# HighPeak Energy, Inc. (HPK) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from HighPeak Energy, Inc.'s 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1792849/000143774922005397/hpe20211231_10k.htm
Accession: 0001437749-22-005397
Filing date: 2022-03-07
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/HPK/
All MD&A years: /company/HPK/mda/
Next year: /company/HPK/mda/fy2022/ (FY 2022)

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

The following discussion and analysis should be read in conjunction with the other sections of this Annual Report, including but not limited to Items 1 and 2: Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.” Historical financial statements and related notes included elsewhere in this Report. This discussion contains “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report. Please read Cautionary Statement Concerning Forward‑Looking Statements. Also, please read the risk factors and other cautionary statements described under “Part I, Item 1A. Risk Factors.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law. See the Company's Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 15, 2021 for a discussion of the Company's 2020 results of operations as compared to the Company's 2019 results of operations.

Overview

HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019 solely for the purpose of combining the businesses of Pure and HPK LP, referred to herein as the “HighPeak business combination,” which was completed on August 21, 2020. HPK LP was formed in August 2019 for the purpose combining the assets of HighPeak I and HighPeak II into one entity. HighPeak I was formed in June 2014 for the purpose of acquiring, exploring and developing crude oil and natural gas properties, although it had no activity until 2017. Beginning in late 2017, HighPeak I began acquiring its assets through an organic leasing campaign and a series of acquisitions consisting primarily of leasehold acreage and existing vertical producing wells.

The Company’s assets are located primarily in Howard County, Texas, which lies within the northeastern part of the crude oil-rich Midland Basin. As of December 31, 2021, the assets consisted of two highly contiguous leasehold positions of approximately 82,023 gross (62,603 net) acres, approximately 44% of which were held by production, with an average working interest of 76%. Our acreage is composed of two core areas, Flat Top to the north and Signal Peak to the south. We operate approximately 90% of the net acreage across the Company’s assets and approximately 98% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the year ended December 31, 2021, approximately 95% and 5% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2021, HighPeak Energy was drilling with three (3) rigs and was in the process of rigging up a fourth rig. Further, as of December 31, 2021, the Company owned an interest in approximately 246 gross (105.7 net) producing wells, 78 gross (71.3 net) of which are operated by the Company, including 59 gross (47.4 net) horizontal wells, 43 gross (41.5 net) of which are operated by the Company. As of December 31, 2021, of the 64,213 MBoe of proved reserves associated with the assets, 45% were developed, 92% of which were liquids.

The markets for the commodities produced by our industry strengthened in 2021 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, commodity markets remain subject to heightened levels of uncertainty related to the COVID-19 pandemic and escalating tensions between Russia and Ukraine. Russian military incursion into Ukraine could give rise to regional instability and result in heightened economic sanctions by the U.S. and the international community that, in turn, could increase uncertainty with respect to global financial markets and production output from OPEC and other crude oil producing nations. Additionally, the COVID-19 pandemic remains a global health crisis and continues to evolve. Despite the emergence of new variants, deployment of vaccines and vaccine boosters to slow the spread of the COVID-19 virus has resulted in substantial improvements in global financial markets and public health. Disruption in financial and commodity markets and industry-specific impacts could result from future case surges or 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, and as a result, may require us to adjust our business plan. Despite continuing impacts of the COVID-19 pandemic, geopolitical issues, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.

The financial results as presented in this section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” consist of the historical results of HPK LP for the period from January 1, 2020 through August 21, 2020 and the Company from August 22, 2020 through December 31, 2021. At the Closing of the HighPeak business combination on August 21, 2020, the Company’s “predecessor” for accounting purposes was HPK LP for the period from January 1, 2020 through August 21, 2020 (the “Predecessor”).

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 December 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $81.22, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $6.20.

Based on current commodity prices and other factors, the Company currently plans to operate four (4) drilling rigs and an average of two (2) frac fleets in the Permian Basin during 2022. However, there are many factors and consequences beyond the Company's control, such as policies of the Biden Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, 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”. 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.

