HighPeak Energy, Inc.: Form 10-Q for the period ended Sep 30, 2023

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

Overview

HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019. 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, 2023, the assets consisted of two generally contiguous leasehold positions of approximately 126,988 gross (114,324 net) acres (consisting of 64,142 net acres in our Flat Top area to the north and 50,182 net acres in our Signal Peak area to the south) covering various subsurface depths, approximately 65% of which were held by production, with an average working interest of approximately 90%. We operate approximately 98% of the net acreage across the Company’s assets and more than 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the nine months ended September 30, 2023, approximately 93% and 7% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of September 30, 2023, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac fleet and expects to average two to three (2-3) drilling rigs and one to two (1-2) frac crews for the remainder of 2023.

Recent Events

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 $23.0 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.

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 Capitol 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.

Subsequent to quarter end, but included in part of the refinancing of the Companies 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 a borrowing capacity of $100.0 million with elected 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.

Public stock offering. In July 2023, we completed a public stock offering whereby we issued 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.

Dividends and dividend equivalents. In January, April and July 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 and $3.2 million, respectively, in dividends being paid on February 24, 2023, May 25, 2023 and August 25, 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 $283,000 in February 2023, $282,000 in May 2023 and $333,000 in August 2023 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional $7,000 in February 2023, $5,000 in May 2023 and $4,000 in August 2023, respectively, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in February 2023, $53,000 in May 2023 and $54,000 in August 2023 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, 2023, the Company incurred a total of $9.6 million in acquisition costs to acquire additional bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas.

Crude Oil and Natural Gas Industry Considerations. The COVID-19 pandemic resulted in a severe worldwide economic downturn, significantly disrupting the demand for crude oil throughout the world, and created significant volatility, uncertainty and turmoil in the crude oil and natural gas industry. The decrease in demand for crude oil, combined with excess supply of crude oil and related products, resulted in crude oil prices declining significantly beginning in late February 2020. Since mid-2020, crude oil prices have improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants that have continued to inhibit a full global demand recovery. In addition, worldwide crude oil inventories are, from a historical perspective, very low and concerns exist with the ability of OPEC and other crude oil producing nations to meet forecasted crude oil demand growth in 2023, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their lack of capital investments over the past few years in developing incremental crude oil supplies. Furthermore, sanctions and import bans on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. As a result of crude oil and natural gas supply constraints, there have been significant increases in European energy costs, which have resulted in inflationary pressures throughout Europe, increasing prospects of recession in many countries throughout the continent. In April 2023, OPEC announced production cuts of around 1.16 million Bopd. On June 4, 2023, OPEC agreed to extend these previously announced production cuts through the end of 2024. On July 3, 2023, Saudi Arabia announced it was extending voluntary cuts through August 2023. However, as a result of current global supply and demand imbalances, crude oil and natural gas prices remain strong, although down from the prior quarter. In addition, the ongoing pandemic, combined with the conflict between Russia and Ukraine, has resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by recent developments in the Israel-Hamas conflict. Specifically, the Company’s 2023 capital program has been and continues to be impacted by higher inflation in steel, diesel, chemical prices and services, among other items.

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

Outlook

HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend heavily on prevailing commodity prices. The crude oil and natural gas industry is cyclical and commodity prices are highly volatile and subject to a high degree of uncertainty. For example, during the period from January 1, 2018 through September 30, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35.

The markets for the commodities produced by our industry strengthened in 2021 and remained strong in 2022 and continuing in 2023, although decreased from 2022 levels overall, as a result of increased demand outpacing increased supply for each of the commodities we produce. Prices for the commodities produced by our industry improved from historic lows in 2020, with crude oil and natural gas prices reaching their highest average annual price since 2014. However, there are many factors beyond the Company’s control, including commodity markets, unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services or supply constraints remain subject to heightened levels of uncertainty as a result of the conflicts in Russia and Ukraine and in Israel and the Gaza Strip, the COVID-19 pandemic, rising interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. Additionally, 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. The actions of OPEC with respect to crude oil production levels, including agreement on and compliance with production cuts, may result in further volatility in commodity prices and the crude oil and natural gas industry generally. Additionally, the impact of inflation as well as rising interest rates continue to have a negative impact on our cash flows and results of operations. 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, 2022, filed with the SEC on March 6, 2023 (the “Annual Report”).

