HPK

The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and related notes. This discussion contains certain “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. These forward-looking statements involve risks and uncertainties and actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read “Cautionary Statement Concerning Forward‑Looking Statements.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law. Overview HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019, is an independent crude oil and natural gas exploration and production company that explores for, develops and produces crude oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin. The Company’s assets are located primarily in Howard and Borden Counties, Texas, and to a lesser extent Scurry and Mitchell Counties, which lie within the northeastern part of the crude oil-rich Midland Basin. As of June 30, 2026, the assets consisted of two highly contiguous leasehold positions of approximately 153,627 gross (139,833 net) acres, approximately 74% of which were held by production, with an average working interest of 91%. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern portion of Howard County. We operate approximately 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 six months ended June 30, 2026, approximately 83% and 17% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of June 30, 2026, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew and expects to average one (1) drilling rig and less than one (1) frac crew during the remainder of 2026 under our current development plan, depending on certain market conditions. Transactions and Recent Developments Debt amendments and actions taken to bolster covenant compliance. In August 2025, the Company entered into the First Term Loan Amendment and the Second Facility Amendment which amended the Term Loan Credit Agreement and the Senior Credit Facility Agreement whereby, among other things, (i) the maturity date was extended two years to September 2028, (ii) the Term Loan Credit Agreement was upsized to $1.2 billion, providing additional liquidity, and (iii) the Term Loan Credit Agreement quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026. Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things (i) the Company has been required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company has been required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations has been increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the Company’s reserve report as of December 31, 2025 and (iv) the Company is prohibited from making quarterly dividends on its common stock until September 30, 2026. In June 2026, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company entered into the Third Term Loan Amendment and the Fourth Facility Amendment whereby, the Company will be required to maintain a total net leverage ratio of not greater than 2.25 to 1.00 for the second quarter of 2026, representing a 0.25x increase in the required ratio level for such quarter. For the third quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels provided for such quarters in the Second Term Loan Amendment and the Third Facility Amendment. It is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the third quarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. Any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder. Commodity Prices. Prices for crude oil, NGL and natural gas are determined primarily by market conditions. Geopolitical global conflicts, tariffs or other trade barriers and any resulting trade tensions, regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, extreme weather conditions and other substantially variable factors influence market conditions for these products. For example, in the last quarter, the conflict in Iran caused the global crude oil market to shift from a supply-demand surplus to a deficit, materially decreasing crude oil and refined products available to the markets, and significantly increasing benchmark crude oil prices. These factors are beyond our control and are difficult to predict. OPEC and its non-OPEC allies, known collectively as OPEC+, continue to meet regularly to evaluate the state of global crude oil supply, demand and inventory levels and can heavily influence volatility in crude oil prices. During the three months ended June 30, 2026 and 2025, weighted average WTI prices averaged $93.29 and $63.75 per Bbl, respectively, and weighted average Henry Hub prices averaged $2.90 and $3.44 per MMBtu, respectively. Acquisitions. During the six months ended June 30, 2026, the Company incurred a total of $2.6 million in acquisition costs related to lease extensions and to acquire additional crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage to its Flat Top and Signal Peak operating areas. 27 Outlook In response to the growing global crude oil supply constraints and the improved commodity pricing environment that began in March of 2026 that we consider temporary, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a one (1) drilling rig program for 2026 depending on certain market conditions. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. If the Company is unable to maintain compliance with its financial covenants or obtain further amendments or waivers from its lenders, it may be required to reduce its capital expenditures, which could adversely impact its ability to develop its acreage, maintain its leasehold positions and grow its production. Despite continuing impacts of the factors listed above and future uncertainty, we are focused on maintaining our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets. Strategic Alternatives On January 23, 2023, the Company announced the intention of its Board to initiate a process to evaluate certain strategic alternatives to maximize shareholder value, including a potential sale of the Company. Evercore Group L.L.C. has been retained as a financial advisor with respect to this ongoing strategic alternatives process. The Company has not set a timetable for the conclusion of this review, nor has it made any decisions related to any further actions or potential strategic alternatives at this time. There can be no assurance that the review will progress beyond this exploratory phase or result in any transaction or other strategic change or outcome. The Company does not intend to comment further regarding the strategic alternatives process unless and until our Board has approved a specific course of action or we have otherwise determined that further disclosure is appropriate or required by law. Financial and Operating Performance The Company's financial and operating performance for the three months ended June 30, 2026 included the highlights described below and comparative discussion of related drivers for the three months ended June 30, 2025: • Net income was $82.3 million ($0.59 per diluted share) for the three months ended June 30, 2026 compared with net income of $26.2 million ($0.19 per diluted share) for the three months ended June 30, 2025. The primary components of the $56.1 million increase in net income include: • a $55.9 million increase in crude oil, NGL and natural gas revenues due to a 35% increase in average realized commodity prices per Boe, excluding the effects of derivatives partially offset by a 7% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased development activity and natural decline; • a $27.0 million increase in the Company’s derivative instruments gain as a result of its crude oil and natural gas commodity contracts entered into and the change in crude oil and natural gas prices thereafter; and • a $1.1 million decrease in the Company’s crude oil and natural gas production costs primarily as a result of decreased communication expenses and lower chemical and treating costs related to third party midstream expansions and debottlenecking; partially offset by: • a $12.2 million increase in DD&A expense primarily due to a 20% increase in the DD&A rate from $22.87 to $27.52 per Boe as a result of a decrease in proved reserves at the end of 2025 partially offset by a 7% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased development activity and natural decline; • A $8.8 million increase in the Company’s income tax expense primarily due to an increase in income before income taxes; • a $3.3 million increase in the Company’s exploration and abandonment expenses primarily due to increased abandoned leasehold costs and plugging and abandonment expenses; • a $1.3 million increase in the Company’s general and administrative expenses primarily attributable to cash compensation to our board of directors which was implemented at the annual meeting in June 2026 and increased legal and audit expenditures due to the growth of the Company; • a $1.2 million increase in gathering, processing and transportation expenses related to the Company’s natural gas production as a result of connecting more natural gas to processing facilities that were not previously connected, thereby enhancing the Company’s ability to maximize returns from its wells by increasing sales volumes; and • a $863,000 increase in the Company’s production and ad valorem tax expense primarily due to the aforementioned increase in operating revenues. • During the three months ended June 30, 2026, average daily sales volumes totaled 45,285 Boepd, compared with 48,649 Boepd during the same period in 2025, a decrease of 7%, primarily due to lower crude oil volumes as a result of decreased development activity and natural decline. • Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, increased during the three months ended June 30, 2026 to $98.82, compared with $63.74 for the same period in 2025. Weighted average NGL prices per Bbl increased during the three months ended June 30, 2026 to $24.14, compared with $20.34 for the same period in 2025. Weighted average natural gas prices per Mcf decreased to negative $1.50 during the three months ended June 30, 2026, compared with positive $1.50 during the same period in 2025. • Cash provided by operating activities totaled $126.3 million for the three months ended June 30, 2026, compared with $141.2 million for the three months ended June 30, 2025. 