57

Impact of Hedging

With the addition of the Revolving Credit Facility in December 2020, HighPeak Energy was required to and has entered into hedging arrangements. The Company’s outstanding crude oil derivative contracts and the weighted average crude oil prices per barrel for those contracts, including those contracts entered into subsequent to December 31, 2021, are as follows:

[[GREPCENT_TABLE]]
[["","","2022","","","2023"],["","","First Quarter","","","Second Quarter","","","Third Quarter","","","Fourth Quarter","","","Total","","","First Quarter","","","Second Quarter","","","Total"],["Crude Oil Price Swaps - WTI: (a)"],["Volume (MBbls)","","","966.4","","","","1,039.8","","","","456.4","","","","487.4","","","","2,950.0","","","","441.0","","","","200.2","","","","641.2"],["Price per Bbl","","$","69.26","","","$","71.96","","","$","75.15","","","$","70.14","","","$","71.27","","","$","70.05","","","$","57.22","","","$","66.04"]]
[[/GREPCENT_TABLE]]

Impact of the COVID-19 Pandemic

The COVID-19 pandemic that resulted in a severe worldwide economic downturn in early 2020, significantly disrupting the demand for crude oil and natural gas throughout the world, and created significant volatility, uncertainty and turmoil in the crude oil and natural gas industry has largely recovered. The decrease in demand for crude oil combined with pressures on the global supply-demand balance for crude oil and related products, resulted in crude oil prices declining significantly beginning in late February 2020. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global crude oil demand, which will ultimately depend on various factors and consequences beyond the Company's control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, the ability of OPEC, Russia and other crude oil producing nations to manage the global crude oil supply, additional actions by businesses and governments in response to the pandemic, the economic downturn and the decrease in crude oil demand, the speed and effectiveness of responses to combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry. In response to these developments, the Company has implemented measures to mitigate the impact of the COVID-19 pandemic on its employees, operations and financial position. These measures include, but are not limited to, the following:

Employee Safety. The Company has taken steps to keep its employees safe during the COVID-19 pandemic by implementing preventative measures and developing response plans intended to minimize unnecessary risk of exposure and infection among its employees. The Company has also modified certain business practices (including those related to non-operational employee work locations, such as a significant reduction in physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, and other governmental and regulatory authorities.

Materials Management. With the supply chain disruptions, overall inflation on materials in general and lack of availability of tubulars, vessels and pumps, the Company has implemented the precautionary measure of pre-ordering many of these types of equipment to ensure they are available when needed to continue our drilling program to minimize delays due to shortages.

Balance Sheet, Cash Flow and Liquidity. The Company has taken the following actions to strengthen its financial position and increase liquidity:

[[GREPCENT_TABLE]]
[["","\u2022","Maintained a strong balance sheet and pursued increased liquidity by issuing a small amount of equity and adding a credit facility with attractive interest rates."],["","\u2022","Used derivative positions to reduce the effects of crude oil price volatility on its net cash provided by operating activities."]]
[[/GREPCENT_TABLE]]

The Company continues to assess the global impacts of the COVID-19 pandemic and may modify its plans as the health and economic impacts of COVID-19 continue to evolve.

Financial and Operating Performance

The Company's financial and operating performance for the year ended December 31, 2021 included the following highlights:

[[GREPCENT_TABLE]]
[["","\u2022","Net income attributable to common stockholders for the year ended December 31, 2021 was $55.6 million ($0.54 per diluted share) compared with a combined net loss of the Company and its Predecessor of $101.5 million for the year ended December 31, 2020. The primary components of the $157.0 million increase in earnings attributable to common stockholders include:"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","a $195.5 million increase in crude oil and natural gas revenues due to a 383% increase in daily sales volumes due to the Company\u2019s successful horizontal drilling program in the Permian Basin, plus an 86% increase in average realized commodity prices per Boe, excluding the effect of derivatives;"]]
[[/GREPCENT_TABLE]]

58

[[GREPCENT_TABLE]]
[["","\u2022","a decrease in other expense of $76.3 million primarily due to a charge to expense in 2020 related to an acquisition that was terminated in April 2020;"],["","\u2022","a $9.1 million decrease in stock-based compensation expense primarily attributable to stock options that were granted in August 2020 upon the closing of the HighPeak business combination whereby approximately 75% of the stock options vested immediately causing a charge to earnings; and"],["","\u2022","a $3.5 million decrease in exploration and abandonment expenses related to lower impairment of undeveloped leasehold costs that the Company was not successful in obtaining extensions on of $4.6 million during 2021 compared with 2020 partially offset by increased geophysical data purchases and geologic and geophysical personnel costs of $1.1 million during 2021 compared with 2020;"]]
[[/GREPCENT_TABLE]]

partially offset by:

[[GREPCENT_TABLE]]
[["","\u2022","a $48.9 million increase in DD&A expense due to a 383% increase in daily sales volumes, partially offset by an 17% decrease in the DD&A rate from $23.08 to $19.20 per Boe, both as a result of increased proved reserves due to the Company\u2019s successful horizontal drilling program in the Permian Basin;"],["","\u2022","a $26.8 million increase in production costs, including production and ad valorem taxes, primarily attributable to the 383% increase in daily sales volumes as a result of the Company\u2019s successful horizontal drilling program in the Permian Basin combined with 53% higher production and ad valorem taxes on a dollar per Boe basis due to higher overall realized prices of 86%;"],["","\u2022","a derivative loss of $26.7 million during the year ended December 31, 2021 compared with zero in the prior year consisting of $11.3 million in settlement payments on contracts that have expired and $15.4 million in net mark to market losses on contracts for future months;"],["","\u2022","a $21.1 million increase in the Company's income tax expense due to the net income experienced in 2021 compared with the net loss experienced in 2020 and the fact that the Predecessor was a pass through entity for income tax purposes and did not recognize any tax expense or benefit on their financial statements;"],["","\u2022","a $2.5 million increase in the Company's interest expense due to the borrowings on the Company\u2019s revolving credit facility that began in early 2021; and"],["","\u2022","a $1.3 million increase in general and administrative costs due primarily to bonuses paid to HighPeak Energy employees compared with none in the prior year."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","During the year ended December 31, 2021, average daily sales volumes totaled 9,304 Boepd, an increase of 383% over 2020, due to the Company's successful horizontal drilling program in the Permian Basin."],["","\u2022","Weighted average realized crude oil prices per Bbl increased during the year ended December 31, 2021 to $70.10, excluding the effects of derivatives, compared with $37.96 for 2020. Weighted average realized NGL prices per Bbl increased during the year ended December 31, 2021 to $35.11, compared with $14.06 for 2020. Weighted average realized natural gas prices per Mcf increased to $3.88 during the year ended December 31, 2021, compared with $1.04 during 2020."],["","\u2022","Cash provided by operating activities totaled $147.0 million for the year ended December 31, 2021."],["","\u2022","The Company increased its borrowing capacity under its Revolving Credit Facility to $195 million with $100.0 million drawn as of December 31, 2021. The Company also raised $22.8 million of capital, net of offering costs, in October 2021 with the issuance of 2,530,000 shares of common stock. This capital gave the Company flexibility to increase its development drilling program from one to three rigs late in 2021 with the addition of a fourth rig underway at yearend. During the year, the Company placed 30 gross (24.5 net) horizontal wells on production, drilled and completed 1 gross (1.0 net) salt-water disposal well and completed $54.0 million in acquisitions of both producing properties and a significant amount of bolt-on undeveloped acreage increasing its drilling inventory. As of December 31, 2021, the Company was also in the process of drilling 5 gross (5.0 net) horizontal producers and 1 gross (1.0 net) salt-water disposal well and had 22 gross (18.0 net) horizontal producers either waiting on completion or in various stages of completion operations."]]
[[/GREPCENT_TABLE]]

59

Operations and Drilling Highlights

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31, 2021"],["Oil (Bbls)","","","8,225"],["NGL (Bbls)","","","613"],["Gas (Mcf)","","","2,795"],["Total (Boe)","","","9,304"]]
[[/GREPCENT_TABLE]]

The Company's liquids production was 95% of total production on a Boe basis for the year ended December 31, 2021.

Costs incurred are as follows (in thousands):

[[GREPCENT_TABLE]]
[["","","Year ended December 31, 2021"],["Unproved property acquisition costs","","$","20,792"],["Proved acquisition costs","","","33,253"],["Total acquisitions","","","54,045"],["Development costs","","","45,852"],["Exploration costs","","","190,346"],["Total finding and development costs","","","290,243"],["Asset retirement obligations","","","1,844"],["Total costs incurred","","$","292,087"]]
[[/GREPCENT_TABLE]]

Development and exploration/extension drilling activity is as follows:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31, 2021"],["","","Development/ Service","","","Exploration/ Extension"],["Beginning wells in progress","","","\u2014","","","","4"],["Well spud","","","9","","","","41"],["Successful wells","","","(3",")","","","(23",")"],["Ending wells in progress","","","6","","","","22"]]
[[/GREPCENT_TABLE]]

During the year ended December 31, 2021, the Company successfully drilled twenty-six (26) horizontal wells, of which twenty-one (21) horizontal wells were located in Flat Top, including one (1) salt-water disposal well, and five (5) were located in Signal Peak. Also, we had an additional twenty-eight (28) wells in progress as of December 31, 2021. At Flat Top, we had four (4) wells being drilled, including three (3) horizontal wells and one (1) salt-water disposal well and twenty (20) horizontal wells in various stages of completion. At Signal Peak, we had two (2) horizontal wells being drilled and two (2) horizontal wells in various stages of completion.

Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 15, 2021 for a discussion of the Company’s 2020 results of operations as compared with the Company’s 2019 results of operations.

