HighPeak Energy, Inc. 10-K

ITEM 5. MARKET FOR REGISTRANT ’ S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES   Market Information   HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq under the symbols “HPK” and “HPKEW,” respectively.   Holders   As of March 2, 2023, there were 48 holders of record of HighPeak Energy common stock and 5 holders of record of HighPeak Energy’s warrants.   Dividend Policy   On July 6, 2021, the Company announced the initiation of a quarterly cash dividend in the amount of $0.025 per share of our common stock payable quarterly which began with the third quarter of 2021 and continued quarterly through the fourth quarter of 2022 and first quarter of 2023. The Company also approved a special dividend of $0.075 per share of common stock that was paid in July 2021. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board. Our Board’s determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the Board deems relevant at the time of such determination. In addition, the Credit Agreement and the indentures governing the 10.000% Senior Notes and 10.625% Senior Notes place certain restrictions on our ability to pay cash dividends.   Stock Performance Graph   The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall the information be incorporated by reference into any future filing under the Securities Act or Exchange Act except to the extent that the Company specifically incorporate it be reference to such filing.   56     The graph below compares the cumulative total stockholder return on the Company’s common stock during the period from August 24, 2020 through December 31, 2022, with cumulative total returns during the same period for the Standard & Poor’s (“S&P”) 500 Index and the S&P Oil and Gas Exploration & Production Index.     The stock price performance included in this graph is not necessarily indicative of future stock price performance.     ITEM 6. [RESERVED]     57     ITEM 7. MANAGEMENT ’ S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   The following discussion and analysis should be read in conjunction with the other sections of this Annual Report, including but not limited to “ Items 1 and 2. Business and Properties — Regulation of the Crude Oil and Natural Gas Industry. ” Historical financial statements and related notes included elsewhere in this Annual Report. This discussion contains “ forward - looking statements ” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward - looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report. Please read Cautionary Statement   Concerning Forward - Looking Statements. Also, please read the risk factors and other cautionary statements described under “ Part I, Item 1A. Risk Factors. ” We assume no obligation to update any of these forward - looking statements, except as required by applicable law. See the Company ’ s Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on March 7, 2022 for a discussion of the Company's 2021 results of operations compared with the Company's 2020 results of operations.   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 December 31, 2022, the assets consisted of two highly contiguous leasehold positions of approximately 125,730 gross (107,704 net) acres, approximately 56% of which were held by production, with an average working interest of 86%. Our acreage is composed of two core areas, Flat Top to the north and Signal Peak to the south. We operate approximately 98% of the net acreage across the Company’s assets and more than 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the year ended December 31, 2022, approximately 94% and 6% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2022, HighPeak Energy was developing its properties using six (6) drilling rigs and three (3) frac fleets and expects to average four to five (4-5) drilling rigs and two to three (2-3) frac crews during 2023.   The markets for the commodities produced by our industry strengthened in 2021 and remained strong in 2022 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, 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 conflict in Ukraine, the COVID-19 pandemic, rising interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy’s ability to execute. Additionally, the COVID-19 pandemic remains a global health crisis and continues to evolve. Despite continuing impacts of these and other factors and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.  Additionally, the impact of inflation as well as rising interest rates continue to have a negative impact on our cash flows and results of 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 December 31, 2022, 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.   Based on first quarter 2023 commodity prices and other factors, the Company currently plans to average four to five (4-5) drilling rigs and two to three (2-3) frac fleets on its properties in the Permian Basin during 2023. 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. Additionally, the Board is evaluating a range of strategic alternative transactions to maximize shareholder value, including the potential sale of the Company.   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. 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 result in any transaction or other strategic change or outcome. The Company does not intend to comment further until it determines that further disclosure is appropriate or necessary.   