Cautionary Statement Concerning Forward-Looking Statements We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords. From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our Revolving Credit Facility, our intention or ability to pay or increase dividends on our capital stock, and impairment are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production, sales, market size, collaborations, cash flows, and trends or operating results also constitute such forward-looking statements. Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: •changes in crude oil and natural gas prices, the pace of drilling and completions activity on our current properties and properties pending acquisition; •infrastructure constraints and related factors affecting our properties; •general economic or industry conditions, whether internationally, nationally and/or in the communities in which our company conducts business, including any future economic downturn, cost inflation, supply chain disruptions, the impact of continued or further inflation, disruption in the financial markets, changes in the interest rate environment and actions taken by OPEC and other oil producing countries as it pertains to the global supply and demand of, and prices for, crude oil, natural gas and NGLs; •ongoing legal disputes over, and potential shutdown of, the Dakota Access Pipeline; •our ability to identify and consummate additional development opportunities and potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness; •changes in our reserves estimates or the value thereof; •disruption to our company’s business due to acquisitions and other significant transactions; •changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs), and similar changes in foreign jurisdictions where we currently or in the future may operate, including Canada; •conditions of the securities markets; •exchange rate fluctuations; •risks associated with our Convertible Notes, including the potential impact that the Convertible Notes may have on our financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of our company; •the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuances, including counterparty risk; •increasing attention to environmental, social and governance matters; •our ability to raise or access capital on acceptable terms; •cyber-incidents could have a material adverse effect on our business, financial condition or results of operations; •changes in accounting principles, policies or guidelines; •events beyond our control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions and shipping channels, including the joint U.S.-Israel strikes on Iran, continued instability in the Middle East and the effects of any changes to conditions in or impacting Venezuela; and •other economic, competitive, governmental, regulatory and technical factors affecting our operations, products and prices. 34 Table of Contents We have based any forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected. Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins in North America. Using this strategy, we had participated in 12,507 gross (1,369.7 net) producing wells as of June 30, 2026. As of June 30, 2026, we had leased approximately 414,787 net acres, of which approximately 71% were developed and all were located in the United States and Canada. We have grown and diversified our business significantly over the last several years through acquisitions of oil and natural gas properties. See Note 3 to our condensed consolidated financial statements for information regarding our recent acquisition activities. Our average daily production in the second quarter of 2026 was approximately 145,659 Boe per day, of which approximately 47% was oil. This was a 9% increase in production compared to the second quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and six months ended June 30, 2026, we added 12.7 and 29.8 net wells to production, respectively. Our weighted average percentage of production volumes by basin for the three months ended June 30, 2026 and 2025 were as follows: Three Months Ended June 30, 2026 Williston Permian Appalachian Uinta Duvernay Total Oil (Bbl) 39 % 44 % 1 % 14 % 2 % 100 % Natural Gas (Mcf) 17 % 27 % 55 % 1 % — % 100 % Total (Boe) 27 % 34 % 30 % 8 % 1 % 100 % Three Months Ended June 30, 2025 Williston Permian Appalachian Uinta Duvernay Total Oil (Bbl) 38 % 49 % — % 13 % — % 100 % Natural Gas (Mcf) 22 % 40 % 36 % 2 % — % 100 % Total (Boe) 31 % 45 % 15 % 9 % — % 100 % 35 Table of Contents Source of Our Revenues We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements. Principal Components of Our Cost Structure •Commodity price differentials. The price differential between our well head price for oil and the NYMEX WTI benchmark price (“Oil Price Differential”) is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price (“Gas Price Differential”) is primarily driven by gathering and transportation costs. As applicable, the calculations of both our Oil Price Differential and Gas Price Differential include certain immaterial non-cash revenue adjustments intended to reflect current period economic conditions. •Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period end. •Production expenses. Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, natural gas processing, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. •Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. •Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations. •General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, audit and other professional fees and legal compliance. •Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool. We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs (including origination and amendment fees), the amortization of bond premiums and discounts, commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense. •Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test impairment review each quarter. The test determines a limit, or ceiling, on the book value of the Company’s oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. As a result of its ceiling test, the Company recorded a non-cash impairment charge of $268.3 million in the six months ended June 30, 2026. The Company did not have any ceiling test impairment charge in the three months ended June 30 2026. The Company recorded a non-cash impairment charge of $115.6 million in the three and six months ended June 30, 2025. Average commodity prices used in our ceiling test calculation have fluctuated significantly in recent quarters. If such prices trend downward, and/or if our proved reserves decrease significantly in 36 Table of Contents future months, the present value of the Company’s future net revenues could decline, which could trigger the need for the Company to record an additional non-cash ceiling test impairment of its oil and gas property costs in future periods. •Income tax expense. Our provision for taxes includes, federal, state and foreign taxes. We record our income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: •the timing and success of drilling and production activities by our operating partners; •the prices and the supply and demand for oil, natural gas and NGLs; •the quantity of oil and natural gas production from the wells in which we participate; •changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices; •our ability to continue to identify and acquire high-quality acreage and drilling opportunities; •the level of our operating expenses; and •the foreign currency exchange rates impacting our foreign operations. In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian, Uinta and Duvernay Basins subjects our operating results to factors specific to these operating regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these operating regions. The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX Henry Hub benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark prices and the sales prices we receive for our production. Our average oil price differential to the NYMEX WTI benchmark price during the three months ended June 30, 2026 was $3.03 per barrel, as compared to $5.31 per barrel for the three months ended June 30, 2025. Our average oil price differential to the NYMEX WTI benchmark price during the six months ended June 30, 2026 was $4.88 per barrel, as compared to $5.50 per barrel for the six months ended June 30, 2025. Our net average realized gas price in the three months ended June 30, 2026 was $2.64 per Mcf, representing a 90% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $2.89 per Mcf in the three months ended June 30, 2025, which represented a 82% realization relative to the average NYMEX Henry Hub pricing. Our net average realized gas price in the six months ended June 30, 2026 was $2.57 per Mcf, representing an 80% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $3.37 per Mcf in the six months ended June 30, 2025, which represented a 91% realization relative to the average NYMEX Henry Hub pricing. 37 Table of Contents Fluctuations in our oil and natural gas price realizations are due to several factors such as realized pricing by basin, gathering and transportation costs, transportation methods, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance temporarily depressing demand, and in the case of gas realizations, the price of NGLs. Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher commodity prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower commodity prices have generally had the opposite effect. In addition, individual components of drilling costs can vary depending on numerous factors, such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant used. During the six months ended June 30, 2026 and 2025, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.4 million and $10.0 million, respectively. Market Conditions The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production. During 2025, a significant decline in oil prices occurred as a result of, among other things, (i) uncertainties regarding U.S. trade policies and tariffs driving concerns over increasing inflation, (ii) continued concerns over slowing global economic growth and resulting reductions in estimated global oil consumption, and (iii) the decision by OPEC to increase production starting in May 2025 and on multiple occasions subsequent thereto, creating additional global supply and further downward pressure on oil prices. However, in early 2026, significant increases in oil prices occurred as a result of the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups in connection with the joint U.S.