further actions or potential strategic alternatives at this time. There can be no assurance that the review will progress beyond this exploratory phase or result in any transaction or other strategic change or outcome. The Company does not intend to comment further regarding the strategic alternatives process unless and until our Board has approved a specific course of action or we have otherwise determined that further disclosure is appropriate or required by law.

Financial and Operating Performance

The Company's financial and operating performance for the three months ended September 30, 2024 included the highlights described below and comparative discussion of related drivers for the three months ended September 30, 2023:

• Net income was $49.9 million ($0.35 per diluted share) for the three months ended September 30, 2024 compared with $38.8 million for three months ended September 30, 2023. The primary components of the $11.1 million increase in net income include:
• a $62.0 million decrease in the Company’s derivative instruments loss from a $29.7 million loss in the prior year period compared with a $42.6 million gain in the current year quarter as a result of its crude oil commodity contracts entered into and the change in crude oil prices thereafter;
• a $27.3 million decrease in loss on extinguishment of debt due to the Company’s refinancing of its long-term debt in September 2023 which caused a loss to be recognized at the time the prior debt was repaid and terminated;
• a $10.3 million decrease in the Company’s stock-based compensation expense primarily due to stock options that were granted during the three months ended September 30, 2023 that were 100% vested upon issuance and thus the expense was recognized at the time of grant compared with none being granted during the three months ended September 30, 2024;
• a $4.4 million decrease in the Company’s crude oil and natural gas production costs primarily as a result of lower chemical and other treating costs throughout Flat Top specifically; and
• a $3.4 million decrease in production and ad valorem taxes, primarily attributable to the 19% decrease in average realized commodity prices per Boe, excluding the effects of derivatives, plus a 3% decrease in daily sales volumes resulting primarily from a major rain storm at the beginning of September that caused a significant amount of flooding and shut in a significant amount of production for a short time, effecting current quarter sales volumes by approximately 750 Boe per day in addition to a production decline resulting from a reduced two-rig development schedule compared with the four to six drilling rigs we were running in early 2023, partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking, partially offset by an increase in ad valorem taxes in the State of Texas due to the continued growth of the Company’s property base;
• a $2.0 million decrease in the Company’s general and administrative expenses primarily attributable to prior year bonus accrual beginning in the third quarter whereas during the current year the Company has accrued projected bonuses quarterly, partially offset by higher salaries and benefits as well as an increase in professional fees, all primarily as a result of the growth of the Company;
• a $1.4 million decrease in the Company’s exploration and abandonment expense primarily due to less leasehold abandonments; and
• a $1.4 million increase in the Company’s interest income due to the increased cash on hand;

Partially offset by:

• a $74.0 million decrease in crude oil, NGL and natural gas revenues due to a 19% decrease in average realized commodity prices per Boe, excluding the effects of derivatives, plus a 3% decrease in daily sales volumes resulting primarily from a major rain storm at the beginning of September that caused a significant amount of flooding and shut in a significant amount of production for a short time, affecting current quarter sales volumes by approximately 750 Boe per day in addition to a production decline resulting from a reduced two-rig development schedule compared with the four to six drilling rigs we were running in early 2023, partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking;
• a $19.2 million increase in DD&A expense due to a 19% increase in the DD&A rate from $24.21 to $28.91 per Boe as a result of significant inflationary pressures on capital costs, partially offset by a 3% decrease in daily sales volumes resulting primarily from a major rain storm that caused a significant amount of flooding that occurred at the beginning of September and shut in a significant amount of production for a short time, effecting current quarter sales volumes by approximately 750 Boe per day in addition to a production decline resulting from a reduced two-rig development schedule compared with the four to six drilling rigs we were running in early 2023, partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking;
• a $5.6 million increase in interest expense due to the increase in the Company’s overall indebtedness and higher interest rates, partially offset by decreased amortization of debt issuance costs and discounts;
• a $1.3 million increase in the Company’s income tax expense primarily due to an increase in income before income taxes; and
• a $864,000 increase in the Company’s other expense primarily as a result of the repair of a production facility that continued into the third quarter of 2024;
• During the three months ended September 30, 2024, average daily sales volumes totaled 51,346 Boepd, compared with 52,708 Boepd during the same period in 2023, a decrease of 3%, due to a major rain storm that caused a significant amount of flooding that occurred at the beginning of September and shut in a significant amount of production for a short time, effecting current quarter sales volumes by approximately 800 Boe per day in addition to a production decline resulting from a reduced two-rig development schedule compares with the four to six drilling rigs we were running in early 2023, partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking.
• Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended September 30, 2024 to $75.99, compared with $82.87 for the same period in 2023. Weighted average NGL prices per Bbl increased during the three months ended September 30, 2024 to $21.14, compared with $20.08 for the same period in 2023. Weighted average natural gas prices per Mcf decreased to $0.42 during the three months ended September 30, 2024, compared with $1.89 during the same period in 2023.
• Cash provided by operating activities totaled $177.1 million for the three months ended September 30, 2024, compared with $158.1 million for the three months ended September 30, 2023.

