NOG 10-K & 10-Q changes, risk factors and insider trading

•political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activityactivity, including the effects of any changes to conditions in or impacting Venezuela;

•infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019;

Due to previous declines inLower oil and natural gas prices,prices weand other factors have resulted in the past taken significant writedowns of our oil and natural gas properties.properties, Weand we may be required to record further writedowns of our oil and natural gas properties in the future.

InWe 2020, we were required to write downfollow the carryingfull valuecost method of certainaccounting offor our oil and natural gas properties, and further writedowns could be required in the future.operations. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment would be recognized. Such write-downs do not impact cash flows from operating activities but do reduce net income. For the year ended December 31, 2025, we recorded a non-cash full cost ceiling impairment charge of $702.7 million. Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods.

We base the estimated discounted future net cash flows from our proved reserves usingon specified pricing and cost assumptions. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as the volume, pricing and duration of our oil and natural gas hedging contracts; actual prices we receive for oil, natural gas and NGLs; our actual operating costs in producing oil, natural gas and NGLs; the amount and timing of our capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

The Dakota Access Pipeline (“DAPL”), a major pipeline transporting crude oil from the Williston Basin, is subject to ongoing litigation (the “DAPL Litigation”) that could threaten its continued operation. In July 2020, a federal district court ordered DAPL to be shut down pending the completion of an environmental impact statement (“EIS”) to determine whether the DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The temporary shutdown order was overturned by the U.S. Court of Appeals in August 2020. DAPL currently remains in operation while the U.S. Army Corps of Engineers (“USACE”) conducts the EIS, which was released in draft form in September 2023 and was open for public comment until mid-December 2023. The USACE received over 200,000 public comments. TheOn dateDecember that19, 2025, the USACE completed the final EIS will be published is not yet known, although according to statements from the USACE the final EIS may be published in 2025.EIS. Following this completion of the EIS, the USACE will determine whether to grant DAPL an easement to cross the Missouri River or to shut down the pipeline,pipeline. unlessPublication of the U.S.EIS Supremedoes Courtnot overturnsconstitute a decision, and a subsequent 30-day waiting period is required. After the lowerwaiting courts’period, orderwhich toconcluded conducton January 20, 2026, the EIS.USACE may issue a Record of Decision identifying a selected alternative for implementation. Moreover, the EIS and/or the USACE’s easement decision may subsequently be challenged in court. In March 2025, a 2024 challenge to the ongoing operation of the pipeline was dismissed in the D.C. Circuit. Petitioners have filed an appeal and litigation is ongoing. As a result, a shut-down remains possible, and there is no guarantee that DAPL will be permitted to continue operations following the completion of the EIS and/or the DAPL Litigation. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect our business, results of operations and financial condition.

Most scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce significant physical effects on weather conditions, such as increased frequency and severity of storms, extreme temperatures, droughts and floods, among other climatic phenomena. If any such effects were to occur, they could adversely affect or delay demand for oil and natural gas products or cause us or our third party operators to incur significant costs in preparing for, or responding to, the effects of climatic events themselves, which may not be fully insured. Energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. To the extent the frequency of extreme weather events increases, this could impact our business in various ways, including damage to operators’ facilities at our properties or increased insurance premiums.premiums and reduced availability of insurance coverage. Potential adverse effects on our third party operators could also include disruption of their production activities and supply chain. Any of these effects could have an adverse effect on our business, results of operations and financial condition.

ContinuingInflationary or worsening inflationary issuespressure and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Inflation has been an ongoing concern in the U.S. since 2021. Ongoing inflationary pressuresWe have resulted inexperienced, and may resultcontinue into additionalexperience, increased inflationary pressure on our business, including increases to the costs of goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation caused the U.S. Federal Reserve to increase the federal funds interest rate by 5.25% to a high of 5.375% between March 2022 and July 2023 in an effort to curb inflationary pressure on the costs of goods and services. While inflationary pressures in the United States’ economy have begun to subside, inflation is still holding above the U.S. Federal Reserve’s target level. Further, despite the U.S. Federal Reserve decreasing the federal funds interest rate to 4.375%3.625% between September 2024 and December 2024,2025, we continue to be impacted by the elevated federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contractstransactions for a portion of our expected production, which may include swaps, collars, puts and other structures. In accordance with applicable accounting principles, we are required to record our derivativesderivative transactions at fair market value, and they are included on our balance sheet as assets or liabilities and in our statements of income as gain (loss) on derivatives, net. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments.transactions. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivativesderivative transactions may limitreduce our potential gains and increase our potential lossesperformance if oil and natural gas prices were to rise substantially over the price established by the hedge.derivative transactions.