58     Acquisitions   During the year ended December 31, 2022, the Company incurred a total of $527.3 million in acquisition costs to acquire various crude oil and natural gas properties largely contiguous to its Signal Peak and Flat Top operating areas primarily in Howard and Borden counties, consisting of approximately 45,101 net acres and associated producing properties, water system infrastructure and in-field fluid gathering pipelines. Included in the acquisition costs is the issuance of 10,853,634 shares of HighPeak Energy common stock valued at $265.0 million on the respective closing dates. The acquisitions were accounted for as asset acquisitions and included approximately 31 gross (26.3 net) producing horizontal wells, 109 gross (87.8 net) producing vertical wells and six vertical salt-water disposal wells and related water system infrastructure as well as over 200 gross horizontal drilling locations targeting the Wolfcamp A, Wolfcamp D and Lower Spraberry formations.   Notes Offerings   In February 2022, the Company completed the private placement of $225.0 million aggregate principal amount of its 10.000% Senior Notes due February 2024, netting proceeds of approximately $202.9 million after giving effect to the original issue discount, placement agent compensation and fees and expenses. The proceeds of the offering were used for general corporate purposes.   In November 2022, the Company completed the private placement of $225.0 million aggregate principal amount of its 10.625% Senior Notes due November 2024, netting proceeds of approximately $200.7 million after giving effect to the original issue discount, placement agent compensation and fees and expenses. The proceeds of the offering were used for general corporate purposes.   On December 12, 2022, the Company completed the private placement of $25.0 million aggregate principal amount of its 10.625% Senior Notes due November 2024, netting proceeds of approximately $23.0 million after giving effect to the original issue discount, placement agent compensation and fees and expenses. The proceeds of the offering were used for general corporate purposes.   Impact of Hedging   In accordance with the Credit Agreement and the indentures governing the 10.000% Senior Notes and 10.625% Senior Notes, 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 as of December 31, 2022 are as follows:       2023   Crude Oil Price Swaps – WTI:   First Quarter     Second Quarter     Third Quarter     Fourth Quarter     Total   Volume (MBbls)     900.0       546.0       276.0       —       1,722.0   Price per Bbl   $ 73.67     $ 67.81     $ 72.30     $ —     $ 71.59         2023   Deferred Premium Put Options – WTI:   First Quarter     Second Quarter     Third Quarter     Fourth Quarter     Total   Volume (MBbls)     —       364.0       644.0       920.0       1,928.0   Price per Bbl (Put Price)   $ —     $ 61.05     $ 60.46     $ 55.97     $ 58.43   Price per Bbl (Net of Premium)   $ —     $ 56.05     $ 55.46     $ 50.97     $ 53.43         2024   Deferred Premium Put Options – WTI:   First Quarter     Second Quarter     Third Quarter     Fourth Quarter     Total   Volume (MBbls)     455.0       455.0       460.0       —       1,370.0   Price per Bbl (Put Price)   $ 51.50     $ 51.50     $ 51.50     $ —     $ 51.50   Price per Bbl (Net of Premium)   $ 46.50     $ 46.50     $ 46.50     $ —     $ 46.50     Financial and Operating Performance   The Company's financial and operating performance for the year ended December 31, 2022 included the following highlights:     • Net income for the year ended December 31, 2022 was $236.9 million ($1.93 per diluted share) compared with $55.6 million for the year ended December 31, 2021. The primary components of the $181.3 million increase in net income include:     • a $535.6 million increase in crude oil and natural gas revenues due to a 163% increase in daily sales volumes primarily due to the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions, plus a 30% increase in average realized commodity prices per Boe, excluding the effect of derivatives;   partially offset by:     • a $112.5 million increase in DD&A expense due to a 163% increase in daily sales volumes and a 4% increase in the DD&A rate from $19.20 to $19.89 per Boe, both as a result of increased proved reserves due to the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions;         • a $58.5 million increase in the Company's income tax expense due to the net income experienced in 2022 compared with 2021;   59       • a $48.1 million increase in the Company's interest expense due to the issuance of the 10.000% Senior Notes and 10.625% Senior Notes, increased borrowings under the Credit Agreement and increased amortization of debt issuance costs and discounts;         • a $44.5 million increase in lease operating expenses related primarily to the increased well count and production from the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions;         • a $33.3 million increase in net derivative losses in 2022 compared with 2021 as a result of increased hedging activity required under our debt agreements and the continued increase of crude oil prices in 2022 compared with 2021;         • a $27.7 million increase in production and ad valorem taxes, primarily attributable to the 163% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions combined with 36% higher production and ad valorem taxes on a dollar per Boe basis due to higher overall realized prices of 30%, excluding the effects of derivatives;         • a $26.7 million increase in stock-based compensation expense primarily attributable to restricted stock issued in late 2021 resulting in an entire year of amortization in 2022 compared with a partial year in 2021, additional restricted stock issued in 2022 and other stock option awards that were granted in 2022 which the majority of the stock options vested immediately causing a charge to earnings; and         • a $3.6 million increase in general and administrative costs due primarily to increased salary and bonus expenditures related to a larger workforce and the continued success of the Company.     • During the year ended December 31, 2022, average daily sales volumes totaled 24,485 Boepd, an increase of 163% over 2021, due to the Company's successful horizontal drilling program in the Permian Basin and to a lesser extent, bolt-on acquisitions.         • Weighted average realized crude oil prices per Bbl increased during the year ended December 31, 2022 to $94.61, excluding the effects of derivatives, compared with $70.10 for 2021. Weighted average realized NGL prices per Bbl increased during the year ended December 31, 2022 to $35.67, compared with $35.11 for 2021. Weighted average realized natural gas prices per Mcf increased to $5.36 during the year ended December 31, 2022, compared with $3.88 during 2021.         • Cash provided by operating activities totaled $504.0 million for the year ended December 31, 2022.         • The Company increased its borrowing capacity under the Credit Agreement to $525.0 million with $270.0 million drawn as of December 31, 2022. In addition, the Company raised $202.9 million, net of discounts and issuance costs, in February 2022 when it issued the 10.000% Senior Notes and another $223.7 million, net of discounts and issuance costs, in November and December 2022 when it issued the 10.625% Senior Notes. The Company also raised $85.0 million of capital in September 2022 with the issuance of 3,933,376 shares of common stock in a private placement. This capital gave the Company flexibility to increase its development drilling program to six rigs in mid-2022. During the year, the Company placed 92 gross (78.2 net) horizontal wells on production, drilled and completed 4 gross (4.0 net) salt-water disposal wells and completed $527.3 million in acquisitions of both producing properties and a significant amount of bolt-on undeveloped acreage increasing its drilling inventory. As of December 31, 2022, the Company was also in the process of drilling 11 gross (10.7 net) horizontal producers and had 54 gross (46.8 net) horizontal producers either waiting on completion or in various stages of completion operations.   Operations and Drilling Highlights   Average daily crude oil, NGL and natural gas sales volumes are as follows:       Year Ended December 31, 2022   Crude Oil (Bbls)     20,718   NGL (Bbls)     2,249   Natural Gas (Mcf)     9,105   Total (Boe)     24,485     The Company's liquids production was 94% of total production on a Boe basis for the year ended December 31, 2022.   60     Costs incurred are as follows (in thousands):       Year Ended December 31, 2022   Unproved property acquisition costs   $ 174,554   Proved acquisition costs     352,791   Total acquisitions     527,345   Development costs     391,298   Exploration costs     655,433   Total finding and development costs     1,574,076   Asset retirement obligations     2,879   Total costs incurred   $ 1,576,955     Development/service and exploration/extension drilling activity is as follows:       Year Ended December 31, 2022       Development/ Service     Exploration/ Extension   Beginning wells in progress     6       22   Well spud     30       103   Successful wells     (33 )     (63 ) Ending wells in progress     3       62     During the year ended December 31, 2022, the Company successfully drilled ninety-six (96) wells, of which seventy-nine (79) horizontal producers plus three (3) salt-water disposal wells were located in Flat Top and thirteen (13) horizontal producers plus one (1) salt-water disposal well were located in Signal Peak. Also, we had an additional sixty-five (65) wells in progress as of December 31, 2022. At Flat Top, we had six (6) horizontal producers being drilled and forty-one (41) horizontal producers either waiting on completion or in various stages of completion. At Signal Peak, we had five (5) horizontal producers being drilled and thirteen (13) horizontal producers either waiting on completion or in various stages of completion operations.   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, 2021 filed with the SEC on March 7, 2022 for a discussion of the Company’s 2021 results of operations compared with the Company’s 2020 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, 2022, 2021 and 2020, revenues from our assets were derived approximately 95%, 96% and 98%, respectively, from crude oil sales and 5%, 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, 2022, sales to the Company’s largest purchaser accounted for approximately 88% of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.   