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

■political and economic conditions, including embargoes, in oil-producing countries such as Venezuela or affecting other oil-producing activity;

These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices. A substantial or extended decline in oil or natural gas prices,prices suchhas asin the significant and rapid decline that occurred in 2020, haspast resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent oil and natural gas prices received from production are insufficient to fund planned capital expenditures, we may be required to reduce spending or borrow or issue additional equity to cover any such shortfall. Lower oil and natural gas prices may limit our ability to comply with the covenants under our Revolving Credit Facility or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.

In addition, fluctuations in oil and natural gas prices have impacted unit-basedequity-based compensation expense for our Predecessor for prior periods and may impact our stock-based compensation expense. For example, in prior periods we have experienced increases to our unit-basedequity-based compensation expense primarily due to increased oil and natural gas prices causing the estimated fair value of the liabilities associated with such unit-basedequity-based compensation to increase, which contributed to net losses recorded during such periods. As a result of the foregoing and other factors, we may continue to incur net losses in the future.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. We have added significant net wells and production from wellbore-only acquisitions, where we don’t hold the underlying leasehold interest that would entitle us to participate in future wells. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.

The DAPL, a major pipeline transporting oil from the Williston Basin, is subject to ongoing litigation that could threaten its continued operation. In July 2020, a federal district court vacated the DAPL’s easement to cross the Missouri River at Lake Oahe and ordered the pipeline be shut down pending the completion of an EIS to determine whether the DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The shut-down order was later reversed on appeal and the DAPL currently remains in operation while the Corps completes the EIS, a draft of which was completed and published for public comment in 2023, The Corps has delayed the release of the final EIS, which is now expected in 2025. Following completion of the EIS, the Corps will issue a final decision whether to grant the DAPL an easement to cross the Missouri River at Lake Oahe or to require the abandonment, removal, or reroute of that section, effectively shutting down the pipeline. Moreover,The shut-down order was later reversed on appeal, and in December 2025, the Corps issued a final EIS concluding that the Corps’ preferred alternative is that the Corps reissue its easement to DAPL subject to additional easement conditions. The Corps is expected to issue a Record of Decision in early 2026 and the DAPL currently remains in operation. However, the EIS or the Corps’ decision with respect to an easement may subsequently be challenged in court. In the interim, the Standing Rock Sioux Tribe has filed suit challengingchallenged the continued operation of the DAPL without the easement.easement in federal court. The district court dismissed Standing Rock’s lawsuit, but Standing Rock has appealed that dismissal to the D.C. Circuit Court of Appeals. As a result, a shut-down remains possible, and there is no guarantee that the DAPL will be permitted to continue operations following the completion of the EIS.operations. 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.

Seasonal weather conditions can limit drilling and completion activities, selling oil and natural gas, and other operations in some of our operating areas. In the Williston Basin, and in other areas in which our interests are located, drilling and other oil and natural gas activities on our properties can be adversely affected during the winter months by severe winter weather and drilling on our properties is generally performed during the summer and fall months. These seasonal constraints can pose challenges for meeting well drilling objectives and increase competition for equipment, supplies and personnel during the summer and fall months, which could lead to shortages and increase costs or delay operations. Additionally, many municipalities impose weight restrictions on the paved roads that lead to jobsites due to the muddy conditions caused by spring thaws. This could limit access to jobsites and our and our operators’ ability to service wells in these areas.

Prior to the Lucero Acquisition, we have only participated in wells operated by third parties and following the Lucero Acquisition, ourOur business continues to be a predominantly non-operated business model. The success of our business operations depends on the timing of drilling activities and success of our third-party operators. If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operations would be adversely affected.

An increase in oil and natural gas prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies. Global, industry-wide supply chain disruptions have resulted in shortages in labor, materials and services from time to time. Such shortages have resulted in inflationary cost increases for labor, materials and services and could cause future costs to increase as well as scarcity of certain products and raw materials. To the extent inflation is elevated, our operators may experience further cost increases for their operations, including oilfield services, labor costs, and equipment if drilling activity in our operators’ areas of operations increases. In addition, there is currently significant uncertainty about the future relationship between the United States and various other countries, with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Tariffs, if enacted, and any further legislation or actions taken by the U.S. federal government that restrict trade, such as trade barriers, and other protectionist or retaliatory measures taken and measures taken by other countries in response could increase the cost of operations. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operators’ ability to conduct desired or expected operations. In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing oil and natural gas prices as producers seek to increase production in order to capitalize on higher oil and natural gas prices. In situations where cost inflation exceeds oil and natural gas price inflation, our profitability and cash flow, our and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in drilling or significant increase in drilling costs could reduce our revenues and profitability.