Our actual future production for any period may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors,result, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, andand, in certain circumstancescircumstances, may actually increase the volatility of our cash flows.flows and result in losses and reductions in liquidity. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contractstransactions is unable to satisfy its obligations under the contracts; our production is less than expected; or there is aan adverse widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement.arrangement may result in losses and reductions in liquidity.

Additionally, certain segments of the investor community have expressed negative sentiment towards investing in the oil and natural gas industry. Climate change-related developments in particular may result in negative perceptions of the traditional oil and gas industry and, in turn, reputational risks associated with exploration and production activities. There have been efforts in recent years, for example, to influence the investment community, including investment advisors, insurance companies and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Financial institutions may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. With the continued volatility in oil and natural gas prices, and thepersistently possibilityhigh thatborrowing interest rates will rise in the near term, increasing the cost of borrowing,costs, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.

Companies across all industries continue to face increasing scrutiny from stakeholders related to their ESG and sustainability practices. Failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals we may set could damage our reputation, causing our investors or other stakeholders to lose confidence in our company, and negatively impact our operations. There can be no assurance that we will be able to accomplish any announced goals, initiatives, commitments or objectives related to our ESG strategy, as statements regarding the same reflect our current plans and aspirations and are not guarantees that we will be able to achieve them within the timelines we announce, or at all. We may determine in our discretion that it is not feasible or practical to implement or complete certain of our ESG goals, initiatives, policies or procedures based on cost, timing or other considerations. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any ESG goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Relatedly, there is increasing focus by regulators, customers and other stakeholders on greenwashing issues and environmental marketing and sustainability-related claims. There can be no assurance that we will not be subject to greenwashing allegations or claims associated with the veracity of our environmental and sustainability-related claims, including any claims related to our emissions reductions initiatives or the sustainability practices of our operators, among other things, which could expose us to liabilities or require us to incur additional costs to adequately prepare disclosures or improve internal controls. There is also increasing focus on ESG and sustainability disclosure and regulation across various jurisdictions and exposure to any new regulatory and legal requirements may lead to increased operational costs and compliance burden for us. The occurrence of any of the foregoing could have a material adverse effect on our business and financial condition.

Further, our business and growth opportunities require us to have strong relationships with various key stakeholders, including our stockholders, lenders, employees, suppliers, customers, local communities and others. We may face pressures from stakeholders to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability, or with respect to other ESG matters, while at the same time remaining a successfully operating public company. At the same time, recent “anti-ESG” political developments could subject the Company to increased risk of criticism or litigation risks from certain “anti-ESG” parties including various government agencies. Such sentiment may focus on the Company’s environmental or social initiatives, which anti-ESG proponents may assert as unlawful, political or polarizing in nature. If we do not successfully manage expectations across these varied stakeholder interests, it could erode our stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital.

In connection with the pricing of our 3.625% convertible senior notes due 2029 (the “Convertible Notes”), in October 2022 and our offering of Additional Convertible Notes (as defined herein) in June 2025, we entered into privately negotiated capped call transactions relating to such notes with the option counterparties. The capped call transactions relating to the Convertible Notes cover, subject to customary adjustments, the number of shares of our common stock that initially underlie such notes. The capped call transactions are expected generally to reduce the potential dilution to our common stock upon any conversion of the Convertible Notes and/or offset any potential cash payments we are required to make in excess of the principal amount of converted notes, as the case may be, with such reduction and/or offset subject to a cap.

We are subject to counterparty risk with respect to the capped call transactions, and the capped call transactions may not operate as planned.