Sources of Revenues

The Company’s revenues, which are entirely originated in the continental United States, are derived from the sale of crude oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. For the years ended December 31, 2021 and 2020, revenues from our assets were derived approximately 96% and 98%, respectively, from crude oil sales and 4% and 2%, respectively, from NGL and natural gas sales.

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers.  For the year ended December 31, 2021, sales to the Company’s largest purchaser accounted for approximately 94% of the Company’s total crude oil, NGL and natural gas sales revenues.  The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

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

60

Principal Components of Cost Structure

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

[[GREPCENT_TABLE]]
[["","\u25cf","Lease Operating Expenses. Lease operating expenses (\u201cLOE\u201d) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, workover rigs and workover expenses, materials and supplies comprise the most significant portion of LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, power costs are incurred in connection with various production-related activities, such as pumping to recover crude oil and natural gas and separation and treatment of water produced in connection with crude oil and natural gas production."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","The Company monitors the operation of its assets to ensure that it is incurring LOE at an acceptable level. For example, it monitors LOE per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows the Company to monitor these costs to identify trends and to benchmark against other producers. Although the Company strives to reduce its LOE, these expenses can increase or decrease on a per-unit basis as a result of various factors as it operates its assets or makes acquisitions and dispositions of properties. For example, the Company may increase field-level expenditures to optimize their operations, incurring higher expenses in one quarter relative to another, or they may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence overall operating cost and could cause fluctuations when comparing LOE on a period-to-period basis."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Production and other taxes. Production and other taxes are paid on produced crude oil and natural gas based on rates established by federal, state or local taxing authorities. In general, production and other taxes paid correlate to changes in crude oil, NGL and natural gas revenues. Production taxes are based on the market value of production at the wellhead. The Company is also subject to ad valorem taxes in the counties where production is located. Ad valorem taxes are based on the fair market value of the mineral interests for producing wells."],["","\u25cf","Depletion \u2013 Crude Oil and Natural Gas Properties. Depletion is the systematic expensing of the capitalized costs incurred to acquire and develop crude oil and natural gas properties. The Company uses the successful efforts method of accounting for crude oil and natural gas properties. Accordingly, all costs associated with acquisition, successful exploration wells and development of crude oil and natural gas reserves, including directly related overhead costs and asset retirement costs are capitalized. However, the costs of abandoned properties, exploratory dry holes, geophysical costs and annual lease rentals are charged to expense as incurred. All capitalized costs of crude oil and natural gas properties are amortized on the unit-of-production method using estimates of proved reserves. Any remaining investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs."],["","\u25cf","General and Administrative Expenses. General and administrative expenses (\u201cG&A\u201d) are costs incurred for overhead, including payroll and benefits for corporate staff and costs of maintaining a headquarters, costs of managing production and development operations, IT expenses and audit and other fees for professional services, including legal compliance and acquisition-related expenses."]]
[[/GREPCENT_TABLE]]

Factors Affecting the Comparability of the Predecessor Historical Financial Results

The comparability of the Predecessor results of operations among the periods presented, and for future periods, is impacted by the following factors:

[[GREPCENT_TABLE]]
[["","\u25cf","The historical financial statements included herein are the financial statements of HPK LP for the period beginning January 1, 2020 and ending on August 21, 2020, as the Predecessor for financial reporting purposes;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","as a corporation, for U.S. federal income tax purposes, HighPeak Energy is subject to U.S. federal income taxes at a statutory rate of 21% of pretax earnings. This is a significant change from the Predecessor\u2019s historical tax treatment because the Predecessor was treated as a partnership for U.S. federal income tax purposes and, as such, the partners of the Predecessor reported their share of the Predecessor\u2019s income or loss on their respective income tax returns;"]]
[[/GREPCENT_TABLE]]

61

[[GREPCENT_TABLE]]
[["","\u25cf","our assets will incur certain additional general and administrative expenses related to being owned by a publicly traded company, that were not previously incurred in HPK LP\u2019s cost structure, including, but not limited to, Exchange Act reporting expenses; expenses associated with compliance with the Sarbanes-Oxley Act of 2002; expenses associated with being listed on a national securities exchange; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs and non-management director compensation;"],["","\u25cf","the Predecessor completed acquisitions during the periods presented, including primarily the acquisition of undeveloped acreage and to a lesser extent producing properties and proved undeveloped reserves for approximately $3.3 million during the period from January 1, 2020 through August 21, 2020;"],["","\u25cf","during the period beginning January 1, 2020 and ending on August 21, 2020, HPK LP recognized a charge to expense of $76.5 million related to the termination of the Grenadier Acquisition (as defined in \u201cItem 8. Financial Statements and Supplementary Data;\u201d and"],["","\u25cf","Our Predecessor financed operations predominantly through equity financing, while beginning with the establishment of our Revolving Credit Facility in December 2020, continued borrowing base increases and our recent notes offering of 2024 Notes in February 2022, we have financed a significant portion of our operations and growth with indebtedness."]]
[[/GREPCENT_TABLE]]

Results of Operations

Results of operations should be read together with the Company's consolidated financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K.