Derivative Financial Instruments

Derivative financial instrument exposure. As of September 30, 2024, the Company was a party to the following open derivative financial instruments.

The estimated fair value of the outstanding open derivative financial instruments as of September 30, 2024 was a net asset of $22.9 million which is included in current assets and current liabilities on the Company’s consolidated balance sheet as of September 30, 2024. During the nine months ended September 30, 2024, the Company recognized a net derivative loss of $23.4 million, including a $11.5 million mark-to-market loss and $11.9 million in net monthly settlement payments.

Operations and Drilling Highlights

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

The Company’s liquids production was 89 percent of total production on a Boe basis for the nine months ended September 30, 2024.

Costs incurred are as follows (in thousands):

The following table sets forth the total number of horizontal producing wells drilled and completed during the nine months ended September 30, 2024:

As of September 30, 2024, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew. The continued threat of an extensive recession, the scope, duration and magnitude of the direct and indirect effects of pandemics, the war between Russia and Ukraine, the Israel-Hamas and Israel-Iran conflicts and the production cuts announced by OPEC are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility with its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

During the nine months ended September 30, 2024, the Company successfully completed and placed on production fifty-one (51) gross (41.4 net) horizontal wells, forty-seven (47) gross (37.9 net) in the Flat Top area and four (4) gross (3.5 net) in the Signal Peak area. The Company also placed one salt-water disposal well in service in its Flat Top area during the nine months ended September 30, 2024. As of September 30, 2024, the Company had seventeen (17) gross (16.9 net) horizontal wells that had been drilled and were in various stages of completion in the Flat Top area and two (2) gross (2.0 net) horizontal wells that had been drilled and were in various stages of completion in the Signal Peak area. In addition, as of September 30, 2024, the Company was in the process of drilling five (5) gross (5.0 net) horizontal wells, all in the Flat Top area.

Results of Operations

Three and Nine Months Ended September 30, 2024

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

The decrease in overall sale volumes during the three months ended September 30, 2024 compared with the same period in 2023 is primarily the result of a major storm at the beginning of September that caused a significant amount of flooding and shut in a significant amount of production for a short time, effecting current quarter sales volumes by approximately 750 Boe per day in addition to a production decline resulting from a reduced two-rig development schedule compared with the four to six drilling rigs we were running in early 2023, partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking. The increase in average daily Boe sales volumes for the nine months ended September 30, 2024, compared with the same period in 2023 was primarily due to the Company’s successful horizontal drilling program and increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking, partially offset by the aforementioned storm and decline resulting from the reduced drilling program.

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

Revenue Variance Analysis.

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

As detailed above, the decrease in total operating revenues for the three months ended September 30, 2024 compared to the same period in 2023 is the result of a 19% decrease in average realized price per Boe coupled with a 3% decrease in average daily sales volumes primarily as a result of a major storm at the beginning of September that caused a significant amount of flooding and shut in a significant amount of production for a short time, effecting current quarter sales volumes by approximately 750 Boe per day in addition to a production decline resulting from a reduced two-rig development schedule compared with the four to six drilling rigs we were running in early 2023, partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking. Also as detailed above, the increase in total operating revenues for the nine months ended September 30, 2024 compared to the same period in 2023 is the result of a 13% increase in average daily sales volumes primarily as a result of the Company’s successful horizontal drilling program and increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking, partially offset by the aforementioned storm and decline resulting from the reduced drilling program, partially offset by a 9% decrease in average realized price per Boe.

Crude Oil and natural gas production costs.

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

The decrease in crude oil and natural gas production costs quarter over quarter can be attributed primarily to lower treating and chemical costs and year over year can be attributed primarily to lower treating and chemical costs and lower expense workover costs as well as lower power and fuel costs with the continued reduction in generator power used throughout the field now that we have overhead electric covering the majority of our properties.