The option counterparties to the capped call transactions are financial institutions, and we are subject to the risk that one or more of the option counterparties may default or otherwise fail to perform,perform under, or may exercise certain rights to terminate their obligations, underterminate, the capped call transactions. Our exposure to the credit risk of the option counterparties is not secured by any collateral. Global economic conditions have from time to time resulted in the actual or perceived failure or financial difficulties of many financial institutions. If an option counterparty to one or more capped call transactions becomes subject to insolvency proceedings, we will become an unsecured creditor in those proceedings with a claim equal to ourthe exposurevalue at that time underof our transactionscapped call transaction with that option counterparty. OurThe exposurevalue of our capped call transactions will depend on many factorsfactors, but, generally, thewill increase in our exposure will be correlated with increases in the market price and/or the volatility of our common stock. In addition, upon a default or other failure to perform,perform under, or a termination ofof, obligations,a capped call transaction by an option counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any option counterparty.

In addition, the capped call transactions are complex, and they may not operate as planned. For example, the terms of the capped call transactions may be subject to adjustment, modification or, in some cases, renegotiationadjustment if certain corporate or other transactions occur. Accordingly, these transactions may not operate as we intend if we are required to adjust their terms as a result of transactions in the future or upon unanticipated developments that may adversely affect the functioning of the capped call transactions.

We will be required to record a greater amount of non-cash interest expense in current and future periods as a result of the amortization of the debt issuance costs for the Convertible Notes. We will report lower net income (or greater net loss) in our financial results because the application of generally accepted accounting principles in the United States (“GAAP”) requires interest to include both the current period’s amortization of the debt issuance costs and the instrument’s coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.

Certain provisions in the indenture governing the Convertible Notes could make a third-party attempt to acquire us more difficult or expensive. For example, if a takeover constitutes a fundamental change, then noteholders will have the right to require us to repurchase their notes for cash. In addition, if a takeover constitutes a make-whole fundamental change, then we may be required to temporarily increase the conversion rate. In either case, and in other cases, our obligations under the notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us or removing incumbent management,us, including in a transaction that noteholders or holders of our common stock may view as favorable.

In addition, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the U.S. For example, in June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the natural gas and oil sector to reduce methane gas and VOC emissions. In December 2023, the EPA finalized more stringent methane rulesrules, later published in March 2024, for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. Notably, the EPA updated the applicability date for certain requirements to a construction date of December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. Under the final rules, which went into effect in May 2024, states have until March 2026 to prepare and submit their plans to impose methane emission controls on existing sources and those existing sources themselves have until 2029 to comply. The presumptive standards established under the final rule are generally the same for both new and existing sources. The requirements include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems and zero-emission requirements for certain devices. The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. However, in March 2025, the EPA announced its intention to reconsider the March 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026. A subsequent rule finalized on November 26, 2025 gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. Fines and penalties for violation of these rules can be substantial. However, the final rule and its requirements are currently subject to legal challenges but remain in effect. Further, in September 2021, the Biden Administration publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions by at least 30% below 2020 levels by 2030. However, in January 2025, President Trump issued executive orders directing (i) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources and (ii) the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change, including the Global Methane Pledge. Consequently, future implementation and enforcement of the final methane rule remains uncertain at this time. To the extent that future legislative or regulatory changes impose more restrictive requirements pertaining to permitting, GHG emissions, financial assurance and bonding for decommissioning liabilities, or carbon taxes, such actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements. While the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives are expected to continue. Consequently, legislation and regulatory programs to address climate change or reduce emissions of GHGs could have a material adverse effect on our business, financial condition or results of operations.

We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. AtAs of December 31, 2024,2025, we had an estimated NOL carryforward of approximately $447.2$532.8 million for U.S. federal income tax purposes. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income. We underwent an “ownership change” during 2018 and, as a result, the use of $121.7 million of our existingremaining NOL carryforwards is subject to limitations under Section 382, which are generally determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382 of the IRC. See Note 10 to our financial statements. Future changes in our stock ownership, some of which are outside of our control, could result in an additional ownership change under Section 382 of the IRC.

From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in recent federal tax legislation such as the IRA,legislation, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

On August 16, 2022, the IRA was signed into federal law. The IRA provides for, among other things, a new U.S. federal 1% excise tax on certain repurchases (including redemptions) of shares by publicly traded domestic (i.e., U.S.) corporations and certain domestic subsidiaries of publicly traded foreign corporations occurring after December 31, 2022. The excise tax is imposed on the repurchasing corporation itself, not its shareholders from which shares are repurchased. The amount of the excise tax is generally 1% of the fair market value of the shares repurchased at the time of the repurchase. However, for purposes of calculating the excise tax, repurchasing corporations are permitted to net the fair market value of certain new share issuances (including those to employees) against the fair market value of shares repurchases during the same taxable year. In addition, certain exceptions apply to the excise tax. On December 27, 2022, the U.S. Department of the Treasury (the “Treasury”) issued a notice that it intends to publish proposed regulations addressing the application of the excise tax (the “Notice”). To provide taxpayers with interim guidance, the Notice describes certain rules upon which taxpayers are generally entitled to rely until publication of the proposed regulations.