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 to three (2-3) drilling rig program for the remainder of the year. 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. Wells Fargo Securities, LLC has been retained as a financial advisor with respect to this strategic alternatives process. To date, however, this process has been exploratory in nature and accordingly remains in preliminary stages, with our discussions to date with prospective counterparties generally excluding substantive discussions regarding potential valuation, structure or other key transaction terms. The Company has not set a timetable for the conclusion of this review, nor has it made any decisions related to any further actions or potential strategic alternatives at this time. There can be no assurance that the review will progress beyond this exploratory phase or result in any transaction or other strategic change or outcome. The Company does not intend to comment further regarding the strategic alternatives process unless and until our Board has approved a specific course of action or we have otherwise determined that further disclosure is appropriate or required by law.

Financial and Operating Performance

The Company's financial and operating performance for the three months ended September 30, 2023 included the following highlights:

• Net income was $38.8 million ($0.27 per diluted share) for the three months ended September 30, 2023 compared with $107.9 million for three months ended September 30, 2022. The primary components of the $69.1 million decrease in net income include:
• a $74.8 million increase in DD&A expense due to a 101% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions, in addition to a 37% increase in the DD&A rate from $17.65 to $24.21 per Boe as a result of significant inflationary pressures on capital costs as well as bolt-on acquisitions;
• a $65.5 million decrease in the Company's net derivative instruments gain from a $35.8 million gain to a $29.7 million loss year over year as a result of its crude oil commodity contracts entered into and the increase in crude oil prices thereafter;
• 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 $22.4 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 $20.1 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 $8.3 million increase in production and ad valorem taxes, primarily attributable to the 101% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program partially offset by 17% lower production taxes on a dollar per Boe basis due to lower overall realized prices of 16%, excluding the effects of derivatives;
• a $5.1 million increase in the Company’s general and administrative expenses primarily attributable to accrued yearend bonuses, increased internal and external audit costs and legal expenses as a result of the growth of the Company;
• a $3.4 million increase in the Company's stock-based compensation expense as a result of more stock options being issued relative to the prior period; and
• a $1.4 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;

Partially offset by:

• a $141.5 million increase in crude oil, NGL and natural gas revenues due to a 101% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program, partially offset by a 16% decrease in average realized commodity prices per Boe, excluding the effects of derivatives;
• a $17.5 million decrease in the Company’s income tax expense due to the net income realized during the three months ended September 30, 2023 compared with the net income during the three months ended September 30, 2022; and
• a $729,000 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.
• During the three months ended September 30, 2023, average daily sales volumes totaled 52,708 Boe/d, compared with 26,247 Boe/d during the same period in 2022, an increase of 101%, due to the Company’s successful horizontal drilling program, and to a lesser extent, bolt-on acquisitions.
• Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended September 30, 2023 to $82.87, compared with $94.21 for the same period in 2022. Weighted average NGL prices per Bbl decreased during the three months ended September 30, 2023 to $20.08, compared with $36.59 for the same period in 2022. Weighted average natural gas prices per Mcf decreased to $1.89 during the three months ended September 30, 2023, compared with $7.73 during the same period in 2022.
• Cash provided by operating activities totaled $521.7 million for the three months ended September 30, 2023, compared with $302.8 million for the three months ended September 30, 2022.

Derivative Financial Instruments

Derivative financial instrument exposure. As of September 30, 2023, 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, 2023 was a net liability of $27.2 million which is included in current assets, noncurrent assets, current liabilities and noncurrent liabilities on the Company’s consolidated balance sheet as of September 30, 2023. During the nine months ended September 30, 2023, the Company recognized a net derivative loss of $30.9 million, including $21.0 million in net monthly settlement payments and a $9.9 million mark-to-market loss.

Operations and Drilling Highlights

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

The Company’s liquids production was 93 percent of total production on a Boe basis for the nine months ended September 30, 2023.