We intend to continue to expand our operations in part through acquisitionsacquisitions, such as the Lucero Acquisition. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential recoverable reserves. On-site inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an on-site inspection is undertaken. Any acquisition involves other potential risks, including, among other things:

We may not be able to integrate the acquired assets into our existing business in an efficient and effective manner or achieve the anticipated benefits of acquisitions such as the Lucero Acquisition.acquisitions. We may not be able to accomplish this integration process successfully. The successful acquisition of properties requires an assessment of several factors, including:

Our oil and natural gas properties are focused on the Williston Basin, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our oil and natural gas properties are not aswidely diversified geographically as some of our competitors,geographically, our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.

U.S. and global markets aremay experiencingexperience volatility and disruption followingas thea escalationresult of certain economic and geopolitical tensions,conditions, including the ongoing military conflict between Russia and Ukraine andUkraine, hostilities in the Middle East.East and the evolving situation in Venezuela. Although the length and impact of thesesuch ongoing conflictsconditions are highly unpredictable, thethese conflictsgeopolitical intensions Ukrainehave, and insuch theconditions Middlemay Eastcontinue haveto, ledlead to market disruptions, including significant volatility in oil and natural gas prices, credit and capital markets, as well as supply chain disruptions. These disruptions have caused, and could continue to cause, significant volatilityVolatility in energy prices,prices whichresulting from such disruptions could have a material effect on our business.

Prolonged unfavorable economic conditions or uncertainty as a result of these conflictsconditions may adversely affect our business, financial condition, and results of operations. Any of the foregoing may also magnify the impact of other risks described in this Annual Report on Form 10-K.

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that we,We, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. Furthermore, various third-party resources that we rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyber-attacks or similar events that are entirely outside our control, and any such events could significantly disrupt our business operations or have a material adverse effect on our results of operations. ToAs of the date of this Annual Report on Form 10-K, to our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future.

Our business could also be impacted by governmental initiatives to encourage the conservation of energy or the use of alternative energy sources. InFor addition,example, the IRA includesincluded a variety of clean-energy tax credits and establishesprovided asignificant programfinancial designedsupport tofor reduce methane emissions from oil and gas operations. These initiativesalternative or similarlower stateGHG-emitting energy production. While the OBBBA eliminated the funding for the majority of the IRA’s incentive programs, any new federal or federalstate initiatives to reduce energy consumption or encourage a shift away from fossil fuels could reduce demand for hydrocarbons and have a material adverse effect on our earnings, cash flows and financial condition. Whether,Though theit extentpresently to which, or howappears the Trump Administration or Congress will continuenot orimplement reverseany coursesuch on governmental initiatives like these cannot be predicted at this time, though the Trump Administration has indicated it will seek to remove support for such. Regardless of federal support,initiatives, states and municipalities may continue to encourage and implement decarbonization measures.measures and future federal administrations or legislatures could reintroduce such.

Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Some organizations that provide information to investors on corporate governance and related matters have developed ratings for investment and voting decisions. While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings and recent activismActivism directed at shifting funding away from companies with energy-related assets could also lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates may continue to rise in the near term, increasing the cost of borrowing, 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 aAny reduction of available capital funding for potential development projects, furtherincluding impactingoil and gas infrastructure projects upon which the operations on our properties rely, could adversely impact our future financial results.

Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, increasing mandatory ESG disclosures, and increasing consumer demand for alternatives to oil and natural gas may result in increased costs, reduced demand for our products, reduced profits, increased administrative, legislative, and judicial scrutiny, reputational damage, and negative impacts on our access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that the Company could be subject to additional governmental investigations, private litigation or activist campaigns as stockholders may attempt to effect changes to the Company’s business or governance practices. Moreover, any new regulations or initiatives related to the disclosure of climate- or ESG-related risks could lead to reputational or other harm with customers, regulators, lenders, investors or other stakeholders and could also increase litigation risks.

While we may elect to pursue certain ESG strategies in the future, any such goals or commitments are aspirational and may not have the intended impact on our business. We may also receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals,goals or commitments, but we cannot guarantee that we will be able to pursue or implement such goals or commitments because of potential costscosts, inaccurate assumptions or technical or operational obstacles. Moreover, failure or a perception (whether or not valid) of failure to pursue or implement ESG strategies or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us, and negatively impact our operations. Additionally, to the extent ESG-related matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. ESG-related matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.