-Israel strikes on Iran, with the NYMEX price for oil peaking in April 2026 at levels not seen since the second quarter of 2022. Oil prices have remained highly volatile since then. Although U.S. inflation rates were relatively stable during the first half of 2026, they remain slightly higher than historical averages. Inflationary pressures, such as trade tariffs, can lead to economic slowdown and/or lead to a recession, which in turn can cause a decrease in short-term or longer-term demand for commodities, resulting in oversupply and potential for lower commodity prices. The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil and natural gas supply and demand, which in turn has increased the volatility of oil and natural gas prices. Prolonged lower oil prices and inflationary costs could impact our operating partners’ development schedule for the non-operated wells in which we have a working interest. Additionally, such prolonged depressed prices could result in a significant triggering event indicating the need for further impairment of our oil and natural gas assets. Any of the foregoing events or circumstances could impact our future sales volumes, operating revenues and expenses, liquidity, per unit metrics and capital expenditures. In light of current macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia’s invasion of Ukraine, conflicts in the Middle East and Venezuela, and potential further imposition of domestic and foreign tariffs, we cannot predict any future volatility in or levels of commodity prices or demand for oil and natural gas. Further, pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we are now subject to foreign currency risks. Our wholly owned Canadian subsidiary uses the Canadian dollar (“CAD”) as its functional currency. Fluctuations in the USD/CAD exchange rate will affect the USD equivalent of our wholly owned Canadian subsidiary’s assets, liabilities, revenues, and operating expenses as reported in our condensed consolidated financial statements. Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2026 and 2025. 38 Table of Contents Three Months Ended June 30, 2026 2025 Average NYMEX Prices(1) Natural Gas (per MMbtu) $ 2.94 $ 3.51 Oil (per Bbl) $ 93.05 $ 63.68 _________ (1)Based on average NYMEX closing prices. Six Months Ended June 30, 2026 2025 Average NYMEX Prices(1) Natural Gas (per MMbtu) $ 3.21 $ 3.69 Oil (per Bbl) $ 82.67 $ 67.52 _________ (1)Based on average NYMEX closing prices. We have entered into derivatives contracts to hedge commodity price risks on a portion of our future expected oil and natural gas production. For a summary as of June 30, 2026, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Part I, Item 3 below. See also Note 10 to our condensed consolidated financial statements. 39 Table of Contents Results of Operations for the Three Months Ended June 30, 2026 and June 30, 2025 The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated. Three Months Ended June 30, 2026 2025 % Change Net Production: Oil (MBbl) 6,213 7,002 (11) % Natural Gas (MMcf) 42,254 31,204 35 % Total (MBoe) 13,255 12,203 9 % Net Sales (in thousands): Oil Sales $ 559,264 $ 402,672 39 % Natural Gas and NGL Sales 111,532 171,697 (35) % Gain (Loss) on Settled Commodity Derivatives (86,320) 60,931 (242) % Gain on Unsettled Commodity Derivatives 156,502 67,888 131 % Other Revenue 4,257 3,621 18 % Total Revenues 745,235 706,809 5 % Average Sales Prices: Oil (per Bbl) $ 90.02 $ 58.37 54 % Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) (20.65) 6.21 (433) % Oil Net of Settled Oil Derivatives (per Bbl) 69.37 64.58 7 % Natural Gas and NGLs (per Mcf) (1) $ 2.64 $ 2.89 (9) % Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.99 0.56 77 % Natural Gas and NGLs Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1) 3.63 3.45 5 % Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) $ 50.61 $ 40.87 24 % Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) (6.51) 4.99 (230) % Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) 44.10 45.86 (4) % Operating Expenses (in thousands): Production Expenses $ 127,089 $ 121,430 5 % Production Taxes 45,699 35,616 28 % General and Administrative Expenses 24,529 15,628 57 % Depletion, Depreciation, Amortization and Accretion 192,885 205,741 (6) % Other Expense 2,496 3,561 (30) % Costs and Expenses (per Boe): Production Expenses $ 9.59 $ 9.95 (4) % Production Taxes 3.45 2.92 18 % General and Administrative Expenses 1.85 1.28 45 % Depletion, Depreciation, Amortization and Accretion 14.55 16.86 (14) % Net Producing Wells at Period End 1,369.7 1,151.7 19 % ______________ (1) The three months ended June 30, 2025 excludes the impact of a legal settlement (See Note 2 to our condensed consolidated financial statements). 