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, 2023:

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As of September 30, 2023, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew in addition to having a third rig drilling salt-water disposal wells. With the continued threat of an extensive recession and uncertainty of the debt refinancing, the Company released a frac crew in the first week of July and now expects to average two to three (2-3) drilling rigs and one to two (1-2) frac crews for the remainder of 2023. However, the scope, duration and magnitude of the direct and indirect effects of the COVID-19 pandemic, the war between Russia and Ukraine, the Israel-Hamas conflict and the production cuts announced by OPEC are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility in 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, 2023, the Company successfully completed and placed on production seventy-two (72) gross (64.2 net) horizontal wells in the Flat Top area and twenty-five (25) gross (24.7 net) horizontal wells in the Signal Peak area. The Company had twenty-five (25) gross (18.6 net) wells that had been drilled and were in various stages of completion as of September 30, 2023, seventeen (17) gross (16.0 net) of which are in the Flat Top area, and eight (8) gross (2.7 net) of which are in the Signal Peak area. In addition, as of September 30, 2023, the Company was in the process of drilling two (2) gross (2.0 net) horizontal wells in the Flat Top area and five (5) gross (5.0 net) horizontal wells in the Signal Peak area. In addition to the aforementioned numbers are two (2) gross (2.0 net) salt-water disposal wells that have been finished and placed in service during the nine months ended September 30, 2023 and an additional four (4) gross (4.0 net) salt-water disposal wells that were in progress as of September 30, 2023.

Results of Operations

Three and Nine Months Ended September 30, 2023

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

The increase in average daily Boe sales volumes for the three and nine months ended September 30, 2023, compared with the same periods in 2022 was primarily due to the Company’s successful horizontal drilling program. However, increases in production were partially offset due to unexpected temporary reduced third-party gas takeaway at Flat Top that began in early fourth quarter 2022 and continues today to a lesser extent. The fourth quarter of 2023 is expected to continue to be impacted by this curtailment at Flat Top, and a natural gas plant that gathers and processes a portion of the natural gas at Signal Peak will be down for six to eight weeks for repairs and maintenance.

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:

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Crude Oil and natural gas production costs.

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

The increase in crude oil and natural gas production costs can primarily be attributed to the Company’s successful horizontal drilling program adding a significant number of newly completed producing wells, increased chemical and treating costs, increased repair and maintenance expense with the addition of a significant number of legacy vertical wells in the Hannathon Acquisition in 2022 and expense workover costs. The change in crude oil and natural gas production costs per Boe were minimal during the three and nine months ended September 30, 2023 compared with the same periods in 2022. Our crude oil production in the first half of 2023 was negatively impacted by (i) a weather event that disrupted a considerable amount of production for a short time, (ii) a fire that shut-in a considerable amount of production for a short time and (iii) temporarily shutting in a considerable amount of production periodically for offset completion operations. The issues described in (i) and (ii) have been resolved and do not continue to impact our crude oil production. In addition, a significant portion of natural gas production in our Flat Top operating area was negatively impacted due to the inability of a new natural gas plant to take all of our volumes since coming online in December 2022. This issue improved during the second and third quarters of 2023 but is still not completely resolved. It is expected to be fully resolved during the fourth quarter of 2023 as the natural gas gatherer continues to optimize their gathering system. These production issues not only curtailed Boe production during the nine months ended September 30, 2023, but they also all increased the costs to the Company. The increase in workover expenses can be attributed to more well work being performed, most significantly, the replacement of tubing strings on two of the Company’s salt-water disposal wells, pump downsizes, and other well work that is being performed to reestablish production on legacy vertical wells that have gone down for various reasons. We anticipate the operating costs per Boe and workover expenses per Boe to continue to decrease in the fourth quarter of 2023. Significant drivers to this decrease are associated with (i) reduced chemical and treating costs by connecting wells in the southeast portion of Flat Top to a new third party facility during the fourth quarter of 2023, (ii) increasing the operational capacity of the natural gas plant taking our Flat Top natural gas production which should increase our NGL and natural gas sales going forward, (iii) returning production back on line that was off line during the three and nine months ended September 30, 2023 related to offset frac operations, weather and fire events that shut-in production for a temporary period of time and related costs, and (iv) reduced workover expense.

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.

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, 2023, compared with the same periods in 2022, was primarily due to the 16% and 26% decrease in realized prices, respectively.

Exploration and abandonments expense.

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

Exploration and abandonment costs increased during the three and nine months ended September 30, 2023 primarily due to $1.1 million and $3.1 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 and higher plugging and abandonment costs related to increased activity centered around legacy vertical wells. 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 to drill in time to save the leases for a multitude of reasons.

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 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 or so as well as bolt-on acquisitions.