Whether and to what extent we are subject to the excise tax in connection with repurchases of our shares depends on a number of factors, including (i) the fair market value of the repurchase,repurchase (ii)and the nature and amount of any equity issuances within the same taxable year of the repurchase, and (iii) the content of any future regulations and other guidance issued from the Treasury.repurchase. Any excise tax will cause a reduction in our cash available on hand, which could have a negative impact on our business and operations.

Our derivativederivatives activities expose us to potential regulatory risks.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) contains measures aimed at increasing the transparency and stability of the over-the-counter derivatives market and preventing excessive speculation. On January 14, 2021, the CFTC published a final rule imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents, though certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC’s requirements for certain enumerated “bona fide” hedging transactions and positions. The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns ten percent or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs ofof, transactions. Moreover, such changes couldand/or materially reducereducing our access toto, derivative opportunities,transactions, which could adversely affect revenues orand cash flow during periods of low commodity prices.flow.

Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge, regardless of whether we were responsible for the release or contamination and regardless of whether our operating partners met previous standards in the industry at the time they were conducted. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of operations on our properties. The application of new or more stringent environmental laws and regulations to our business may cause us to curtail production or increase the costs of our production, development or exploration activities.

•Proved reserves of 378.5384.1 MMBoe at year-end, ana 11%1% increase compared to year-end 20232024

•Provided returns to shareholders totaling approximately $256.5$230.4 million, comprised of $162.0$173.4 million in common stock dividend payments and $94.5$57.0 million in repurchases of common stock.stock

•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.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.

•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, franchise taxes, 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 and bond premiums (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 $702.7 million in the year ending December 31, 2025. The Company did not have any ceiling test impairment charges for the years ended December 31, 2024 and 2023. Average commodity prices have declined in recent months. If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record aan additional non-cash ceiling test impairment of its oil and gas property costs in future periods.

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 2024 was $3.88 per barrel, as compared to $2.83 per barrel in 2023. Our net average realized gas price during 2024 was $2.24 per Mcf, representing a 93% realization relative to the average NYMEX Henry Hub pricing, compared to a net average realized gas price of $2.98 per Mcf during 2023, which represented 112% realization relative to average NYMEX Henry Hub pricing. Fluctuations in our oil and 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. SinceDuring 2021, we have observed inflationary pressures on drilling2025 and other operating costs due to various factors, such as higher commodity prices, labor shortages, supply chain disruptions and other factors. During 2024 and 2023,2024, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.4$10.2 million and $9.5$9.4 million, respectively.

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. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

For 2024,2025, the average NYMEX WTI pricing was $75.76$64.73 per barrel of oil, or 2%15% lower than the $77.61$75.76 average pricing in 2023.2024. Our average realized oil price before reflecting settled oil derivatives was $71.59$59.20 per barrel of oil in 2024,2025, as compared to $74.78$71.59 in 2023.2024. Our average realized oil price after reflecting settled oil derivatives was $71.48$64.35 per barrel of oil in 2024,2025, as compared to $73.88$71.48 in 2023,2024, representing a 3%10% decline year-over-year. The lower average realized oil price in 20242025 iswas principally due to a 15% lower average NYMEX WTI benchmark price in 20242025 compared to 2023,2024, partially offset by ahigher lower average lossgains on settled oil derivatives.

For 2024,2025, the average NYMEX Henry Hub pricing for natural gas was $2.41$3.62 per MMbtu, or 9%50% lowerhigher than the $2.66$2.41 per MMbtu price in 2023.2024. Our average realized natural gas price before reflecting settled natural gas derivatives was $2.87 per Mcf in 2025, as compared to $2.24 per Mcf in 2024, as compared to $2.98 per Mcf in 2023.2024. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.32 per Mcf in 2025, as compared to $3.00 per Mcf in 2024, as compared to $3.90 per Mcf in 2023, representing aan 23%11% declineincrease year-over-year. The lowerhigher average realized natural gas price in 20242025 is due to both a lowerhigher average NYMEX Henry Hub benchmark priceprice, andpartially offset by lower gaingains on settled natural gas derivatives in 20242025 compared to 2023.2024.