28 Derivative Financial Instruments Crude oil derivative financial instrument exposure. As of June 30, 2026 and factoring in derivative instruments entered into subsequent to quarter end, the Company was party to the following open crude oil derivative financial instruments. Settlement Month Settlement Year Type of Contract Bbls Per Day Index Swap Price per Bbl Costless Collar Floor Price per Bbl Costless Collar Ceiling Price per Bbl Crude Oil: Jul – Sep 2026 Costless Collar 13,000 WTI Cushing $ — $ 61.38 $ 69.39 Jul – Sep 2026 Swap 5,000 WTI Cushing $ 63.45 $ — $ — Jul – Sep 2026 Roll Swap 26,011 NYMEX WTI Roll $ 4.30 $ — Jul – Sep 2026 Basis Swap 23,000 Argus WTI Midland $ 1.37 $ — $ — Oct – Dec 2026 Costless Collar 10,800 WTI Cushing $ — $ 61.67 $ 68.52 Oct – Dec 2026 Swap 5,000 WTI Cushing $ 63.45 $ — $ — Oct – Dec 2026 Roll Swap 25,000 NYMEX WTI Roll $ 4.23 $ — $ — Oct – Dec 2026 Basis Swap 23,000 Argus WTI Midland $ 1.37 $ — $ — Jan – Mar 2027 Costless Collar 8,900 WTI Cushing $ — $ 59.78 $ 65.24 Jan – Mar 2027 Swap 4,400 WTI Cushing $ 62.14 $ — $ — Jan – Mar 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Apr – Jun 2027 Costless Collar 4,000 WTI Cushing $ — $ 52.00 $ 62.85 Apr – Jun 2027 Swap 6,470 WTI Cushing $ 59.61 $ — $ — Apr – Jun 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Jul – Sep 2027 Swap 8,950 WTI Cushing $ 61.46 $ — $ — Jul – Sep 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Oct – Dec 2027 Swap 7,500 WTI Cushing $ 70.42 $ — $ — Oct – Dec 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Natural gas derivative financial instrument exposure. As of June 30, 2026 and factoring in derivative financial instruments entered into subsequent to quarter end, the Company was party to the following open natural gas derivative financial instruments. Settlement Month Settlement Year Type of Contract MMBtu Per Day Index Price per MMBtu Natural Gas: Jul – Sep 2026 Swap 30,000 HH $ 4.300 Oct – Dec 2026 Swap 30,000 HH $ 4.300 Oct – Dec 2026 Basis Swap 25,000 WAHA $ (1.455 ) Jan – Mar 2027 Swap 19,667 HH $ 4.300 Jan – Mar 2027 Basis Swap 25,000 WAHA $ (1.487 ) Apr – Jun 2027 Basis Swap 25,000 WAHA $ (1.487 ) Jul – Sep 2027 Basis Swap 25,000 WAHA $ (1.487 ) Oct – Dec 2027 Basis Swap 25,000 WAHA $ (1.487 ) The estimated fair value of the outstanding open derivative financial instruments as of June 30, 2026 was a net asset of $1.6 million which is included in current assets and current and noncurrent liabilities on the Company’s condensed consolidated balance sheet as of June 30, 2026. During the six months ended June 30, 2026, the Company recognized a net derivative loss of $103.6 million, including a $31.4 million mark-to-market loss and $72.2 million in net monthly settlement payments. 29 Operations and Drilling Highlights Average daily crude oil, NGL and natural gas sales volumes are as follows: Six Months Ended June 30, 2026 Crude Oil (Bbls) 29,884 NGL (Bbls) 7,919 Natural Gas (Mcf) 45,921 Total (Boe) 45,456 The Company’s liquids production was 83% of total production on a Boe basis for the six months ended June 30, 2026. Costs incurred are as follows (in thousands): Six Months Ended June 30, 2026 Unproved property acquisition costs $ 2,558 Proved acquisition costs — Total acquisitions 2,558 Development costs 126,484 Exploration costs 59,458 Total finding and development costs 188,500 Asset retirement obligations 549 Total costs incurred $ 189,049 The following table sets forth the total number of horizontal producing wells drilled and completed during the six months ended June 30, 2026: Drilled Completed Gross Net Gross Net Flat Top area 10 9.6 13 12.6 Signal Peak area 7 7.0 7 7.0 Total 17 16.6 20 19.6 As of June 30, 2026, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew. The continued conflict in Iran, commodity-specific tariffs and the possibility of trade wars, the ongoing war between Russia and Ukraine and other conflicts in the Middle East and the production cuts and reversals thereof announced by OPEC+ are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility with its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed regularly. 