Also, institutionalcertain lendersfinancial institutions may, of their own accord, decide not to provide funding or insurance for fossil fuel energy companies or related infrastructure projects based on climate or other ESG-related concerns, which could affect our access to capital for potential growth projects.projects, In March 2024, the SEC finalized rules mandating extensive disclosure of climate risks for certain registrants. In March 2024, the SEC finalized rules mandating extensive disclosure of climate risks for certain registrants. However, the future of the rule is uncertain atthough this time given that its implementationtrend has beenwaned stayedin pendingrecent theyears. outcomeAny ofmaterial legal challenges. Moreover, on February 11, 2025, SEC Acting Chairman Mark T. Uyeda requested that the U.S. Court of Appeals for the Eighth Circuit not schedule argumentreduction in the casecapital whileavailable to the SECfossil reconsidersfuel theindustry finalizedcould rules.make Whileit themore SEC, under the new presidential administration, may seekdifficult to repealsecure orfunding otherwisefor modifyexploration, thedevelopment, rules,production, wetransportation, cannotand predictprocessing whetheractivities, such action will occur or its timings. Enhanced climate disclosure requirementswhich could resultimpact inour additional legalbusiness and accounting costs and accelerate the trendresults of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. States may pass laws imposing more expansive disclosure requirements for climate-related risks.operations. New laws, regulations, or enforcement initiatives related to the disclosure of climate-related risks could lead to reputational or other harm with customers, regulators, lenders, investors or other stakeholders and could also increase litigation risks. Any material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and results of operations.

Separately,Certain existing public and governmental authorities, as well as other parties, have also heightened scrutiny around climate-change related disclosures in public filings. For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including greenwashing (i.e., misleading informationemployment or false claims overstating potential benefits). Certain regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals or standards were misleading, false or otherwise deceptive. Certain employmentbusiness practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Company’s environmental or social commitments (such as reducing GHG emissions) or its pursuit of certain employment or business practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Company’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties.

Holders of our common stock are only entitled to receive such cash dividends as our Board, in its sole discretion, may declare out of funds legally available for such payments. We paid cash dividends of $63.6$92.1 million, $58.0$63.6 million and $36.0$58.0 million to our equity holders during the years ended December 31, 2024,2025, 20232024 and 2022,2023, respectively. We cannot assure you that we will pay dividends in the future. Any future determination relating to the payment of dividends will be dependent on a variety of factors, including any limitations imposed by covenants in the Revolving Credit Facility and any debt agreements that we may enter into in the future. Under ourthe Revolving Credit Facility, we are permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) our total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500$500.0 million,million (2) our then-effective borrowing base, and (3) the then-effective aggregate amount of our lenders’elected commitments and (b) as of the date of such distribution, the EBITDAX Ratio does not exceed 1.50 to 1.00. If ourthe EBITDAX Ratio exceeds 1.50 to 1.00, but does not exceed 2.25 to 1.00, and if our total outstanding credit usage does not exceed 80% of the Commitments, we may also make distributions if our distributable free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and we have delivered a certificate to our lenders attesting to the foregoing. The summaries above do not purport to be completecomplete. and you are encouraged to read theThe Revolving Credit Facility, whichFacility is filed as an exhibit to this Annual Report on Form 10-K, for greater detail with respect to these provisions.10-K. As a consequence of these various limitations and restrictions, we may not be able to make, or may have to reduce or eliminate at any time, the payment of dividends on our common stock. If as a result, we are unable to pay dividends, investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Any change in the level of our dividends or the suspension of the payment thereof could have a material adverse effect on the market price of our common stock. For additional information, please see —Risks Relating to Our Common Stock—. Although we expect to continue to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock.

Additionally, oil and natural gas operations and related infrastructure projects on federal lands mayare bealso impacted by recent and ongoing revisionssubject to the NEPA implementing regulations.NEPA. NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs (“BIA”), to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. NEPA’sFor implementingmany regulations,years, asthe promulgatedNEPA process has followed regulations issued by the CEQ,CEQ. have been subject to multiple revisionsHowever, in recentJanuary years2026, betweenCEQ theissued Trumpa andfinal Bidenrule Administrations.rescinding CEQ’s latest revisions under the Biden Administration expanded requirements to analyze the cumulative effects of the project on climate change and consider any disproportionate impact of the project on communities with environmental justice concerns as well enhance certain project obligations for implementing environmental mitigation measures. However, theseits regulations were vacated in February 2025 byfollowing a federal district court and the Court of Appeals for the D.C. Circuit recentlydecision heldlimiting similarly that CEQ does not haveCEQ’s authority to issuepromulgate bindingsuch. Further, the U.S. Supreme Court’s recent Seven County decision directed lower courts to give substantial deference to the reviewing agency’s scoping decisions in NEPA regulations.reviews. The ultimate consequences of thisthese judicial decisiondevelopments are not yet clear and the actions the Trump Administration may take, if any, in the aftermath of these decisions cannot be predicted at this time.clear.