The Company’s revenues are presented net of certain gathering, transportation and processing expenses incurred to deliver production of its assets’ crude oil, NGL and natural gas to the market. Cost levels of these expenses can vary based on the volume of crude oil, NGL and natural gas produced as well as the cost of commodity processing. Crude oil, NGL and natural gas prices are inherently volatile and are influenced by many factors outside the Company’s control. To reduce the impact of fluctuations in crude oil, NGL and natural gas prices on revenues, the Company may periodically enter into derivative contracts with respect to a portion of its estimated crude oil, NGL and natural gas production through various transactions that fix or set a floor price for future prices received.   61     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:     ● Lease Operating Expenses.  Lease operating expenses (“LOE”) 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.   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.     ● 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.         ● Depletion –  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/extension 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.         ● General and Administrative Expenses.  General and administrative expenses (“G&A”) 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.   62     Results of Operations   Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.     Crude Oil, NGL and natural gas revenues.   The Company’s revenues are derived from the sales of crude oil, NGL and natural gas production. Increases or decreases in the Company’s revenues, profitability and future production are highly dependent on commodity prices. Prices are market driven and future prices will fluctuate due to supply and demand factors, availability of transportation, seasonality, geopolitical developments and economic factors, among other items.   Crude oil, NGL and natural gas revenues are as follows (in thousands):       Year Ended December 31,               2022     2021     Change   Crude oil, NGL and natural gas revenues   $ 755,686     $ 220,124     $ 535,562     Average daily sales volumes are as follows:       Year Ended December 31,               2022     2021     % Change   Crude Oil (Bbls)     20,718       8,225       152 % NGL (Bbls)     2,249       613       267 % Natural Gas (Mcf)     9,105       2,795       226 % Total (Boe)     24,485       9,304       163 %   The increase in average daily Boe sales volumes for the year ended December 31, 2022, compared with 2021 was due to the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions. It is impracticable to determine the significance from bolt-on acquisitions as the Company previously owned various non-operated interests in the majority of the properties acquired as well as the fact that drilling and completion operations were ongoing on the assets at the time of closing.  However, the majority of the increase shown above is from the Company’s successful drilling program including on the undeveloped assets acquired.    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:       Year Ended December 31,               2022     2021     % Change   Crude oil per Bbl   $ 94.61     $ 70.10       35 % NGL per Bbl   $ 35.67     $ 35.11       2 % Natural gas per Mcf   $ 5.36     $ 3.88       38 % Total per Boe   $ 84.56     $ 64.82       30 %   The increase in prices for crude oil, NGL and natural gas for the year ended December 31, 2022, compared with 2021 was due to a higher commodity price environment.   Crude oil and natural gas production costs.   Crude oil and natural gas production costs are as follows (in thousands):       Year Ended December 31,               2022     2021     Change   Crude oil and natural gas production costs   $ 69,599     $ 25,053     $ 44,546     63     Crude oil and natural gas production costs per Boe are as follows:       Year Ended December 31,               2022     2021     % Change   Lease operating expense   $ 7.49     $ 7.28       3 % Workover costs     0.30       0.10       200 %     $ 7.79     $ 7.38       6 %   Lease operating expense per Boe for 2022 increased slightly compared with 2021. This is largely due to increased lease operating expense per Boe of $8.62 during the first quarter of 2022 due in part to the significant number of rental generators required to power our field operations. When our power distribution infrastructure and substation were energized beginning in May 2022, we reduced the number of rental generators in the field throughout the remainder of the year. By the fourth quarter of 2022, our lease operating expense per Boe was $6.86 and we anticipate this number to continue to decline as we extend the power infrastructure field wide and energize our solar farm project. The increase in workover costs year over year can be attributed to the wells getting older and beginning to need more repair and maintenance from time to time.   Production and ad valorem taxes.   Production and ad valorem taxes are as follows (in thousands):       Year Ended December 31,               2022     2021     Change   Production and ad valorem taxes   $ 38,440     $ 10,746     $ 27,694     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:       Year Ended December 31,               2022     2021     % Change   Production taxes per Boe   $ 4.04     $ 3.09       31 % Ad valorem taxes per Boe   $ 0.26     $ 0.07       271 %     $ 4.30     $ 3.16       36 %   Production taxes per Boe for the year ended December 31, 2022, compared with 2021, increased primarily due to the 30% overall increase in commodity prices. The increase in ad valorem taxes per Boe for the year ended December 31, 2022, compared with 2021, was primarily due to the increase in commodity prices in 2021 and a significant number of wells that came on production during 2021 that had no ad valorem tax in 2021. 