40 Table of Contents Oil and Natural Gas Sales In the second quarter of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $670.8 million, compared to $574.4 million in the second quarter of 2025. In the second quarter of 2025, we recorded a legal settlement of approximately $81.7 million from an operator in North Dakota to resolve our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements). Excluding the impact of the legal settlement, oil and natural gas sales increased by 36%. The increase in revenues was primarily driven by a 24% increase in weighted average realized prices and a 9% increase in production volumes. We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Acquisitions were a significant driver of our 9% increase in production volumes in the second quarter of 2026 compared to the same period of 2025. Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a gain of $70.2 million in the second quarter of 2026, compared to a gain of $128.8 million in the second quarter of 2025. Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For the second quarter of 2026, we realized a loss on settled commodity derivatives of $86.3 million, compared to a gain of $60.9 million in the second quarter of 2025. We incur realized losses on settled commodity derivatives when the average commodity market price at settlement is higher than our average hedge book price. Conversely, we incur gains when the average commodity market price at settlement is lower than our average hedge book price. For the second quarter of 2026, we realized a gain on our unsettled commodity derivative of $156.5 million, compared to a gain of $67.9 million in the second quarter of 2025. Our derivatives are not designated for hedge accounting, and thus are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying condensed consolidated balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $240.3 million, a change of $361.9 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value or our unsettled derivative contracts at June 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $127.1 million in the second quarter of 2026, compared to $121.4 million in the second quarter of 2025. On a per unit basis, production expenses were $9.59 per Boe in the second quarter of 2026 compared to $9.95 per Boe in the second quarter of 2025. The decrease in our production expenses per unit in the second quarter of 2026 compared to the second quarter of 2025 was primarily due to higher production volumes in the second quarter of 2026 as compared to the same period in 2025. Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were $45.7 million in the second quarter of 2026, compared to $35.6 million in the second quarter of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.8% and 7.2% in the second quarter of 2026 and 2025, respectively. 41 Table of Contents General and Administrative Expenses General and administrative expenses were $24.5 million in the second quarter of 2026, or $1.85 per Boe, compared to $15.6 million in the second quarter of 2025, or $1.28 per Boe. The increase was primarily driven by the $7.6 million transaction costs recorded for the Duvernay Acquisition, which was accounted for as a business combination (see Note 3 to our condensed consolidated financial statements). Legal Settlement Expense In the second quarter of 2025, we incurred legal expenses of approximately $33.1 million in conjunction with our $81.7 million received from an operator in North Dakota, pursuant to a legal settlement resolving our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements). Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $192.9 million in the second quarter of 2026, compared to $205.7 million in the second quarter of 2025. Depletion expense, the largest component of DD&A, decreased by $13.0 million in the second quarter of 2026 compared to the second quarter of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.45 per Boe in the second quarter of 2026 compared to $16.76 per Boe in the second quarter of 2025. Depreciation, amortization and accretion was $1.3 million and $1.2 million in the second quarter of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the second quarter of 2026 and 2025: Three Months Ended June 30, 2026 2025 $ Change % Change Depletion $ 14.45 $ 16.76 $ (2.31) (14) % Depreciation, Amortization and Accretion 0.10 0.10 — — % Total DD&A Expense $ 14.55 $ 16.86 $ (2.31) (14) % Impairment Expense The Company recorded an impairment charge of $115.6 million in the second quarter of 2025, as a result of its full cost ceiling test. No impairment charges were recorded in the second quarter of 2026. Interest Expense, Net Interest