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2024,2025, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increaseddecreased 13%by 3% from 2023,2024, driven by a 26% increase in production volumes, partially offset by a 10%14% decrease in realized prices on a per Boe basis, excluding the effect of settled commodity derivatives.derivatives, partially offset by a 9% increase in production volumes. The lower average realized price in 20242025 as compared to 20232024 was driven primarily by lower average NYMEX oil and natural gas prices in 20242025 as compared to 2023,2024, in addition to higher average oil price differentialsdifferentials, partially offset by higher realized gas and lowerNGL gas price realizations to the NYMEX average natural gas priceprices in 20242025 as compared to 2023.2024. Oil price differentials during 20242025 averaged $3.88$5.53 per barrel, as compared to $2.83$3.88 per barrel in 2023. Gas price realizations in 2024 averaged 93% of the NYMEX average gas price, as compared to 112% in 2023 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. Our substantial acquisition activities in 2024 and 2023 (see Note 3 to our financial statements) helped drive the 26% increase in production levels in 2024 as compared to 2023. In addition, the number of net wells we added to production (excluding acquisitions) increased by 18% in 2024 as compared to 2023, due to our growing organic acreage footprint and increased development on our properties.2024.

For 2024,2025, we realized a gain on settled commodity derivatives of $83.2$201.3 million, compared to a $57.9$83.2 million gain in 2023.2024. The increased gain on settled derivatives was primarily due to a decrease in the average NYMEX oil and continued depressed NYMEX gas price in 20242025 compared to 2023.2024. The average NYMEX oil price for 20242025 was $75.76$64.73 per barrel, compared to $77.61$75.76 per barrel for 2023. Further, the average NYMEX Henry Hub gas price for 2024 was 2.41 per Mcf, compared to 2.66 per Mcf for 2023.2024.

During 2023,2024, our derivative settlements included 8.110.5 million barrels of oil subject to swaps at an average settlement price of $75.19$74.93 per barrel, and we had an additional 6.38.9 million barrels of oil hedged subject to collars. Additionally, during 2023,2024, our derivative settlements included 33.841.7 million MMBtu of natural gas subject to swaps at an average settlement price of $3.95$3.50 per MMBtu, and we had an additional 20.029.6 million MMBtu of gas hedged subject to collars. Our average realized price (including all commodity derivative cash settlements) in 20242025 was $49.21$44.82 per Boe compared to $54.22$49.21 per Boe in 2023.2024. The gain on settled commodity derivatives increased our average realized price per Boe by $1.83$4.08 and $1.61$1.83 in 20242025 and 2023,2024, respectively. The percentage of oil production hedged under our derivative contracts was 73%77% and 65%73% in 20242025 and 2023,2024, respectively.

The Company had unsettled commodity derivative lossesgains of $179.3 million in 2025, compared to a loss of $21.3 million in 2024, compared to a gain of $201.3 million in 2023.2024. Our derivatives are not designated for hedge accounting and 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 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 December 31, 2024,2025, all of our derivative contracts were recorded at their fair value, which was a net liabilityasset of $57.2$121.6 million, a change of $21.0$178.8 million from the $36.2$57.2 million net liability recorded as of December 31, 2023.2024. The increasechange in the netfair liabilityvalue atof Decemberour 31,derivative 2024contracts as compared to December 31, 2023year-over-year was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2023.2024. Our open commodity derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Production expenses were $473.7 million in 2025, compared to $429.8 million in 2024, compared to $347.0 million in 2023.2024. On a per unit basis, production expenses decreasedincreased 2%, from $9.62 per Boe in 2023 to $9.46 per Boe in 2024,2024 to $9.61 per Boe in 2025, primarily due to higher productionworkover volumescosts in 2024.2025. On an absolute dollar basis, production expenses increased 24%10% in 20242025 compared to 2023,2024, primarily due to a 26%9% increase in production volumes partially caused by an 18% increase in net wells.volumes.