Crude Oil, NGL and natural gas revenues.

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

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year Change"],["","","Successor","","","Successor","","","Predecessor"],["","","(in thousands)"],["Crude oil, NGL and natural gas revenues","","$","220,124","","","$","16,400","","","$","8,223","","","$","195,501"]]
[[/GREPCENT_TABLE]]

Average daily sales volumes are as follows:

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Crude Oil (Bbls)","","","8,225","","","","3,017","","","","1,007","","","","375","%"],["NGL (Bbls)","","","613","","","","134","","","","86","","","","495","%"],["Natural Gas (Mcf)","","","2,795","","","","849","","","","373","","","","413","%"],["Total (Boe)","","","9,304","","","","3,292","","","","1,154","","","","383","%"]]
[[/GREPCENT_TABLE]]

The increase in average daily Boe sales volumes for the year ended December 31, 2021, compared with 2020 was due to the Company's successful horizontal 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 prices are as follows:

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Oil per Bbl","","$","70.10","","","$","40.15","","","$","34.26","","","","85","%"],["NGL per Bbl","","$","35.11","","","$","19.44","","","$","9.31","","","","150","%"],["Gas per Mcf","","$","3.88","","","$","1.45","","","$","0.52","","","","273","%"],["Total per Boe","","$","64.82","","","$","37.74","","","$","30.44","","","","86","%"]]
[[/GREPCENT_TABLE]]

62

The increase in prices for crude oil, NGL and natural gas for the year ended December 31, 2021, compared with 2020 was due to a higher commodity price environment.

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):

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Crude oil and natural gas production costs","","$","25,053","","","$","2,653","","","$","4,870","","","","233","%"],["Crude oil and natural gas production costs per Boe","","$","7.38","","","$","6.10","","","$","18.03","","","","(31",")%"]]
[[/GREPCENT_TABLE]]

The increase in lease operating expenses can be attributed to the fact that by the end of 2021 we had ownership in fifty-nine (59) producing horizontal wells compared with nineteen (19) horizontal wells at the end of 2020. Likewise, the decrease in lease operating expense per Boe for the year ended December 31, 2021, compared with 2020, was primarily attributable to the increased production volumes associated with the higher well count. We anticipate continued reduction to the lease operating expense per Boe as we put more wells on production, start up our electrification project which will reduce the use of generators for power and continue to expand our salt-water collection and disposal system to decrease the use of trucks.

Production and ad valorem taxes.

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

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Production and ad valorem taxes","","$","10,746","","","$","886","","","$","566","","","","1,799","%"]]
[[/GREPCENT_TABLE]]

In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices and valuations as of the first of the year, whereas production taxes are based upon current year commodity prices and sales volumes.

Production and ad valorem taxes per Boe are as follows:

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Production taxes per Boe","","$","3.09","","","$","1.78","","","$","1.42","","","","118","%"],["Ad valorem taxes per Boe","","$","0.07","","","$","0.26","","","$","0.68","","","","(90",")%"]]
[[/GREPCENT_TABLE]]

Production taxes per Boe for the year ended December 31, 2021, compared with 2020, increased primarily due to the 86% overall increase in commodity prices. The decrease in ad valorem taxes per Boe for the year ended December 31, 2021, compared with 2020, was primarily due to a significant number of wells that have come on production during 2021 that had no ad valorem tax in 2021 as 2022 will be the first year that they will be assessed ad valorem taxes. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.

63

Exploration and abandonments expense.

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

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Geologic and geophysical data costs","","$","807","","","$","179","","","$","3","","","","351","%"],["Geologic and geophysical personnel costs","","","487","","","","4","","","","\u2014","","","","6,857","%"],["Abandoned leasehold costs","","","235","","","","4,827","","","","\u2014","","","","(95",")%"],["Plugging and abandonment expense","","","20","","","","22","","","","1","","","","(13",")%"],["Exploration and abandonments expense","","$","1,549","","","$","5,032","","","$","4","","","","(69",")%"]]
[[/GREPCENT_TABLE]]

The decrease in exploration and abandonment expenses is primarily the result of a reduction in various insignificant undeveloped leases that we chose not to extend, partially offset by an increase in geologic and geophysical personnel costs being classified as a part of exploration and abandonment expense that are now identifiable and not merely a component of administration fees paid to a management company and increased geologic and geophysical data expenses.