General and administrative expense.

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

The increase in general and administrative expense for the three and nine months ended September 30, 2023 is primarily as a result of accrued bonuses in 2023 which were not recognized until the fourth quarter in 2022, 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. The decrease in the rate per Boe for the nine months ended September 2023 compared to the same period in 2022 is the result of economies of scale and efficiencies gained as we bring additional wells on production due to our successful horizontal drilling program.

Interest expense.

The increase in interest expense can be attributed to the fact that we have continued to increase our borrowings under our Prior Credit Agreement, and we issued $225.0 million of 10.000% Senior Notes in February 2022 and $225.0 million and $25.0 million of 10.625% Senior Notes in November and December 2022, respectively, and additional interest of $8.3 million on the 10.625% Senior Notes in June 2023 related to not achieving an increased rating and increased amortization of discounts and debt issuance costs related to these new issuances. In addition, the Company issued $1.2 billion under the Term Loan Credit Agreement in mid-September 2023 and paid off the Prior Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes.

Gain (loss) on derivative instruments, net.

The Company primarily utilizes commodity swap contracts and 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 and the newly entered into deferred premium collars and deferred premium put option contracts.

Other expense.

The Company paid $6.5 million during the second quarter of 2023 to buyout and terminate a water treatment contract with a former outside board member. Other costs of $1.5 million relate primarily 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, 2023, compared with the same periods in 2022, was due to the Company realizing decreased net income during the three and nine months ended September 30, 2023 compared to the same periods in 2022. The effective income tax rate differs from the statutory rate primarily due to a revision in the deferred tax asset related to certain stock-based compensation and permanent differences between GAAP income and taxable income during the nine months ended September 30, 2022. 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 which include the remaining net proceeds of the Term Loan financing, (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 beginning March 31, 2024, (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.

2023 capital budget. In March 2023, the Company determined to reduce its previously reported capital budget for 2023 in connection with its transition from a six-rig drilling program to a two-rig drilling program. The Company anticipates moving to a three-rig program in the fourth quarter of 2023. The Company currently expects total capital expenditures for 2023 to be in the range of approximately $900.0 to $975.0 million for drilling, completion, facilities and equipping crude oil wells plus $50 to $60 million for field infrastructure buildout and other costs. The 2023 reduced 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 generated by operations and cash on its consolidated balance sheet which includes the remaining net proceeds of the Term Loan financing. The Company’s capital expenditures for the nine months ended September 30, 2023 were $840.0 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, economic downturn or potential recession, a potential government shut-down, geo-political risks and additional actions by businesses, OPEC and other cooperating countries, and governments in response to the COVID-19 pandemic, 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, 2023, compared with 2022, was primarily related to higher revenues associated with increased production volumes as a result of our successful horizontal drilling program.

Investing activities. The increase in net cash used in investing activities for the nine months ended September 30, 2023, compared with 2022, was primarily due to increases in additions to crude oil and natural gas properties compared with the nine months ended September 30, 2022, when the Company had more drilling rigs and frac crews running compared with the prior year period, partially offset by a significant decrease in cash crude oil and natural gas property acquisition costs.

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

• 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.
• Nine months ended September 30, 2022: The Company received $210.2 million in net proceeds from the issuance of the 10.000% Senior Notes, borrowed a net $255.0 million on the Prior Credit Agreement and received $85.0 million in proceeds from a private placement of HighPeak Energy common stock, $7.8 million from the exercise of warrants and $120,000 from the exercise of stock options. These cash inflows were partially offset by the Company incurring $9.2 million of debt issuance costs primarily related to the 10.000% Senior Notes, $8.5 million in dividends and dividend equivalent payments and $290,000 in stock issuance costs related to the aforementioned private placement.

Interest Rate Risk. We are exposed to market risk due to the floating interest rate associated with any outstanding balance on the Term Loan Credit Agreement. As of September 30, 2023, we had a $1.2 billion outstanding balance on the Term Loan Credit Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the beginning of each quarter for a period three months. To the extent that the interest rate on our long-term debt is fixed, interest rate changes will affect the fair value but will not impact results of operations or cash flows. However, for the Term Loan Credit 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. However, future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, could have further negative impacts on prices. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing armed conflicts between Russia and Ukraine and between Israel and Hamas, and recent production cut announcements from OPEC. 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, 2023 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, 2023 would have increased (decreased) the Company’s revenues by approximately $13.9 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, 2023 would have increased (decreased) the Company’s revenues by approximately $663,000 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, 2023, 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 $3.9 million.