30 During the six months ended June 30, 2026, the Company successfully completed and placed on production twenty (20) gross (19.6 net) horizontal wells. As of June 30, 2026, the Company had sixteen (16) gross (15.6 net) horizontal wells that had been drilled and were in various stages of completion. In addition, as of June 30, 2026, the Company was in the process of drilling five (5) gross (4.8 net) horizontal wells. Results of Operations Three and Six Months Ended June 30, 2026 Crude Oil, NGL and natural gas revenues. Average daily sales volumes are as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Crude Oil (Bbls) 28,952 33,913 (15 )% 29,884 36,056 (17 )% NGL (Bbls) 8,429 7,462 13 % 7,919 7,592 4 % Natural Gas (Mcf) 47,423 43,642 9 % 45,921 43,371 6 % Total (Boe) 45,285 48,649 (7 )% 45,456 50,876 (11 )% The decrease in average daily Boe sales volumes for the three and six months ended June 30, 2026, compared with the same periods in 2025 was primarily due to lower crude oil sales volumes as a result of reduced development activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking. The crude oil, NGL and natural gas prices that the Company reports are based on the market prices received for each commodity. The weighted average realized prices, excluding the effects of derivatives, are as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Crude Oil per Bbl $ 98.82 $ 63.74 55 % $ 84.95 $ 67.90 25 % NGL per Bbl $ 24.14 $ 20.34 19 % $ 20.92 $ 22.30 (6 )% Natural Gas per Mcf $ (1.50 ) $ 1.50 (200 )% $ (0.14 ) $ 1.91 (107 )% Total per Boe $ 66.11 $ 48.90 35 % $ 59.35 $ 53.08 12 % Revenue Variance Analysis. The following table illustrates the variance in revenues attributable to prices versus volumes (in thousands except prices and percentages): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Total operating revenues $ 272,419 $ 216,472 26 % $ 488,304 $ 488,783 0 % Average daily sales volumes (Boe) 45,285 48,649 (7 )% 45,456 50,876 (11 )% Realized price per Boe $ 66.11 $ 48.90 35 % $ 59.35 $ 53.08 12 % Revenue change from prior period due to prices $ 76,190 35 % $ 57,738 12 % Revenue change from prior period due to volumes (20,238 ) (9 )% (58,224 ) (12 )% Rounding (5 ) 0 % 7 0 % Total change from prior period revenues $ 55,497 $ (479 ) As detailed above, the increase in total operating revenues for the three months ended June 30, 2026 compared to the same period in 2025 is the result of a 35% increase in average realized price per Boe partially offset by a 7% decrease in average daily sales volumes primarily as a result of lower crude oil sales volumes as a result of reduced development activity and natural decline. Also detailed above, the decrease in total operating revenues for the six months ended June 30, 2026 compared to the same period in 2025 is the result of a 11% decrease in average daily sales volumes primarily as a result of lower crude oil sales volumes as a result of reduced development activity and natural decline partially offset by a 12% increase in average realized price per Boe. 31 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): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Crude oil and natural gas production costs $ 32,641 $ 33,726 (3 )% $ 62,165 $ 69,288 (10 )% Crude oil and natural gas production costs per Boe (excluding expense workovers) $ 6.43 $ 6.55 (2 )% $ 6.48 $ 6.58 (2 )% Workover expense $ 1.49 $ 1.06 41 % $ 1.08 $ 0.94 15 % The decrease in crude oil and natural gas production costs for the three and six months ended June 30, 2026 compared to the same periods in 2025 can be attributed primarily to decreased chemical and treating costs related to third party midstream expansions and debottlenecking and communication expenses. Gathering, processing and transportation expenses. Gathering, processing and transportation expenses are as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Gathering, processing and transportation expenses $ 17,234 $ 16,072 7 % $ 34,967 $ 30,935 13 % Gathering, processing and transportation expenses per Boe are as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Gathering, processing and transportation expenses $ 4.18 $ 3.63 15 % $ 4.25 $ 3.36 26 % Gathering, processing and transportation expenses for the three and six months ended June 30, 2026 increased compared to the same periods in 2025. This is primarily related to connecting more natural gas to processing facilities that were not previously connected, thereby enhancing the Company’s ability to maximize returns from its wells by increasing sales volumes. The slightly higher increase in the per Boe amounts can be attributed to the increase in NGL and natural gas as a total component of our product mix when calculating Boe. Production and ad valorem taxes. Production and ad valorem taxes are as follows (in thousands, except percentages): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Production and ad valorem taxes $ 13,254 $ 12,391 7 % $ 25,154 $ 27,543 (9 )% In general, production taxes and ad valorem taxes are directly related to commodity sales volumes and price changes; however, Texas ad valorem taxes are based upon an asset valuation assessed by the state as of January 1 of that particular year based on prior year commodity prices, whereas production taxes are based upon current year sales revenues at current commodity prices. Overall, the increase in production and ad valorem taxes during the three months ended June 30, 2026 compared to the same period in 2025 can be attributed primarily to the aforementioned 26% increase in operating revenues partially offset by