General and administrative expenses were $61.3 million for 2025, compared to $50.5 million for 2024, compared to $46.8 million for 2023.2024. The increase in 20242025 compared to 20232024 was driven in part by an increase in professional fees and employee compensation costs to support the Company’s growth,growth and higher acquisition-related costs, partially offset by lower acquisition-relatedprofessional costs.fees.

Depletion, depreciation, amortization and accretion (“DD&A”) was $814.9 million in 2025, compared to $740.9 million in 2024, compared to $486.0 million in 2023.2024. The aggregate increase in DD&A expense for 20242025 compared to 20232024 was driven by a 26%9% increase in production levels and a 21%1% increase in the depletion rate per Boe. The increase in depletion rate per Boe for 2024 as compared to 2023 was primarily due to a significant increase to our depletable cost base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our financial statements). The following table summarizes DD&A expense per Boe for 20242025 and 20232024:

Interest expense, net of capitalized interest, was $172.4 million in 2025, compared to $157.7 million in 2024, compared to $135.7 million in 2023.2024. The increase in interest expense forin 20242025 as compared to 20232024 was primarily due to higher levelsoutstanding borrowings under the Revolving Credit Facility, through the first half of debt pursuant to borrowings2025, to fund the Company’s acquisitionacquisitions activities that occurred in the latter part of 2024. See Note 3 for further information.

During 2024,2025, we recorded income tax expense of $160.5$23.9 million related to federal and state income taxes, as compared to $77.8$160.5 million in 2023.2024. The effective tax rate for 2024 was 23.6% compared to an effective tax rate of 7.8% for 2023. The increasedecrease in income tax expense in 20242025 is primarily due to lower book income in 2025 as compared to 2024. In addition, the releaseenactment of ourthe valuationOne allowanceBig duringBeautiful Bill Act in July 2025, which reinstated the second100% quarteradditional first-year “bonus” depreciation deduction, provided favorable updates to the calculation of 2023.disallowed interest, and to the determination of whether the Company is subject to the Corporate Alternative Minimum Tax.

We completed over $883.5$333.5 million in substantial bolt-on acquisitions that closed during 20242025 (see Note 3 to our financial statements). We financed these acquisitions with a combination of debt issuances, credit facility borrowings, equity consideration and internally generated cash flow from operations.

As of December 31, 2024,2025, we had outstanding total debt of $2,423.2 million consisting of $690.0$478.0 million of borrowings under our Revolving Credit Facility, $705.1$20.2 million aggregate principal amount of our Senior Notes due 2028 (as defined herein), $700.0 million aggregate principal amount of our Convertible Notes (as defined herein), $500.0 million aggregate principal amount of our 8.750% senior notes due 2031 (the “Senior Notes due 2031”) (as defined herein), and $725.0 million aggregate principal amount of our Senior Notes due 2031 (as defined herein), and $500.0 million aggregate principal amount of our Convertible Notes due 20292033 (as defined herein).

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. At December 31, 2024,2025, we had a working capital deficitsurplus of $43.5$46.7 million, compared to a surplusdeficit of $123.6$43.5 million at December 31, 2023.2024. Current assets decreasedincreased by $8.7$85.3 million and current liabilities increaseddecreased by $158.5$5.0 million at December 31, 2024,2025, as compared to December 31, 2023.2024.

The $8.7$85.3 million decreaseincrease in current assets in 20242025 as compared to 20232024 was primarily driven by a $29.2$120.2 million decreaseincrease in derivative instruments andinstruments, a $36.9$17.7 million decreaseincrease in advances to operators, and a $7.2 million increase in cash and other current assets, partially offset by a $19.1$39.7 million increasedecrease in accounts receivable and a $34.8$20.0 million increasedecrease in income tax receivable.

The $158.5$5.0 million increasedecrease in current liabilities in 20242025 as compared to 20232024 was primarily due to a $155.6$19.9 million decrease in derivative instruments and $3.0 million decrease in accrued interest, partially offset by a $17.9 million increase in accounts payablepayable, accruals and accruedother liabilities,current primarily as a result of increased development activity, and a $3.1 million increase in derivative instruments.liabilities.