Depletion, depreciation and amortization expense.

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

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["DD&A expense","","$","65,201","","","$","9,877","","","$","6,385","","","","301","%"],["DD&A expense per Boe","","$","19.20","","","$","22.73","","","$","23.64","","","","(17",")%"]]
[[/GREPCENT_TABLE]]

The increase in DD&A expense and decrease in DD&A expense per Boe is primarily due to the increased production associated with our successful horizontal drilling program and 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):

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["General and administrative expense","","$","8,885","","","$","2,775","","","$","4,840","","","","17","%"],["General and administrative expense per Boe","","$","2.62","","","$","6.39","","","$","17.92","","","","(76",")%"],["Stock-based compensation expense","","$","6,676","","","$","15,776","","","$","\u2014","","","","(58",")%"]]
[[/GREPCENT_TABLE]]

The increase in general and administrative expense for the year ended December 31, 2021 is primarily as a result of increased employee count, salary increases, annual bonuses paid to employees in December 2021 and the increased administrative costs associated with being a public company, partially offset by more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count in 2021 compared with 2020, no business combination charges in 2021 compared with 2020 and lower exploration general and administrative expenses that are classified as exploration and abandonment expense which are now identifiable and not included as a component of administration fees paid to a management company.

64

The decrease in noncash stock-based compensation expense is due to fewer awards being issued in 2021 as compared with 2020.

Interest expense.

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Interest expense","","$","2,484","","","$","8","","","$","\u2014","","","","30,950","%"]]
[[/GREPCENT_TABLE]]

The increase in interest expense can be attributed to the fact that we entered into our Revolving Credit Facility in December 2020 and began drawing on it late in the second quarter of 2021. Interest expense for the year ended December 31, 2021 includes interest expense of $1.7 million, commitment fees of $245,000 and amortization of debt issuance costs of $498,000.

Derivative gain (loss), net.

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Noncash derivative gain (loss), net","","$","(15,467",")","","$","\u2014","","","$","\u2014","","","","100","%"],["Cash payments on settled derivative instruments, net","","","(11,267",")","","","\u2014","","","","\u2014","","","","100","%"],["Derivative gain (loss), net","","$","(26,734",")","","$","\u2014","","","$","\u2014","","","","100","%"]]
[[/GREPCENT_TABLE]]

The Company primarily utilizes commodity swap contracts, collar contracts, collar contracts with short puts and basis swap 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 Credit Agreement and the indenture for the Company’s 2024 Notes require the Company to hedge certain quantities of its projected crude oil production. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market loss and cash settlements relate to crude oil derivative swap contracts.

Income tax expense.

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year % Change"],["","","Successor","","","Successor","","","Predecessor"],["Income tax expense (benefit)","","$","16,904","","","$","(4,223",")","","$","\u2014","","","","n/a"],["Effective income tax rate","","","23.3","%","","","20.4","%","","","0.0","%","","","n/a"]]
[[/GREPCENT_TABLE]]

The change in income tax expense during the year ended December 31, 2021, compared with 2020, was due to the Company realizing net income during the year ended December 31, 2021 compared with a net loss for the period from August 22, 2020 through December 31, 2020 and the fact that the Predecessor was treated as a partnership for U.S. federal income tax purposes and, as such, the partners of the Predecessor reported their share of the Company’s income or loss on their respective income tax returns. In contrast, HighPeak Energy is a corporation and is subject to U.S. federal income taxes on any income or loss following the business combination on August 21, 2020. The effective income tax rate differs from the statutory rate primarily due to permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

65

Liquidity and Capital Resources

Liquidity. The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, including cash proceeds from our recent $225 million offering of 2024 Notes, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under our Revolving Credit Facility, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets.

The Company's short-term and long-term liquidity requirements consist primary of  (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of contractual obligations and (iv) working capital obligations. Funding for these cash needs may be provided by any combination of the Company's sources of liquidity. Although the Company expects that its sources of funding will be adequate to fund its 2022 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company's future needs.

2022 capital budget. The Company’s capital budget for 2022 is expected to be in the range of approximately $715 to $760 million for drilling, completion, facilities and equipping crude oil wells plus $35 to $40 million for field infrastructure buildout and other costs. The 2022 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical general and administrative expenses and corporate facilities. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, through borrowings under the Credit Agreement, proceeds from the issuance and sale of the 2024 Notes and, depending on market circumstances, potential future debt or equity offerings. The Company's capital expenditures for the year ended December 31, 2021 were $290.2 million.