lower ad valorem taxes and the decrease in production and ad valorem taxes during the six months ended June 30, 2026 compared to the same period in 2025 can be primarily attributed to lower ad valorem taxes. Production and ad valorem taxes per Boe are as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Production taxes per Boe $ 3.06 $ 2.32 32 % $ 2.77 $ 2.52 10 % Ad valorem taxes per Boe $ 0.16 $ 0.48 (67 )% $ 0.29 $ 0.47 (38 )% The increase in production taxes per Boe for the three and six months ended June 30, 2026, compared with the same periods in 2025 can be attributed primarily to the increased commodity prices and the lower sales volumes thus far in 2026. The change in ad valorem taxes per Boe for the three and six months ended June 30, 2026, compared with the same periods in 2025, was primarily due to the expected decrease in ad valorem taxes expected for 2026. 32 Exploration and abandonments expense. Exploration and abandonment expense details are as follows (in thousands, except percentages): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Abandoned leasehold costs $ 3,702 $ 266 1,292 % $ 3,739 $ 266 1,306 % Unsuccessful exploratory well costs 484 — 100 % 566 — 100 % Geologic and geophysical personnel costs 245 253 (3 )% 530 513 3 % Plugging and abandonment expenses 13 590 (98 )% 349 594 (41 )% Geologic and geophysical data costs — — n/m 2 — 100 % Exploration and abandonments expense $ 4,444 $ 1,109 301 % $ 5,186 $ 1,373 278 % Exploration and abandonment costs increased during the three and six months ended June 30, 2026 primarily due to increased abandoned leasehold costs related primarily to outlying leases that the Company was not successful extending at attractive prices and unsuccessful well costs related to initial costs on a well that the Company elected not to drill partially offset by lower plugging and abandonment expenses. DD&A expense. DD&A expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change DD&A expense $ 113,429 $ 101,226 12 % $ 226,443 $ 210,551 8 % DD&A expense per Boe $ 27.52 $ 22.87 20 % $ 27.52 $ 22.86 20 % The increase in DD&A during the three and six months ended June 30, 2026 is primarily due to an increase in the DD&A rate primarily attributable to decreased proved reserves partially offset by decreased sales volumes. 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): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change General and administrative expense $ 7,004 $ 5,671 24 % $ 12,749 $ 12,016 6 % General and administrative expense per Boe $ 1.70 $ 1.28 33 % $ 1.55 $ 1.30 19 % Stock-based compensation expense $ 868 $ 88 886 % $ 1,733 $ 265 554 % The increase in general and administrative expense in total for the three and six months ended June 30, 2026 compared to the same periods in 2025 is primarily a result of higher cash compensation to independent members of our Board of Directors and increased legal and audit expenses partially offset by decreased wages and benefits primarily related to the retirement of the Company’s former chief executive officer in September 2025. The increase in stock-based compensation expense for the three and six months ended June 30, 2026 compared to the same periods in 2025 is the result of restricted stock issued to certain employees of the Company in January 2026. Interest expense. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Term Loan Credit Agreement $ 34,427 $ 31,715 9 % $ 68,393 $ 64,058 7 % Senior Credit Facility Agreement 197 187 5 % 385 372 3 % Amortization of debt issuance costs 1,354 2,057 (34 )% 2,238 4,091 (45 )% Amortization of discount — 2,453 (100 )% — 4,879 (100 )% $ 35,978 $ 36,412 (1 )% $ 71,016 $ 73,400 (3 )% 33 The decrease in interest expense can be attributed to a decrease in amortization of discounts and debt issuance costs related to the refinancing of the Company’s debt in August 2025 partially offset by an increased outstanding debt balance in 2026 compared to 2025. Loss on derivative instruments, net. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Noncash gain (loss) on derivative instruments, net $ 108,154 $ 19,034 468 % $ (31,400 ) $ 14,178 (321 )% Cash (payments) receipts on settlement derivatives, net (54,728 ) 7,412 (838 )% (72,201 ) 4,341 (1,763 )% Gain (loss) on derivative instruments, net $ 53,426 $ 26,446 102 % $ (103,601 ) $ 18,519 (659 )% The Company primarily utilizes commodity swap contracts, costless collars, roll swaps and basis swaps to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budget and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require 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 gains and losses and cash settlements relate to crude oil derivative swap contracts, costless collars, roll swaps and basis swaps and natural gas derivative swap contracts and basis swaps. Other expense. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Financial advisor fee $ 3,000 $ — 100 % $ 3,000 $ — 100 % Debt refinancing costs — 2,489 (100 )% — 2,489 (100 )% Other — — — 50 — 100 % $ 3,000 $ 2,489 21 % $ 3,050 $ 2,489 23 % During the three and six months ended June 30, 2026, the Company expensed the financial advisory fee paid to Texas Capital Securities related to its ongoing strategic alternatives process as the agreement was terminated. During the three and six months ended June 30, 2025, the Company incurred approximately $2.5 million in rating agency fees, legal and accounting professional fees and other costs related to a proposed refinancing of its existing debt obligations. The Company ultimately elected to not close that specific refinancing transaction. Accordingly, these costs were expensed as incurred. Provision for income taxes. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 % Change 2026 2025 % Change Provision for income taxes $ 16,448 $ 7,663 115 % $ (11,203 ) $ 17,602 (164 )% Effective income tax rate 16.7 % 22.6 % (26 )% 19.9 % 22.0 % (10 )% The change in provision for income taxes during the three and six months ended June 30, 2026, compared with the same periods in 2025, was primarily due to the change in income (loss) before income taxes mainly due to the significant increase in derivative gains and losses as well as the reversal of an annualized loss limitation during the three months ended June 30, 2026 that was recognized during the three months ended March 31, 2026 which was reversed primarily due to the large increase in commodity prices that resulted in an increase in income before income taxes. The effective income tax rate differs from the statutory rate primarily due to Texas state margin taxes and other permanent differences between GAAP income and taxable income. See Note 13 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” for additional information. 34 Liquidity and Capital Resources Liquidity. The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Senior Credit Facility Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) sales of nonstrategic assets. The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of other contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortizations of its indebtedness. 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 2026 planned capital expenditures and provide adequate liquidity to fund other needs, however this may be subject to significant uncertainty due to changes in crude oil, NGL and natural gas pricing and potential covenant compliance issues under its debt instruments described below and no assurance can be given that such funding sources will be adequate to meet the Company’s future needs. As of June 30, 2026, the Company was in compliance with the financial covenants under its Term Loan Credit Agreement and Senior Credit Facility Agreement, as amended. In particular, we recently entered into credit facility amendments described below to ensure our continued compliance with covenants in our debt instruments, but it is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the third quarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. If the Company is unable to maintain compliance with its financial covenants or successfully implement the measures described above, its liquidity and capital resources would be materially and adversely affected. Specifically, the Company's borrowing availability under its Senior Credit Facility Agreement, which was approximately $92.1 million as of June 30, 2026, could be reduced or eliminated, and the Company may be unable to access additional debt or equity financing on acceptable terms or at all. In addition, any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder. If such amounts were accelerated and became immediately due and payable, the Company does not expect it would have sufficient liquidity to repay such indebtedness and would likely need to pursue a restructuring, refinancing or other strategic alternatives, which may not be available on acceptable terms or at all. Debt Refinancing and Recent Amendments. In September 2023, we completed a refinancing of our long-term debt in its entirety by entering into an agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement was set to mature on September 30, 2026 prior to the amendments discussed below. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00% of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries. The Term Loan Credit Agreement also contained certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter prior to the amendments discussed below. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio. The Term Loan Credit Agreement contained customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments. Simultaneously with the closing of the Term Loan Credit Agreement, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023. The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof. 35 On November 1, 2023, but included in part of the refinancing of the Company’s overall long-term debt, the Company entered into a Senior Credit Facility Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $100.0 million and effective March 29, 2024 pursuant to the First Facility Amendment, current commitments of $100.0 million and customary debt issuance costs which totaled approximately $1.1 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Senior Credit Facility Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries. August 2025 Amendments In August 2025, the Company entered into the First Term Loan Amendment and the Second Facility Amendment which amended the Term Loan Credit Agreement and the Senior Credit Facility Agreement whereby, among other things, (i) the maturity date was extended two years to September 2028, (ii) the Term Loan Credit Agreement was upsized to $1.2 billion, providing additional liquidity, and (iii) the Term Loan Credit Agreement quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026. February 2026 Amendments Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things, (i) the Company has been required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company has been required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations has been increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the Company’s reserve report as of December 31, 2025 and (iv) the Company is prohibited from making quarterly dividends on its common stock until September 30, 2026. June 2026 Amendments In June 2026, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company entered into the Third Term Loan Amendment and the Fourth Facility Amendment whereby, the Company will be required to maintain a total net leverage ratio of not greater than 2.25 to 1.00 for the second quarter of 2026, representing a 0.25x increase in the required ratio level for such quarter. For the third quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to these amendments. Common Stock Issuance. Pursuant to a sales agreement with its agents entered into on May 6, 2026, the Company may sell shares of its common stock at the market price from time to time up to a maximum aggregate of $150 million. The Company has not issued any shares of its common stock under an at the market offering thus far. Unless otherwise specified in any prospectus supplement, the Company intends to use the net proceeds from the sale of its securities offered under these prospectuses for working capital and general corporate purposes including, but not limited to, capital expenditures, repayment of indebtedness, potential acquisitions and other business opportunities. Pending any specific application, the Company may initially invest funds in short-term marketable securities or apply them to the reduction of indebtedness. 2026 capital budget. The Company’s capital budget for 2026 is expected to be in the range of approximately $255 to $285 million for operated and non-operated drilling, completion, facilities and equipping crude oil wells, field infrastructure buildout and other costs, excluding acquisitions. The 2026 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses and general and administrative expenses. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its consolidated balance sheet, cash generated by operations and borrowing capacity available under its Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the year ended December 31, 2025 were $511.8 million, including the completion and/or continuation of certain one-time infrastructure projects but excluding acquisitions. 36 However, there are many factors and consequences beyond the Company’s control impacting our capital budget, such as political and regulatory uncertainties, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC or OPEC+, and governments in response to pandemics, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part II, Item 1A. Risk Factors” of this Quarterly Report. The Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. Capital resources. Cash flows from operating, investing and financing activities are summarized below (in thousands). Six Months Ended June 30, 2026 2025 Change % Change Net cash provided by operating activities $ 180,546 $ 298,265 $ (117,719 ) (39 )% Net cash used in investing activities $ (190,143 ) $ (322,078 ) $ 131,935 (41 )% Net cash (used in) provided by financing activities $ (6,132 ) $ (40,983 ) $ 34,851 (85 )% Operating activities. The decrease in net cash flow provided by operating activities for the six months ended June 30, 2026, compared with the same period in 2025, was primarily related to a decrease in discretionary cash flow as a result of a decrease in derivative settlements of approximately $76.5 million associated with higher overall commodity prices and an increased amount of derivative transactions entered into by the Company in accordance with its Term Loan Credit Agreement and Senior Credit Facility Agreement coupled with an overall increase in accounts receivable changes of $41.3 million related to increased commodity prices. Investing activities. The decrease in net cash used in investing activities for the six