Our cash flowssummary for the years ended December 31, 20242025 and 20232024 areis presented below:

Net cash provided by operating activities in 20242025 was $1.4$1.5 billion, compared to $1.2$1.4 billion in 2023. This increase was driven by an increase in production volumes, partially offset by lower average realized commodity prices and higher operating and interest costs.2024. Net cash provided by operating activities is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the year ended December 31, 20242025 was a deficitsurplus of $53.9$70.1 million compared to a deficit of $106.1$53.9 million in 2023.2024.

Net cash provided by financing activities was $266.8 million and $684.7 million forIn the yearsyear ended December 31, 20242024, andour 2023,financing respectively.activities resulted in net cash provided of $266.8 million. The cash provided by financing activities in 2024 was primarily related to $984.0 million in increased borrowings under our Revolving Credit Facility, partially offset by $455.0 million in repayments of borrowing under our Revolving Credit Facility, $94.5 million in repurchases of common stock, and $162.0 million in dividend payments to holders of our common stock.

We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”). 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. Subsequent to December 31, 2025, 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 elected commitment amount was increased from $1.6 billion to $1.8 billion. As of December 31, 2024, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.5 billion, and2025, we had $690.0$478.0 million in borrowings outstanding under the facility, leaving $810.0approximately million$1.3 billion in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.

As of December 31, 2024,2025, we had outstanding $705.1$20.2 million aggregate principal amount of our Senior Notes due 2028. See Note 4 to our financial statements for further details regarding the Senior Notes due 2028. Subsequent to December 31, 2025, in February 2026, we gave notice to the holders of the Senior Notes due 2028 (the “Notice of Full Redemption”) that we elected to redeem all of the outstanding Senior Notes due 2028, in accordance with the terms of the 2028 Notes Indenture. Pursuant to the Notice of Full Redemption, the Redemption Date is March 4, 2026, and the Redemption Price is 100%.

ConvertibleSenior Notes due 20292033

As of December 31, 2024,2025, we had outstanding $500.0$725.0 million aggregate principal amount of our ConvertibleSenior Notes.Notes due 2033. See Note 4 to our financial statements for further details regarding the ConvertibleSenior Notes.Notes due 2033.

Contractual and Other Obligations. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 4 to our financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 12 to our financial statements. We have firm commitments on certain assets that we assumed in our April 2021 acquisition of natural gas properties in the Appalachian Basin. See “Item 2—Properties—Delivery Commitments” above. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments. Further, we have contractual commitments under a Joint Development Agreement with an unaffiliated operator to develop certain oil and natural properties in Appalachia. See Note 8 to our financial statements.

ThereExcept as described below, there have been no material changes to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K filed with the SEC for the period ended December 31, 2025.

•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;

•the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuance,issuances, including counterparty risk;

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 withinin theNorth United States.America. Using this strategy, we had participated in 12,15312,507 gross (1,303.91,369.7 net) producing wells as of MarchJune 31,30, 2026. As of MarchJune 31,30, 2026, we had leased approximately 335,050414,787 net acres, of which approximately 81%71% were developed and all were located in the United States.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 firstsecond quarter of 2026 was approximately 148,303145,659 Boe per day, of which approximately 50%47% was oil. This was a 10%9% increase in production compared to the firstsecond quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and six months ended MarchJune 31,30, 2026, we added 17.112.7 and 29.8 net wells to production.production, respectively.

Our weighted average percentage of production volumes by basin for the three months ended MarchJune 31,30, 2026 and 2025 were as follows:

•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 threesix months ended MarchJune 31,30, 2026. The Company did not have any ceiling test impairment charge forin the three months ended MarchJune 31,30 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 declinedfluctuated significantly in recent quarters. If thissuch downwardprices trend continues,downward, and/or if our proved reserves decrease significantly in 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 includesincludes, bothfederal, federalstate and stateforeign taxes. We record our federal 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.

•our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and

•the level of our operating expenses.expenses; and

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, AppalachianAppalachian, Uinta and UintaDuvernay 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.

Our average oil price differential to the NYMEX WTI benchmark price during the three months ended March 31, 2026 was $5.85 per barrel, as compared to $5.79 per barrel for the three months ended March 31, 2025. Our net average realized gas price in the three months ended March 31, 2026 was $2.50 per Mcf, representing a 72% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $3.86 per Mcf in the three months ended March 31, 2025, which represented a 100% realization relative to the average NYMEX Henry Hub pricing. 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 factorsfactors, such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant used. During the threesix months ended MarchJune 31,30, 2026 and 2025, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.3$10.4 million and $10.5$10.0 million, respectively.