2022 was the first year these wells were assessed ad valorem taxes. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.   Exploration and abandonments expense.   Exploration and abandonment expense details are as follows (in thousands):       Year Ended December 31,               2022     2021     Change   Geologic and geophysical personnel costs   $ 1,003     $ 807     $ 196   Geologic and geophysical data costs     146       487       (341 ) Abandoned leasehold costs     —       235       (235 ) Plugging and abandonment expense     —       20       (20 ) Exploration and abandonments expense   $ 1,149     $ 1,549     $ (400 )   The decrease in exploration and abandonment expenses is primarily the result of a reduction in the purchase of geologic and geophysical data and no abandoned leasehold costs in 2022 compared with $235,000 in 2021 partially offset by increased geologic and geophysical personnel costs.   64     Depletion, depreciation and amortization expense.   DD&A expense is as follows (in thousands):       Year Ended December 31,               2022     2021     Change   DD&A expense   $ 177,742     $ 65,201     $ 112,541     DD&A expense per Boe is as follows:       Year Ended December 31,               2022     2021     % Change   DD&A expense per Boe   $ 19.89     $ 19.20       4 %   The increase in DD&A expense is primarily due to the increased production associated with our successful horizontal drilling program and bolt-on acquisitions.  The increase in DD&A expense per Boe can be primarily attributed to inflationary pressures and acquisitions, including new leasehold.    General and administrative expense.   General and administrative expense and stock-based compensation expense are as follows (in thousands):       Year Ended December 31,               2022     2021     Change   General and administrative expense   $ 12,470     $ 8,885     $ 3,585   Stock-based compensation expense   $ 33,352     $ 6,676     $ 26,676     General and administrative expense per Boe is as follows:         Year Ended December 31,               2022     2021     % Change   General and administrative expense per Boe   $ 1.40     $ 2.62       (47 )%   The increase in general and administrative expense for the year ended December 31, 2022 is primarily as a result of increased employee count, salary increases and annual bonuses.   The increase in noncash stock-based compensation expense is due to restricted stock issued in late 2021 resulting in an entire year of amortization in 2022 compared with a partial year in 2021, additional restricted stock issued in 2022 and other stock option awards that were granted in 2022 which the majority of the stock options vested immediately causing a charge to earnings.   Interest expense.   Interest expense is as follows (in thousands):       Year Ended December 31,               2022     2021     Change   Interest expense on 10.000% Senior Notes   $ 19,625     $ —     $ 19,625   Interest expense on Credit Agreement     14,022       1,986       12,036   Interest expense on 10.625% Senior Notes     3,593       —       3,593   Amortization of discounts     7,735       498       7,237   Amortization of debt issuance costs     5,635       —       5,635       $ 50,610     $ 2,484     $ 48,126     The increase in interest expense can be attributed to increased borrowings under the Credit Agreement and the issuance of $225.0 million of the Company’s 10.000% Senior Notes in February 2022 and $250.0 million of the Company’s 10.625% Senior Notes in November and December 2022.   Derivative loss, net.   Derivative loss, net is as follows (in thousands):       Year Ended December 31,               2022     2021     Change   Noncash derivative loss, net   $ (1,909 )   $ (15,467 )   $ 13,558   Cash payments on settled derivative instruments, net     (58,096 )     (11,267 )     (46,829 ) Derivative loss, net   $ (60,005 )   $ (26,734 )   $ (33,271 )   65     The Company primarily utilizes commodity swap contracts and deferred premium puts 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 indentures governing the Company’s 10.000% Senior Notes and 10.625% Senior Notes require the Company to hedge certain quantities of its projected crude oil production which in the case of the Credit Agreement, if its ratio of debt to EBITDAX is greater than a certain ratio. 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 and natural gas derivative swap contracts.   Income tax expense.         Year Ended December 31,               2022     2021     Change   Income tax expense (in thousands)   $ 75,361     $ 16,904     $ 58,457   Effective income tax rate     24.1 %     16.7 %     7.4 %   The change in income tax expense during the year ended December 31, 2022, compared with 2021, was due to increased net income during the year ended December 31, 2022 compared with 2021. The effective income tax rate differs from the statutory rate primarily due to a revision on the deferred tax asset related to certain stock-based compensation and permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information.   