months ended June 30, 2026, compared with 2025, was primarily due to decreases in additions to crude oil and natural gas properties. Financing activities. The Company's significant financing activities are as follows: • Six months ended June 30, 2026: The Company paid debt issuance costs of $6.1 million primarily related to the Second Term Loan Amendment and the Third Facility Amendment. • Six months ended June 30, 2025: The Company made a mandatory amortization payment on its Term Loan Credit Agreement totaling $60.0 million and paid dividends and dividend equivalents of $9.9 million and $1.1 million, respectively, partially offset by borrowings under our Senior Credit Facility Agreement of $30.0 million. Interest Rate Risk. We are exposed to market risk due to the floating interest rates associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of June 30, 2026, we had a $1.2 billion outstanding balance on the Term Loan Credit Agreement and zero outstanding on the Senior Credit Facility Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the end of each quarter for a period of three months and the Senior Credit Facility Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period of up to six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic but are significantly down from the past two years. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing war between Russia and Ukraine, conflicts in the Middle East, and U.S. intervention in Venezuela. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our sales volumes during the six months ended June 30, 2026 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the six months ended June 30, 2026 would have increased (decreased) the Company’s revenues by approximately $11.5 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the six months ended June 30, 2026 would have increased (decreased) the Company’s revenues by approximately $1.7 million on an annualized basis. We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of June 30, 2026, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $6.8 million. Additionally, as of June 30, 2026, a $0.10 increase (decrease) in the forward curves associated with our natural gas commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $729,000. 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. 37 Non-GAAP Financial Measures EBITDAX represents net income before interest expense, interest and other income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, noncash derivative gains and losses, loss on extinguishment of debt, other expense, gains and losses on divestitures and certain other items. EBITDAX excludes certain items we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. We are also subject to financial covenants under our Term Loan Credit Agreement and Senior Credit Facility Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” of this Quarterly Report. The Term Loan Credit Agreement and Senior Credit Facility Agreement provide a material source of liquidity for us. Under the terms of our Term Loan Credit Agreement and the Senior Credit Facility Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of total net leverage or a minimum permitted ratio of asset coverage, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, lenders under those agreements would be entitled to exercise all of their remedies for default. The following table provides a reconciliation of our net income (GAAP) to EBITDAX (non-GAAP) for the periods presented (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Net income $ 82,275 $ 26,176 $ (45,173 ) $ 62,511 Interest expense 35,978 36,412 71,016 73,400 Interest and other income (1,032 ) (361 ) (1,981 ) (1,171 ) Provision for income taxes 16,448 7,663 (11,203 ) 17,602 Depletion, depreciation and amortization 113,429 101,226 226,443 210,551 Accretion of discount 302 256 597 500 Exploration and abandonment expense 4,444 1,109 5,186 1,373 Stock based compensation 868 88 1,733 265 Derivative related noncash activity (108,154 ) (19,034 ) 31,400 (14,178 ) Other expense 3,000 2,489 3,050 2,489 EBITDAX $ 147,558 $ 156,024 $ 281,068 $ 353,342 New Accounting Pronouncements Our historical condensed consolidated financial statements and related notes to condensed consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done, and judgments made on how the specifics of a given rule apply to us. In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for crude oil and natural gas activities, crude oil, NGL and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes. Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. There have been no material changes in our critical accounting policies and procedures during the three months ended June 30, 2026. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report. New accounting pronouncements issued but not yet adopted. The effects of new accounting pronouncements are discussed in Note 2 of Notes to Condensed Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)." 38