Production and ad valorem taxes.

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

In general, production taxes and ad valorem taxes are directly related to commodity sales volumes and price changes; however, Texas ad valorem taxes are based upon an asset valuation assessed by the state as of January 1 of that particular year based on prior year commodity prices, whereas production taxes are based upon current year sales revenues at current commodity prices. Overall, the decrease in production and ad valorem taxes during the three months ended September 30, 2024 compared to the same period in 2023 can be attributed primarily to the 19% decrease in overall commodity prices received in addition to the 3% aforementioned decrease in sales volumes, partially offset by an increase in ad valorem taxes due to the increased property base of the Company. Overall, the increase in production and ad valorem taxes during the nine months ended September 30, 2024 compared to the same period in 2023 can be primarily attributed to the 13% aforementioned increase in sales volumes partially offset by a 9% decrease in overall commodity prices received and an increase in ad valorem taxes due to the increased property base of the Company.

Production and ad valorem taxes per Boe are as follows:

The decrease in production taxes per Boe for the three and nine months ended September 30, 2024, compared with the same periods in 2023 can be attributed primarily to the lower commodity prices received in 2024. The decrease in ad valorem taxes per Boe for the three and nine months ended September 30, 2024, compared with the same periods in 2023, was primarily due to the Company efforts working with the counties to reduce valuations for 2024.

Exploration and abandonments expense.

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

Exploration and abandonment costs decreased during the three and nine months ended September 30, 2024 primarily due to less abandoned leasehold costs, plugging and abandonment expenses and a reimbursement from an industry partner for seismic expenses in 2024.

DD&A expense.

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

The increase in DD&A in 2024 is primarily due to the increased production associated with our successful horizontal drilling program and the increase in rate can be attributed to significant inflationary pressures on capital costs over the past year.

General and administrative expense.

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

The decrease in general and administrative expense during the three months ended September 30, 2024 compared with the same period in 2023 is primarily the result of the prior year period including nine months of accrued employee bonuses whereas in 2024 we began accruing quarterly in the first quarter and thus only three months are included in the current year period. The increase in general and administrative expense and general and administrative expense per Boe for the nine months ended September 30, 2024 is primarily a result of adding new employees and increased salaries and benefits related to the growth of the Company in addition to higher professional services costs related to the growth of the Company.

Interest expense.

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The increase in interest expense can be attributed to a higher overall debt balance in 2024 compared with 2023 and higher interest rates in 2024 primarily on our Term Loan Credit Agreement compared with interest rates in 2023 on our Prior Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes. Partially offsetting this increase was a decrease in amortization of discounts and debt issuance costs as a result of the issuance of our longer term $1.2 billion Term Loan Credit Agreement in mid-September 2023.

Loss on derivative instruments, net.

The Company primarily utilizes commodity swap contracts, costless collars, deferred premium collars and deferred premium put option contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budget and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require, and previously the Prior Credit Agreement and the indentures governing the Company’s 10.000% Senior Notes and 10.625% Senior Notes required, the Company to hedge certain quantities of its projected crude oil production. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market gain (loss) and cash settlements relate to crude oil derivative swap contracts, deferred premium collars and deferred premium put option contracts.

Other expense.

During the three and nine months ended September 30, 2024, the Company incurred $1.2 million and $3.2 million, respectively, primarily related to repairs on a damaged production facility which resulted in a delay in turning several newly completed wells online and $181,000 and $181,000, respectively, related to damages sustained during the major rain storm that caused significant flooding throughout the field resulting in a significant amount of production being off-line for a short period of time. During the three and nine months ended September 30, 2023, the Company paid zero and $6.5 million, respectively, to buyout and terminate a water treatment contract with a former outside board member and incurred other costs of $540,000 and $1.5 million, respectively, primarily related to repairs on production facilities that were damaged in a fire that shut in a significant amount of production for a short time.

Provision for income taxes.

The change in provision for income taxes during the three and nine months ended September 30, 2024, compared with the same periods in 2023, was primarily due to the change in income before income taxes for both periods and the reversal of a deferred tax asset related to a temporary difference from restricted stock being reclassified to a permanent difference. The effective income tax rate differs from the statutory rate primarily due to certain aforementioned stock-based compensation revisions, Texas state income taxes and other permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)" for additional information.