The budget above assumes that the Company will operate four (4) drilling rigs and an average of two (2) frac fleets in the Permian Basin during 2022. However, there are many factors and consequences beyond the Company's control, such as policies of the Biden Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, 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”. Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

Capital resources.

As of December 31, 2021, the Company had $100.0 million in outstanding borrowings and approximately $93.1 million available to borrow under its Revolving Credit Facility. The Company also had unrestricted cash on hand of $34.9 million as of December 31, 2021. In February 2022, the Company completed the issuance of $225.0 million principal amount of 10.00% senior unsecured notes due 2024 (the “2024 Notes”) providing net proceeds of approximately $203.9 million to the Company which it used to pay off debt outstanding under the Company’s Revolving Credit Facility and the borrowing base and bank commitments under the Revolving Credit Facility were decreased to $138.8 million. The remainder of the proceeds will be used for the Company’s 2022 capital budget and general corporate purposes.

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

[[GREPCENT_TABLE]]
[["","","","","","","Year Ended December 31, 2020"],["","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020","","","Year to Year Change"],["","","Successor","","","Successor","","","Predecessor"],["Net cash provided by (used in) operating activities","","$","147,015","","","$","5,413","","","$","(4,102",")","","$","145,704"],["Net cash used in investing activities","","$","(250,371",")","","$","(71,939",")","","$","(67,886",")","","$","(110,546",")"],["Net cash provided by financing activities","","$","118,673","","","$","84,135","","","$","51,220","","","$","(16,682",")"]]
[[/GREPCENT_TABLE]]

Operating activities. The increase in net cash flow provided by operating activities for the year ended December 31, 2021, compared with 2020, was primarily due to an increase in cash flow from the statement of operations related mostly to increased revenues associated with increased production volumes as a result of our successful horizontal drilling program coupled with an increase in accounts payable and accrued liabilities primarily as a result of prepayments by industry partners for their share of future capital expenditures, increased operating and general and administrative expenses and increased revenues payable to partners and royalty owners. Partially offsetting this increase was an increase in accounts receivable from the increased crude oil, NGL and natural gas revenues related to increased production volumes in December 2021 versus December 2020 and an increase in the amount of prepaid expenses, inventory and other noncurrent assets related to the Company’s increased drilling program.

66

Investing activities. The increase in net cash used in investing activities for the year ended December 31, 2021, compared with 2020, was primarily due to increases in additions to crude oil and natural gas properties as the Company ran one drilling rig at the beginning of the year, added a second rig late in the second quarter and third rig in the fourth quarter of 2021 compared with recommencing its drilling program in late 2020 after pausing its development drilling program in March 2020 in response to the COVID-19 pandemic. In addition, the Company spent $54.0 million in acquisitions of proved and unproved crude oil and natural gas properties in 2021 compared with $4.5 million in 2020. Partially offsetting these increases was the receipt of $3.4 million in proceeds during the year ended December 31, 2021 for the sale of nonstrategic assets compared with no such sales in 2020. In addition, during the year ended December 31, 2020, the Company funded an extension payment of $15.0 million related to an acquisition in 2020 that was terminated and funded notes receivable to Pure of $7.5 million related to the HighPeak business combination.

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

[[GREPCENT_TABLE]]
[["","\u2022","2021: The Company (i) borrowed $120.0 million and repaid $20.0 million for a net increase in long-term debt of $100.0 million under the Revolving Credit Facility, (ii) received $22.8 million from the issuance of 2,530,000 shares of common stock, net of issuance costs, (iii) received $10.6 million in proceeds from the exercises of warrants and stock options of the Company, (iv) paid dividends to its common stockholders of $11.6 million and paid dividend equivalents to certain of holders of restricted stock and vested stock options of $1.0 million and (iv) spent $2.2 million on debt issuance costs related to amendments and increased borrowing capacity under its Revolving Credit Facility."],["","\u2022","2020: The Company (i) received $84.5 million from the aforementioned HighPeak business combination, net of issuance costs, (ii) received $54.0 million in capital contributions from its partners prior to the Closing of the aforementioned HighPeak business combination, (iii) made distributions to its partners totaling $2.8 million prior to the Closing of the aforementioned HighPeak business combination and (iv) spent $405,000 on debt issuance costs related to closing its Revolving Credit Facility in December 2020."]]
[[/GREPCENT_TABLE]]

Interest Rate Risk.  We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of December 31, 2021, we had a $100.0 million outstanding balance on our Revolving Credit Facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the Revolving Credit Facility’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Revolving Credit Facility 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. Changes in interest rates do not impact the amount of interest we pay on our recently issued fixed-rate Notes subsequent to yearend but can impact their fair values.