Liquidity and Capital Resources   Liquidity . The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, including cash proceeds from our recent $225.0 million and $25.0 million offerings of 10.625% Senior Notes in November 2022 and December 2022, respectively, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Credit Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets.   The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of contractual obligations 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 its sources of funding will be adequate to fund its 2023 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.   2023 capital budget . The Company’s capital budget for 2023 is expected to be in the range of approximately $1.1 to $1.2 billion for drilling, completion, facilities and equipping crude oil wells plus $50 to $60 million for field infrastructure buildout and other costs. The 2023 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, and, depending on market circumstances, potential future debt or equity offerings. The Company’s capital expenditures for the year ended December 31, 2022 were $1.0 billion, excluding acquisitions.   The budget above assumes that the Company will operate an average of four to five (4-5) drilling rigs and an average of two to three (2-3) frac fleets in the Permian Basin during 2023. 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, 2022, the Company had $745.0 million in outstanding borrowings and approximately $252.6 million available to borrow under the Credit Agreement. The Company also had unrestricted cash on hand of $30.5 million as of December 31, 2022.     Cash flows from operating, investing and financing activities are summarized below (in thousands).       Year Ended December 31,               2022     2021     Change   Net cash provided by operating activities   $ 504,014     $ 147,015     $ 356,999   Net cash used in investing activities   $ (1,182,408 )   $ (250,371 )   $ (932,037 ) Net cash provided by financing activities   $ 674,029     $ 118,673     $ 555,356     66     Operating activities. The increase in net cash flow provided by operating activities for the year ended December 31, 2022, compared with 2021, 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 and to a lesser extent, bolt-on acquisitions, coupled with an increase in accounts payable and accrued liabilities primarily as a result of increased drilling and completion activities, 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 2022 versus December 2021 and an increase in the amount of prepaid expenses, inventory and other noncurrent assets related to the Company’s increased drilling program.   Investing activities. The increase in net cash used in investing activities for the year ended December 31, 2022, compared with 2021, was primarily due to increases in additions to crude oil and natural gas properties as the Company significantly increased its drilling and completion program in 2022 compared to 2021. In addition, the Company spent $262.4 million in acquisitions of proved and unproved crude oil and natural gas properties in 2022 compared with $54.0 million in 2021.   Financing activities. The Company’s significant financing activities are as follows:     • 2022: The Company (i) borrowed $925.0 million and repaid $755.0 million for a net increase in long-term debt related to the Credit Agreement of $170.0 million, (ii) issued an aggregate principal amount of $225.0 million ($210.2 million net of discounts) of its 10.000% Senior Notes and an aggregate principal amount of $250.0 million ($230.0 million net of discounts) of its 10.625% Senior Notes, (iii) received $85.0 million from the issuance of 3,933,376 shares of common stock in a private placement, (iv) received $7.9 million in proceeds from the exercises of warrants and stock options of the Company, (v) paid dividends to its common stockholders of $10.4 million and dividend equivalents to certain holders of vested stock options of $1.2 million and (vi) spent $17.1 million on debt issuance costs related to amendments to increase its borrowing capacity under the Credit Agreement and the issuance of the 10.000% Senior Notes and 10.625% Senior Notes.         • 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 Credit Agreement, (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 dividend equivalents to certain holders of vested stock options of $1.0 million and (v) spent $2.2 million on debt issuance costs related to amendments to increase its borrowing capacity under the Credit Agreement.   Interest Rate Risk.   We are exposed to market risk due to the floating interest rate associated with any outstanding balance on the Credit Agreement. As of December 31, 2022, we had a $270.0 million outstanding balance on the Credit Agreement. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of the Credit Agreement for a period up to three months. To the extent that the interest rate is fixed, interest rate changes will affect the Credit Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the 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. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate 10.000% Senior Notes and 10.625% Senior Notes 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 ongoing armed conflict between Russia and Ukraine. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 2022 sales volumes and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the year ended December 31, 2022 would have increased (decreased) the Company’s revenues by approximately $7.9 million and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2022 would have increased (decreased) the Company’s revenues by approximately $332,000.   