The Dodd-Frank Act contains measures aimed at increasing the transparency and stability of the OTC 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” derivative transactions. The CFTC also has 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. The CFTC’s aggregation rules are now in effect, although CFTC staff has granted relief until August 12, 2025 from various conditions and requirements in the final aggregation rules.rules until the effective date of any codifying rulemaking. 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 of transactions. Moreover, such changes could materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low oil and natural gas prices.

In recent years Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. While it presently appears unlikely that comprehensive climate change legislation will be passed by Congress in the near future, certain federal laws, like the IRA, have been enacted to advance numerous climate-related objectives. TheWhile IRA contains hundredsmany of billionsthe IRA’s provisions were repealed or defunded following the change in presidential administrations and the enactment of dollarsthe OBBBA in incentives2025, forany similar or future climate-related legislation could increase costs within the developmentoil and gas industry or accelerate a transition away from fossil fuels, either of renewablewhich energy,could cleanadversely hydrogen,affect cleanour fuels, electric vehicles, supporting infrastructurebusiness and carbonresults captureof and sequestration, among other provisions.operations. Moreover, various federal agencies have adopted climate change considerations into their rulemaking and decision-making processes and have promulgated regulations that seek to restrict, monitor or otherwise limit GHG emissions. For example, in December 2023, the EPA finalized rules establishing more stringent methane and volatile organic compound emissions performance standards for oil and gas facilities. The IRA also included a first-ever fee on waste methane emissions, for which the EPA has finalizedpromulgated regulationsregulations, applicable to implement. These regulatory initiatives could increase operating costs within the oil and gas industryoperations and the IRA’s funding provisions could accelerate the transition away from fossil fuels,upon which could in turn adversely affect our business relies, that impose stringent performance standards for methane emissions, including so-called green well-completion standards, limits on venting and resultsflaring and requirements to implement enhanced leak detection and repair programs. However, there continues to be uncertainty regarding the federal regulation of operations.GHG emissions. Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several presidential administrations. The current Trump Administration announcedhas itsexpressed intenta topolicy seekpreference reversalof andlimiting eliminateor supportrescinding regulations concerning GHG emissions and, in February 2026 promulgated a final rule repealing the EPA’s 2009 “Endangerment Finding” that forms the basis under the CAA for such regulations and initiatives, though the extent to which and the timeline for doing so remains uncertain. Whether Congress elects to pursue legislation to repeal, revise, or otherwise limit the enforcement of these regulations and certainmost of the IRA’sEPA’s provisionsGHG-related rules. However, whether or how the EPA’s rescission of its “Endangerment Finding” and other such policies will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulations, cannot be predicted at this time. SeveralIn the absence of federal climate legislation, several states have also implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring, or otherwise regulating GHG emissions. State, regional, and local governments may also elect to continue to participate in international climate change initiatives, despite the current Trump Administration withdrawing the United States from the Paris Agreement and related initiatives and pledges in 2025. The participation in, or support for, climate-related policies and initiatives by politicians, regulators, financial institutions, consumers and other stakeholders could increase opposition to, reduce funding for, or lead to new restrictions on, fossil fuel development and production activities, any of which could adversely affect our financial performance. See Part I. Items 1 and 2. Business and Properties—Regulation and Environmental Matters, for additional discussion of regulatory matters affecting and resulting from risks related to climate change and GHGs.

Wells in the Williston Basin of North Dakota, where we own significant oil and natural gas properties, produce natural gas as well as oil. Constraints in third party natural gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In 2014, theThe NDIC, North Dakota’s chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDIC requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. It is possible that other states in which we operate, including Montana, will require gas capture plans or otherwise institute new regulatory requirements in the future to reduce flaring.

We could have an indemnification obligation to Jefferies in certain circumstances if the Distribution were determined not to qualify for tax-free treatment for U.S. federal tax purposes, or in certain other circumstances, which could materially adversely affect our business, financial condition and results of operations.purposes.