expense, Net was $41.4 million in the second quarter of 2026 compared to $44.4 million in the second quarter of 2025. The decrease was primarily due to lower weighted average borrowing rates, pursuant to the refinancing of the Company’s Senior Notes due 2028 by the Senior Notes due 2033 at a lower borrowing cost (See Note 4 to our condensed consolidated financial statements). Loss on Foreign Currency Transactions Foreign currency transaction losses were $4.7 million in the second quarter of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to the Company’s recent acquisition of oil and natural gas properties in Canada. The Company did not have any foreign currency transactions in the second quarter of 2025. Gain on Contingent Consideration During the second quarter of 2026, we recorded a contingent consideration gain of $2.7 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration gain was primarily driven by a favorable change in the forward NYMEX WTI oil price curve from the acquisition date to June 30, 2026. 42 Table of Contents Income Tax During the second quarter of 2026, we recorded an income tax expense of $74.0 million, as compared to $32.2 million recorded for the second quarter of 2025. The higher income tax expense in the second quarter of 2026 was driven by a higher taxable income as compared to the same period in 2025. 43 Table of Contents Results of Operations for the Six Months Ended June 30, 2026 and June 30, 2025 The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated. Six Months Ended June 30, 2026 2025 % Change Net Production: Oil (MBbl) 12,834 14,083 (9) % Natural Gas (MMcf) 82,614 61,597 34 % Total (MBoe) 26,603 24,349 9 % Net Sales (in thousands): Oil Sales $ 998,346 $ 862,354 16 % Natural Gas and NGL Sales 212,305 288,967 (27) % Gain (Loss) on Settled Commodity Derivatives (103,953) 72,993 (242) % Gain (Loss) on Unsettled Commodity Derivatives (364,921) 77,588 (570) % Other Revenue 8,487 7,006 21 % Total Revenues 750,264 1,308,908 (43) % Average Sales Prices: Oil (per Bbl) $ 77.79 $ 62.01 25 % Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) (12.22) 3.87 (416) % Oil Net of Settled Oil Derivatives (per Bbl) 65.57 65.88 — % Natural Gas and NGLs (per Mcf) (1) $ 2.57 $ 3.37 (24) % Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.64 0.30 113 % Natural Gas and NGLs Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1) 3.21 3.67 (13) % Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) $ 45.51 $ 44.38 3 % Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) (3.91) 3.00 (230) % Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) 41.60 47.38 (12) % Operating Expenses (in thousands): Production Expenses $ 256,836 $ 235,470 9 % Production Taxes 84,042 71,685 17 % General and Administrative Expenses 47,703 30,109 58 % Depletion, Depreciation, Amortization and Accretion 389,983 411,432 (5) % Other Expense 5,771 6,098 (5) % Costs and Expenses (per Boe): Production Expenses $ 9.65 $ 9.67 — % Production Taxes 3.16 2.94 7 % General and Administrative Expenses 1.79 1.24 44 % Depletion, Depreciation, Amortization and Accretion 14.66 16.90 (13) % Net Producing Wells at Period End 1,369.7 1,151.7 19 % ______________ (1)The six months ended June 30, 2025, excludes the impact of a legal settlement (See Note 2 to our condensed financial statements). 44 Table of Contents Oil and Natural Gas Sales In the first six months of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,210.7 million, compared to $1,151.3 million in the first six months of 2025. In the first six months of 2025, we recorded a legal settlement of approximately $81.7 million from an operator in North Dakota to resolve our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements). Excluding the impact of the legal settlement, oil and natural gas sales increased 13%. The increase in revenues was primarily driven by a 3% increase in weighted average realized prices and a 9% increase in production volumes. We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Acquisitions were a significant driver of our 9% increase in production volumes in the first six months of 2026 compared to the same period of 2025. Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a loss of $468.9 million in the first six months of 2026, compared to a gain of $150.6 million in the first six months of 2025. Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For the first six months of 2026, we realized a loss on settled commodity derivatives of $104.0 million, compared to a gain of $73.0 million in the first six months of 2025. For the first six months of 2026, we realized a loss on our unsettled commodity derivative of $364.9 million, compared to a gain of $77.6 million in the first six months of 2025. Our derivatives are not designated for hedge accounting, and thus are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying condensed consolidated balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $240.3 million, a change of $361.9 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value or our unsettled derivative contracts at June 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $256.8 million in the first six months of 2026, compared to $235.5 million in the first six months of 2025. On a per unit basis, production expenses were $9.65 per Boe in the first six months of 2026 compared to $9.67 per Boe in the first six months of 2025. Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were $84.0 million in the first six months of 2026, compared to $71.7 million in the first six months of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.9% and 6.7% in the first six months of 2026 and 2025, respectively. General and Administrative Expenses General and administrative expenses were $47.7 million in the first six months of 2026, or $1.79 per Boe, compared to $30.1 million in the first six months of 2025, or $1.24 per Boe. The increase was primarily driven by $14.3 million in 45 Table of Contents transaction costs recorded for both the Utica Acquisition and the Duvernay Acquisition, which were both accounted for as business combinations (see Note 3 to our condensed consolidated financial statements). Legal Settlement Expense In the first six months of 2025, we incurred legal expenses of approximately $33.1 million in conjunction with our $81.7 million received from an operator in North Dakota, pursuant to a legal settlement resolving our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements). Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $390.0 million in the first six months of 2026, compared to $411.4 million in the first six months of 2025. Depletion expense, the largest component of DD&A, decreased by $21.7 million in the first six months of 2026 compared to the first six months of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.56 per Boe in the first six months of 2026 compared to $16.80 per Boe in the first six months of 2025. Depreciation, amortization and accretion was $2.6 million and $2.4 million in the first six months of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the first six months of 2026 and 2025: Six Months Ended June 30, 2026 2025 $ Change % Change Depletion $ 14.56 $ 16.80 $ (2.24) (13) % Depreciation, Amortization and Accretion 0.10 0.10 — — % Total DD&A Expense $ 14.66 $ 16.90 $ (2.24) (13) % Impairment Expense In the first six months of 2026, the Company recorded a non-cash impairment charge of $268.3 million compared to $115.6 million in the first six months of 2025, as a result of its full cost ceiling tests. Interest Expense, Net Interest expense, Net was $84.0 million in the first six months of 2026 compared to $87.7 million in the first six months of 2025. The decrease was primarily due to lower weighted average borrowing rates, pursuant to the refinancing of the Company’s Senior Notes due 2028 by the Senior Notes due 2033 at a lower borrowing cost (See Note 4 to our condensed consolidated financial statements). Loss on Foreign Currency Translations Foreign currency transaction losses were $4.7 million in the first six months of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to the Company’s recent acquisition of oil and natural gas properties in Canada. The Company did not have any foreign currency transactions in the first six months of 2025. Gain on Contingent Consideration During the first six months of 2026, we recorded a contingent consideration gain of $2.7 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration gain was primarily driven by a favorable change in the forward NYMEX WTI oil price curve from the acquisition date to June 30, 2026. Income Tax During the first six months of 2026, we recorded an income tax benefit of $99.1 million due to our pretax losses caused, primarily, by our losses on commodity derivatives and our non-cash ceiling test impairment charge. Conversely, we recorded an income tax expense of $79.0 million for the first six months of 2025. 46 Table of Contents Liquidity and Capital Resources Overview Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments. Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. In March 2026, we issued 8,288,289 shares of our common stock in a public offering for total consideration of approximately $227.9 million. In March 2026, we redeemed all of the outstanding Senior Notes due 2028 at a redemption price of 100%. Total consideration paid pursuant to the redemption of the Senior Notes due 2028 was approximately $20.2 million. In June 2026, we issued 3,689,413 shares of our common stock in conjunction with the acquisition of oil and gas properties pursuant to the Duvernay Acquisition (See Note 3 to our condensed consolidated financial statements). In June 2026, we repurchased and retired 2,948,447 shares of our common stock for total consideration of $60.1 million, or an average price of $20.37 per share. As of June 30, 2026, we had outstanding total debt of $2.8 billion consisting of $825.0 million of borrowings under our Revolving Credit Facility, $700.0 million aggregate principal