Liquidity and Capital Resources

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

The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) near-term debt maturities, including quarterly mandatory payments under our Term Loan Credit Agreement, (iii) payments of other contractual obligations, (iv) acquisitions of crude oil and natural gas properties and (v) working capital obligations. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity.

2024 capital budget. The Company’s capital budget for 2024 is expected to be in the range of approximately $540 to $580 million for drilling, completion, facilities and equipping crude oil wells and for field infrastructure buildout and other costs. The 2024 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses, general and administrative expenses and corporate facilities. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its consolidated balance sheet, cash generated by operations and borrowing capacity available under its Senior Credit Facility Agreement. The Company’s capital expenditures for the nine months ended September 30, 2024 were $451.8 million, excluding acquisitions.

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

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

Operating activities. The increase in net cash flow provided by operating activities for the nine months ended September 30, 2024, compared with 2023, was primarily related to an increase in discretionary cash flow as a result of an increase in revenues less operating and general administrative expenses of approximately $14.0 million associated with increased production volumes as a result of our successful horizontal drilling program and cost cutting efforts related primarily to power generation and treating and chemical costs plus an increase in other current assets and a decrease in accounts payable and other current liabilities, partially offset by a decrease in accounts receivables.

Investing activities. The decrease in net cash used in investing activities for the nine months ended September 30, 2024, compared with 2023, was primarily due to decreases in additions to crude oil and natural gas properties when the Company had fewer drilling rigs and frac crews running on average compared with the nine months ended September 30, 2023.

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

• Nine months ended September 30, 2024: The Company made mandatory payments on its Term Loan Credit Facility totaling $90.0 million, paid $27.2 million to repurchase 1,849,636 shares of its common stock at an average cost of approximately $14.73 per share, excluding any potential excise taxes, and paid dividends and dividend equivalents of $15.1 million and $1.6 million, respectively.
• Nine months ended September 30, 2023: The Company borrowed $1.17 billion on the Term Loan Credit Agreement, net of a $30.0 million original issue discount, and $255.0 million on the Prior Credit Agreement, received $155.8 million from a public offering of 14,835,000 shares of common stock and $1.7 million and $148,000 in proceeds from the exercise of warrants and stock options, respectively, partially offset by the repayment of the Prior Credit Agreement, 10.625% Senior Notes and 10.000% Senior Notes of $525.0 million, $250.0 million and $225.0 million, respectively, payment of a make whole premium on the 10.625% Senior Notes of $4.5 million, payment of debt issuance costs and stock issuance costs totaling $26.4 million and $5.4 million, respectively, and the payment of dividends and dividend equivalents of $8.7 million and $903,000, respectively.

Interest Rate Risk. We are exposed to market risk due to the floating interest rates associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of September 30, 2024, we had a $1.11 billion outstanding balance on the Term Loan Credit Agreement and zero outstanding on the Senior Credit Facility Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the end of each quarter for a period of three months and the Senior Credit Facility Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period of six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.

Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing armed conflicts between Russia and Ukraine, Israel and Hamas and Israel and Iran. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our sales volumes during the nine months ended September 30, 2024 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2024 would have increased (decreased) the Company’s revenues by approximately $15.1 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2024 would have increased (decreased) the Company’s revenues by approximately $1.2 million on an annualized basis.

We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2024, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $9.1 million.

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

Non-GAAP Financial Measures

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

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

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

New Accounting Pronouncements

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

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

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

There have been no material changes in our critical accounting policies and procedures during the three months ended September 30, 2024. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report.

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

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

During the period from January 1, 2020 through September 30, 2024, 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. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2024 would have increased (decreased) the Company’s revenues by approximately $15.1 million on an annualized basis, excluding the effects of derivatives, and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2024 would have increased (decreased) the Company’s revenues by approximately $1.2 million on an annualized basis, excluding the effects of derivatives.

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

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

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

The average forward prices based on September 30, 2024 market quotes were as follows:

The average forward prices based on October 31, 2024 market quotes were as follows:

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

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

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

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

Interest Rate Risk. As of September 30, 2024, we had $1.11 billion outstanding under the Term Loan Credit Agreement and had $93.1 million of available borrowing capacity under the Senior Credit Facility Agreement. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement and Senior Credit Facility Agreement. The Company also periodically has fixed rate debt but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The impact of a 1% increase in interest rates on our outstanding debt as of September 30, 2024 would have resulted in an annual increase in interest expense of approximately $11.1 million.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2024 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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