This section generally discusses certain 20242025 and 20232024 items and certain year-to-year comparisons between 20242025 and 2023.2024. Discussions of 20222023 items and year-to-year comparisons between 20232024 and 20222023 that are not included in this Form 10-K can be found in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023,2024, filed on FebruaryMarch 24,12, 20242025 which is incorporated herein by reference.

Our business strategy is focused on creating long-term stockholder value through the profitable acquisition, development and production of oil and natural gas assets that provide an attractive return on invested capital, while maintaining a strong balance sheet and distributing a meaningful dividend to our stockholders. We have historically investedinvest in non-operated minority working and mineral interests in oil and natural gas properties with our core area of focus currently in the Bakken and Three Forks formations of the Williston Basin of North Dakota and Montana, although we have assumed limited operations in the Williston Basin through the Lucero Acquisition.Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of December 31, 2024,2025, we had a working interest in 6,0716,402 gross (168.2226.1 net) productive wells and 248283 gross (9.76.1 net) wells that were being drilled or completed, and an additional 362336 gross (8.015.9 net) wells that had been permitted for development by us or our operators. In addition, we had a royalty only interest in 1,1801,301 gross (2.83.2 net) productive wells.

Commodity prices are a significant factor impacting our earnings, operating cash flows and our acquisition and divestiture strategy, as well as the decisions of us and our operators in conducting operations. During the last several years, prices for oil and natural gas have experienced periodic downturns and sustained volatility, impacted by thegeneral COVID-19 pandemiceconomic and recovery,political conditions, the ongoing military conflict between Russia and Ukraine, conflicthostilities in the Middle East, the evolving situation in Venezuela, supply chain constraints, elevated interest rates and costs of capital, and reductionschanges in production by OPEC and its key member, Saudi Arabia, and certain other non-OPEC oil-producing countries.

As a result of such commodity price volatility, which we expect to continue throughout 2025,2026, our earnings and operating cash flows can vary substantially. While we do hedge a substantial portion of our production, we are still significantly subject to movements in commodity prices. Such volatility can make it difficult to predict future effects on our financial results and the decisions of our operators. Factors that we expect will continue to impact commodity prices include product demand connected with global economic conditions, inflationary factors, industry production and inventory levels, the United States Department of Energy’s planned repurchases (or possible releases) of oil from the strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC and other oil-producing countries, the imposition of and changes in tariffs and other controls on imports and exports and resulting consequences,consequences of such, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty.uncertainty, including a prolonged U.S. government shutdown. Any of the foregoing can have a substantial impact on the prices of oil and natural gas, which in turn impacts our decisions and the decision of our operators to drill and extract resources.

We derive our revenues from the sale of oil and natural gas 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 production. We also entered into a number of costless collars forand natural gas in the first quarter of 2025.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.

Commodity derivatives gain (loss), net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and natural gas. Gain (loss) on commodity derivatives, net is comprised of (i1) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii2) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

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. For fiscal 2024 and 2023,2025, general and administrative expenses included non-recurring costs related to the Lucero Acquisition and an offset for reimbursement of past legal expenses as a result of the Spin-Off,settlement respectively.discussed in Note 11 (“Commitments and Contingencies”) to the Consolidated Financial Statements.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Revolving Credit Facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We do not capitalize any portion of the interest paid on applicable borrowings. We include the amortization of deferred financing costs, commitment fees and annual agency fees as interest expense.

■changes in the fairrealized valuegains ofand thelosses on our derivative instruments;

■our ability to continue to identify and acquire producing properties, high-quality acreage and drilling opportunities; and ■the level of our operating expenses.

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. Worldwide supply in terms of output, especially production from properties within the United States, the production quotas set by OPEC and certain other oil-producing countries, the conflictsconflict in UkraineUkraine, andhostilities in the Middle EastEast, the evolving situation in Venezuela and the strength of the U.S. dollar can adversely impact oil prices.