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, duringin Marchearly 2026, a significant increaseincreases 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 reachingpeaking 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 quarterhalf 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.

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 MarchJune 31,30, 2026 and 2025.

We have entered into derivatives contracts to hedge commodity price riskrisks on a portion of our future expected oil and natural gas production. For a summary as of MarchJune 31,30, 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.

Results of Operations for the Three Months Ended MarchJune 31,30, 2026 and MarchJune 31,30, 2025

In the firstsecond quarter of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $539.9$670.8 million, compared to $577.0$574.4 million in the firstsecond quarter of 2025. TheIn decreasethe 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 was(see primarilyNote driven2 byto aour 15%condensed decreaseconsolidated infinancial weighted average realized prices, partially offset by a 10% increase in production volumes.statements).

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 10%9% increase in production volumes in the firstsecond quarter of 2026 compared to the same period of 2025.

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 lossgain of $539.1$70.2 million in the firstsecond quarter of 2026, compared to a gain of $21.8$128.8 million in the firstsecond 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 firstsecond quarter of 2026, we realized a loss on settled commodity derivatives of $17.6$86.3 million, compared to a gain of $12.1$60.9 million in the firstsecond quarter of 2025. ForWe incur realized losses on settled commodity derivatives when the firstaverage quartercommodity ofmarket 2026,price at settlement is higher than our average hedge book price. Conversely, we realizedincur agains losswhen onthe average commodity market price at settlement is lower than our unsettledaverage commodityhedge derivativebook of $521.4 million, compared to a gain of $9.7 million in the first quarter of 2025.price.

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 MarchJune 31,30, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $398.2$240.3 million, a change of $519.9$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 MarchJune 31,30, 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 were $129.7$127.1 million in the firstsecond quarter of 2026, compared to $114.0$121.4 million in the firstsecond quarter of 2025. On a per unit basis, production expenses were $9.72$9.59 per Boe in the firstsecond quarter of 2026 compared to $9.39$9.95 per Boe in the firstsecond quarter of 2025. The increasedecrease in our production expenses per unit in the firstsecond quarter of 2026 compared to the firstsecond quarter of 2025 was primarily due to higher processingproduction chargesvolumes incurredin the second quarter of 2026 as compared to processthe oursame naturalperiod gasin and NGL production volumes.2025.

We pay production taxes based on realized oil and natural gas sales. Production taxes were $38.3$45.7 million in the firstsecond quarter of 2026, compared to $36.1$35.6 million in the firstsecond quarter of 2025. As a percentage of oil and natural gas sales, our production taxes were 7.1%6.8% and 6.3%7.2% in the firstsecond quarter of 2026 and 2025, respectively.

General and administrative expenses were $23.2$24.5 million in the firstsecond quarter of 2026, or $1.74$1.85 per Boe, compared to $14.5$15.6 million in the firstsecond quarter of 2025, or $1.19$1.28 per Boe. The increase was primarily driven by higherthe $7.6 million transaction costs recorded for the acquisitionDuvernay of the Utica Assets,Acquisition, which was accounted for as a business combination (see Note 3 to our condensed consolidated financial statements).

Depletion, depreciation, amortization and accretion (“DD&A”) was $197.1$192.9 million in the firstsecond quarter of 2026, compared to $205.7 million in the firstsecond quarter of 2025. Depletion expense, the largest component of DD&A, decreased by $8.7$13.0 million in the firstsecond quarter of 2026 compared to the firstsecond 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 $14.67$14.45 per Boe in the firstsecond quarter of 2026 compared to $16.84$16.76 per Boe in the firstsecond quarter of 2025. Depreciation, amortization and accretion was $1.3 million and $1.1$1.2 million in the firstsecond quarter of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the firstsecond quarter of 2026 and 2025:

In the first quarter of 2026, theThe Company recorded a non-cashan impairment charge of $268.3$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 firstsecond quarter of 2025.2026.

Interest expense, Net was $42.6$41.4 million in the firstsecond quarter of 2026 compared to $43.4$44.4 million in the firstsecond quarter of 2025. The decrease was primarily due to lower weighted average levelsborrowing of debtrates, pursuant to the repurchase and redemptionrefinancing 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).