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, 2022, 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 $5.0 million.   67     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 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, derivative gains and losses net of settlements, 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 Credit Agreement based on EBITDAX ratios and debt covenants under the indentures governing the 10.000% Senior Notes and 10.625% Senior Notes based on consolidated leverage indebtedness to forward 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 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 (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.  The Credit Agreement provides a material source of liquidity for us.  Under the terms of our Credit Agreement, the 10.000% Senior Notes and the 10.625% Senior Notes, 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 the Credit Agreement and would therefore materially limit a significant source of our liquidity.  In addition, if we are in default under the Credit Agreement and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding 10.000% Senior Notes and 10.625% Senior Notes, 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):       Year Ended December 31,       2022     2021   Net income   $ 236,854     $ 55,559   Interest expense     50,610       2,484   Interest and other income     (266 )     (1 ) Income tax expense     75,361       16,904   Depletion, depreciation and amortization     177,742       65,201   Accretion of discount     370       167   Exploration and abandonment expense     1,149       1,549   Stock-based compensation     33,352       6,676   Derivative related noncash activity     1,909       15,467   Other expense     —       167   EBITDAX   $ 577,081     $ 164,173     Critical Accounting Estimates   The Company prepares its consolidated financial statements for inclusion in this Annual Report in accordance with GAAP. See Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information. The following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP.   Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for crude oil and natural gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for crude oil and natural gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of DD&A expense.   68     Proved reserve estimates. Estimates of the Company’s proved reserves included in this Annual Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:     ● the quality and quantity of available data;   ● the interpretation of that data;   ● the accuracy of various mandated economic assumptions; and   ● the judgment of the persons preparing the estimate.   The Company’s proved reserve information included in this Annual Report as of December 31, 2022, 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, 2022 and 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 9,211 MBoe, 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, 2022 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2022 standardized measure on a twelve-month average of commodity prices on the first day of each month in 2022 and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Items 1 and 2. Business and Properties” and Unaudited Supplementary Data included in “Item 8. Financial Statements and Supplementary Data” for additional information.   The Company’s estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which the Company records DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company’s assessment of its proved properties for impairment.   Impairment of proved crude oil and natural gas properties. The Company 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, 2022, the Company carried unproved property costs of $114.7 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:     ● The well has found a sufficient quantity of reserves to justify its completion as a producing well; and   ● The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.   69     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 2022, the Company did not have any unrecognized tax benefits. See Note 13 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.   Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments of the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note 10 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.   Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, and (ii) the closing stock price on the date of grant for the fair value of unrestricted and restricted stock awards. See Note 9 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.   Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities the Company measures and records at fair value on a recurring basis include commodity derivative contracts and interest rate contracts. Other assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. The assets and liabilities the Company measures and records at fair value on a nonrecurring basis include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities may require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.   Recent Accounting Pronouncements   The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”   Off-Balance Sheet Arrangements   Commitments and Contingencies are discussed in Note 10 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”   70