amount of our Convertible Notes due 2029, $500.0 million aggregate principal amount of our Senior Notes due 2031, and $725.0 million aggregate principal amount of our Senior Notes due 2033. As of June 30, 2026, we had total liquidity of approximately $1.0 billion, consisting of $975.0 million of committed borrowing availability under the Revolving Credit Facility and $47.6 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 83% and 82% of our total oil and gas sales in the second quarter of 2026 and 2025, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the six months ended June 30, 2026, we hedged approximately 80% of our crude oil production and approximately 60% of our natural gas production. For a summary as of June 30, 2026, of our open commodity swap contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Working Capital Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments. 47 Table of Contents At June 30, 2026, we had a working capital deficit of $128.4 million, compared to a surplus of $46.7 million at December 31, 2025. Current assets decreased by $83.9 million and current liabilities increased by $91.2 million at June 30, 2026, compared to December 31, 2025. Cash Flows Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. See “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below. Our cash summary for the three and six months ended June 30, 2026 and 2025 is presented below: Three Months Ended June 30, Six Months Ended June 30, (In thousands, unaudited) 2026 2025 2026 2025 Net Cash Provided by Operating Activities $ 321,617 $ 362,112 $ 645,232 $ 769,538 Net Cash Used for Investing Activities $ (379,811) (327,255) (1,014,489) (591,813) Net Cash Provided by (Used for) Financing Activities 74,230 (42,577) 408,035 (160,802) Effect of Exchange Rate Changes on Cash and Cash Equivalents $ (5,474) $ — $ (5,474) $ — Net Increase in Cash $ 10,562 $ (7,720) $ 33,304 $ 16,923 Cash Flows from Operating Activities Net cash provided by operating activities for the three months ended June 30, 2026 was $321.6 million, compared to $362.1 million in the same period of the prior year. The lower cash provided by operating activities in the second quarter of 2026 was primarily due to realized losses from settled commodity derivatives, partially offset by increased revenues from higher prices and production volumes. Net cash provided by operating activities for the six months ended June 30, 2026 was $645.2 million, compared to $769.5 million in the same period of the prior year. The lower cash provided by operating activities in the six months ended June 30, 2026 was primarily due to realized losses from settled commodity derivatives, partially offset by increased revenues from higher prices and production volumes. Cash Flows from Investing Activities Cash flows used in investing activities during the three months ended June 30, 2026 and 2025 were $379.8 million and $327.3 million, respectively. Cash flows used in investing activities during the six months ended June 30, 2026 and 2025 were $1,014.5 million and $591.8 million, respectively. Cash used in investing activities was higher during the six months ended June 30, 2026 primarily due to the Utica Acquisition and the Duvernay Acquisition, as described in Note 3 to the Company’s condensed consolidated financial statements. Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the three months ended June 30, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $463.4 million, while the actual cash spend in this regard amounted to $379.8 million. Further, during the six months ended June 30, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,203.1 million, while the actual cash spend in this regard amounted to $1,014.4 million. 48 Table of Contents Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the six months ended June 30, 2026 and 2025 are summarized in the following table: Six Months Ended June 30, (In thousands, unaudited) 2026 2025 Drilling and Development Capital Expenditures $ 369.7 $ 478.6 Acquisition of Oil and Natural Gas Properties 637.0 110.8 Other Capital Expenditures 7.7 1.9 Total $ 1,014.4 $ 591.3 Cash Flows from Financing Activities Net cash provided by financing activities was $74.2 million during the three months ended June 30, 2026, compared to net cash used for financing activities of $42.6 million during the three months ended June 30, 2025. For the three months ended June 30, 2026, cash provided by financing activities was primarily due to $172.0 million net borrowings under our Revolving Credit Facility, partially offset by $50.0 million disbursed for our common stock repurchases and $47.4 million of common stock dividend payments. For the three months ended June 30, 2025, cash used for financing activities was primarily due to $150.0 million net repayment of borrowings under our Revolving Credit Facility, $44.3 million of common stock dividend payments, $35.0 million in repurchases of common stock, and $16.9 million from the entry into Additional Capped Call