Contractual obligations. The Company's contractual obligations include leases (primarily related to contracted drilling rigs, equipment and office facilities), capital funding obligations, volume commitments, aid-in-construction 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. 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).” 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. The Term Loan Credit Agreement and Senior Credit Facility Agreement provides 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 debt, as defined in the Term Loan Credit Agreement and Senior Credit Facility Agreement, to EBITDAX, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, lenders under those agreements would be entitled to exercise all of their remedies for default.

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

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, 2023. 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, 2018 through September 30, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2021 would have increased (decreased) the Company’s revenues by approximately $13.6 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, 2023 would have increased (decreased) the Company’s revenues by approximately $663,000 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 for the outstanding borrowings under the Senior Credit Facility 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, 2023 market quotes were as follows:

The average forward prices based on November 2, 2023 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, 2023, we had $1.2 billion outstanding under the Term Loan Credit Agreement and no available borrowing capacity. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement. The impact of a 1% increase in interest rates on our outstanding debt as of September 30, 2023 would have resulted in an annual increase in interest expense of approximately $12.0 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, 2023 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, except as described below.

Restrictions in our Term Loan Credit Agreement, our Senior Credit Facility Agreement and any future debt agreements could limit our growth and ability to engage in certain activities.

The terms and conditions governing our Term Loan Credit Agreement, our Senior Credit Facility Agreement and any future additional indebtedness are expected to:

• require us to dedicate a portion of cash flow from operations to service our debt, thereby reducing the cash available to finance operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
• increase vulnerability to economic downturns and adverse developments in our business;
• place restrictions on our ability to engage in certain business activities, including without limitation, to raise capital, obtain additional financing (whether for working capital, capital expenditures or acquisitions) or to refinance indebtedness, grant or incur liens on assets, pay dividends or make distributions in respect of our capital stock, make investments, amend or repay subordinated indebtedness, sell or otherwise dispose of assets, businesses or operations and engage in business combinations or other fundamental changes;
• potentially place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
• limit management’s discretion in operating our business.

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

Our existing and future indebtedness may adversely affect our cash flows and ability to operate our business, remain in compliance and repay our debt.

As of September 30, 2023, we have $1.2 billion of total indebtedness outstanding under our Term Loan Credit Agreement, which contains restrictive covenants and other provisions with which we must comply on an ongoing basis.

We may be unable to repay amounts due when they become due, and our ability to refinance our indebtedness on reasonable terms may be limited. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to several significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial, and some of which may be secured by our assets. Our current level of indebtedness could have important consequences, such as:

• making it difficult for us to satisfy our obligations under our indebtedness and contractual and commercial commitments;
• increasing our vulnerability to adverse economic and industry conditions;
• requiring us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, or otherwise reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;
• limiting our flexibility to plan for, or react to, changes in our business and the industry in which we operate;
• restricting us from making strategic acquisitions or exploiting business opportunities;
• placing us at a competitive disadvantage compared to our competitors that have less debt;
• limiting our ability to borrow additional funds; and
• decreasing our ability to compete effectively or operate successfully under adverse economic and industry conditions.

Our results of operations and cash flows vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry.

We expect our results of operations and cash flows to vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flows may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and as a result, our ability to generate cash flows from operations and to pay our debt. Many of these factors, such as crude oil, NGL and natural gas prices, regulatory factors, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. If we do not generate sufficient cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring our debt;
• selling assets;
• reducing or delaying capital investments; or
• seeking to raise additional capital.

However, any alternative financing plans that we undertake may not allow us to meet our debt obligations. Any refinancing or debt restructuring may not be possible, any assets may not be sold or, if sold, the timing of the sales and the amount of proceeds realized from those sales may not be favorable to us or additional financing may not be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt obligations could materially and adversely affect our business, financial condition, results of operations and prospects.

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and could require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest or principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to refinance our indebtedness, sell assets or issue equity, or borrow more funds on terms acceptable to us, if at all.

In addition, if we fail to comply with the covenants or other terms of our Term Loan Credit Agreement or Senior Credit Facility Agreement, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.