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 escalating tensions between Russia and Ukraine. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 2021 sales volumes, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the year ended December 31, 2021 would have increased (decreased) the Company’s revenues by approximately $3.1 million and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2021 would have increased (decreased) the Company’s revenues by approximately $102,000.

We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2021, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have changed our net derivative positions for these products by approximately $2.6 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 (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures and certain other items. EBITDAX excludes certain items that 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 analysis, 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 Credit Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” In addition, EBITDAX is widely used by professional research analysis 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 (loss), income (loss) 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 (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our Revolving Credit Facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of total debt, as defined in the Credit Agreement, to EBITDAX, we would be in default. An event that would prevent us from borrowing under our Revolving Credit Facility would materially limit a significant source of our liquidity. In addition, if we are in default under our Revolving Credit Facility and are unable to obtain a waiver of that default from our lenders, the lenders under that facility would be entitled to exercise all of their remedies for default. 

67

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

[[GREPCENT_TABLE]]
[["","","","","","","","Year Ended December 31, 2020"],["","","","Year Ended December 31, 2021","","","August 22, 2020 through December 31, 2020","","","January 1, 2020 through August 21, 2020"],["","","","Successor","","","Successor","","","Predecessor"],["Net income (loss)","","","$","55,559","","","$","(16,429",")","","$","(85,034",")"],["Interest expense","","","","2,484","","","","8","","","","\u2014"],["Interest income","","","","(1",")","","","(6",")","","","\u2014"],["Income tax expense (benefit)","","","","16,904","","","","(4,223",")","","","\u2014"],["Depletion, depreciation and amortization","","","","65,201","","","","9,877","","","","6,385"],["Accretion of discount","","","","167","","","","51","","","","89"],["Exploration and abandonment expense","","","","1,549","","","","5,032","","","","4"],["Stock based compensation","","","","6,676","","","","15,776","","","","\u2014"],["Derivative related noncash activity","","","","15,467","","","","\u2014","","","","\u2014"],["Other expense","","","","167","","","","\u2014","","","","76,503"],["EBITDAX","","","$","164,173","","","$","10,086","","","$","(2,053",")"]]
[[/GREPCENT_TABLE]]

Critical Accounting Estimates

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

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

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

[[GREPCENT_TABLE]]
[["","\u25cf","the quality and quantity of available data;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","the interpretation of that data;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","the accuracy of various mandated economic assumptions; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","the judgment of the persons preparing the estimate."]]
[[/GREPCENT_TABLE]]

The Company's proved reserve information included in this Annual Report as of December 31, 2021 and 2020 was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions, positively or negatively, to the estimate of proved reserves. For the year ended December 31, 2021 and periods from August 22, 2020 through December 31, 2020 and January 1, 2020 through August 21, 2020, net downward revisions of our proved reserves totaled approximately 1,658 MBoe, 1,603 MBoe and 2,120 MBoe, respectively.  We cannot predict the amounts or timing of future reserve revisions or removals.

It should not be assumed that the standardized measure included in this Annual Report as of December 31, 2021 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2021 standardized measure on a twelve-month average of commodity prices on the first day of each month in 2021 and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Items 1 and 2. Business and Properties” and Unaudited Supplementary Data included in “Item 8. Financial Statements and Supplementary Data” for additional information.

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

Holding all other factors constant, if crude oil and natural gas prices used in our year-end reserve estimates increased to $72.00 per barrel and $3.75 per MMBtu of natural gas, our proved reserves as of December 31, 2021 could increase by approximately 296 MBoe, or less than 1%.  If the increase in proved reserves under this price sensitivity existed throughout 2021, our DD&A expense for 2021 would have decreased by approximately 1%.

68

Impairment of proved crude oil and natural gas properties. The Company reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved and risk-adjusted probable and possible reserves, management's price outlooks, production and capital costs expected to be incurred to recover the reserves, discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved crude oil and natural gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

Impairment of unproved crude oil and natural gas properties. At December 31, 2021, the Company carried unproved property costs of $108.4 million. Management assesses unproved crude oil and natural gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, management's price outlooks and planned future sales or expiration of all or a portion of such projects.

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

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

[[GREPCENT_TABLE]]
[["","\u25cf","The well has found a sufficient quantity of reserves to justify its completion as a producing well; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project."]]
[[/GREPCENT_TABLE]]

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

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

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

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

Uncertain tax positions. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefits is sustained upon examination by the taxing authorities, the tax benefit will be recorded as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recorded. As of December 2021, the Company did not have any unrecognized tax benefits. See Note 13 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

69

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

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

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

New Accounting Pronouncements

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

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