Transactions, partially offset by the issuance of $200.0 million in aggregate principal amount of Additional Convertible Notes at an issue price of 105.597% of the principal amount thereof. Net cash provided by financing activities was $408.0 million during the six months ended June 30, 2026, compared to net cash used for financing activities of $160.8 million during the six months ended June 30, 2025. For the six months ended June 30, 2026, cash provided by financing activities was primarily due to $227.9 million proceeds from issuance of common stock, and $347.0 million net borrowings under our Revolving Credit Facility, partially offset by $91.8 million of common stock dividend payments, $50.0 million in repurchases of common stock, $20.2 million spent to redeem all of the outstanding Senior Notes due 2028, and $2.8 million to settle the tax obligations related to employee share based compensations. For the six months ended June 30, 2025, cash used for financing activities was primarily due to $210.0 million net repayment of borrowings under our Revolving Credit Facility, $86.0 million of common stock dividend payments, $50.0 million in repurchases of common stock, and $16.9 million from the entry into Additional Capped Call Transactions, partially offset by the issuance of $200.0 million in aggregate principal amount of Additional Convertible Notes at an issue price of 105.597% of the principal amount thereof. Revolving Credit Facility We have entered into the Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and natural gas properties. In February 2026, the Company completed a wildcard redetermination, pursuant to which the borrowing base was increased from $1.8 billion to $1.975 billion, and the aggregate elected commitment amount was increased from $1.6 billion to $1.8 billion. As of June 30, 2026, the Revolving Credit Facility had a borrowing base of $1.975 billion and an elected commitment amount of $1.8 billion, and we had $825.0 million in borrowings outstanding under the facility, leaving approximately $1.0 billion in available committed borrowing capacity. See Note 4 to our condensed consolidated financial statements for further details regarding the Revolving Credit Facility. 49 Table of Contents Senior Notes due 2028 In March 2026, we redeemed all of the outstanding Senior Notes due 2028, in accordance with the terms of the 2028 Notes Indenture, at a redemption price of 100%. See Note 4 to our condensed consolidated financial statements for further details regarding the Senior Notes due 2028. Convertible Notes due 2029 As of June 30, 2026, we had outstanding $700.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our condensed consolidated financial statements for further details regarding the Convertible Notes. Senior Notes due 2031 As of June 30, 2026, we had outstanding $500.0 million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our condensed consolidated financial statements for further details regarding the Senior Notes due 2031. Senior Notes due 2033 As of June 30, 2026, we had outstanding $725.0 million aggregate principal amount of our Senior Notes due 2033. See Note 4 to our condensed consolidated financial statements for further details regarding the Senior Notes due 2033. Effects of Inflation and Pricing The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not presently budgeting for any material change in per well drilling and completion and other associated costs in 2026 compared to 2025. Effects of Foreign Currency Exchange Rate Changes Pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we are now subject to foreign currency risks from fluctuations in the USD/CAD exchange rate. Effects of Pricing on Contingent Consideration Liability Pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we incurred a contingent consideration liability payable in January 2028. The payable amount is dependent on the WTI oil price reaching an average of $72.50 per Bbl during the period from April 1, 2026 to December 31, 2027. In accordance with the applicable accounting guidelines, we remeasure the fair value of the contingent consideration liability each reporting period. Gains or losses from remeasurement are recorded in earnings. Contractual Obligations and Commitments Please see our disclosure of contractual obligations and commitments as of December 31, 2025, included in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025. Critical Accounting Estimates Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Our critical accounting estimates include impairment testing of natural gas and crude oil production properties, and derivative instruments and hedging activity. There were no material changes in our critical accounting estimates from those reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025. 50 Table of Contents A description of our critical accounting policies, including estimates, was provided in Note 2 to our financial statements provided in Part II, Item 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025.