The average calendar 20242025 WTI oil price was $75.69$64.60 per Bbl or 2%15% lower than the average WTI price per Bbl in calendar 2023.2024. Our settled derivatives increased our realized oil price per Bbl by $1.54$3.81 in calendar 20242025 and increased our realized oil price per Bbl by $0.40$1.54 in calendar 2023.2024. Our average 20242025 realized oil price per Bbl after reflecting settled derivatives was $71.48$62.95 compared to $73.99$71.48 in 2023.2024. The average calendar 20242025 NYMEX natural gas price was $2.19$3.52 per MMBtu, or 13%61% lowerhigher than the average NYMEX price per MMBtu in calendar 2023.2024. Our settled derivatives increased our realized gas price per Mcf by $0.10 in calendar 2025. We had no gas price derivatives in place in calendar 2024 and 2023.2024. Our 20242025 realized natural gas price per Mcf after reflecting settled derivatives was $1.34$2.31 compared to $1.88$1.34 in 2023, which was primarily driven by lower NYMEX pricing for natural gas and gas realization.2024.

We employ a hedging program that partially mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk and NotesNote 6 (“Derivative Instruments”) to Consolidated Financial Statements—Note 6—Derivative Instruments.Statements.

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $274.0 million for the year ended December 31, 2025 from $242.0 million for the year ended December 31, 2024 from $233.9 million for the year ended December 31, 2023.2024. The increase in oil and natural gas revenue was due to a 10%34% increase in production volumes, and was partially offset by a 6%15% decrease in the average realized prices per Boe before hedging for the year ended December 31, 2024.2025. The increase in production volumes increased oil and natural gas revenue by approximately $21.3$69.2 million, while the decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $13.2$37.2 million. The increase in production volumes was in part due to the Lucero Acquisition.

The decreases in realized oil and natural gas prices were primarily due to lower benchmark commodity prices inDuring the year ended December 31, 20242025, $3.3 million and $13.6 million of recoupments of oil and gas revenue, respectively, were recognized as comparedpart of the settlement discussed in Note 11 (“Commitments and Contingencies”) to the yearConsolidated endedFinancial December 31, 2023, as well as increased differentials.Statements. Our oil price differential to the weighted average benchmark price during the year ended December 31, 20242025 was negative $5.90$5.40 per Bbl, as compared to a negative $4.19$5.90 per Bbl during the year ended December 31, 2023,2024, primarily due to the legal settlement increasing the realized price per Bbl in the period, partially offset by less favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 20242025 was $1.34$2.21 per Mcf, representing a 62%64% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $1.88$1.34 per Mcf during the year ended December 31, 2023,2024, representing a 74%62% realization relative to the weighted average NYMEX natural gas price. The higher realized price was primarily due to the legal settlement increasing the realized price per Mcf in the period. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner.

Lease Operating Expense. Lease operating expense increased to $10.92 per Boe for the year ended December 31, 2025 from $10.00 per Boe for the year ended December 31, 2024 from $9.11 per Boe for the year ended December 31, 2023.2024. The increase per Boe for the year ended December 31, 20242025 compared with the year ended December 31, 20232024 was relateddue in part to increaseda workover$1.10 operationsper andBoe higherincrease service costs. The increasedin workover costs werebetween responsibleperiods, fordriven approximately $0.10/Boe ofby the increaseproperties andfrom shouldthe resultLucero in increased production when these wells return to production.Acquisition.

Production Tax Expense. Total production taxes decreasedincreased to $23.4 million for the year ended December 31, 2025 from $21.5 million for the year ended December 31, 2024 from $21.6 million for the year ended December 31, 2023.2024. Production taxes are primarily based on oil revenue and natural gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 8.9%8.5% and 9.2%8.9% for the years ended December 31, 20242025 and 2023,2024, respectively. The lower production tax rate was driven by the production mix and the relative tax rates on oil and natural gas revenue.

DD&A. DD&A increased to $129.4 million for the year ended December 31, 2025 compared with $100.3 million for the year ended December 31, 2024 compared with $81.7 million for the year ended December 31, 2023.2024. The increase of $18.6$29.1 million or 23%29% was the result of a 10%34% increase in production and a 12%4% increasedecrease in the DD&A rate for the year ended December 31, 20242025 compared with the year ended December 31, 2023.2024. The increase in production accounted for a $8.8$32.7 million increase in DD&A expense while the increasedecrease in the DD&A rate accounted for a $9.7$3.6 million increasedecrease in DD&A expense.

For the year ended December 31, 2024,2025, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $20.92$20.16 per Boe compared with $18.68$20.92 per Boe for the year ended December 31, 2023.2024. The increaselower in the depletionDD&A rate was driven by the properties acquired in the Lucero Acquisition in 2025 and was partially offset by decreased oil and natural gas reserves related to the lower oil and natural gas prices combined with higher operating expenses and the impact of acquisitions and related capital expenditures in the year ended December 31, 2024.expenses.

Equity-based Compensation. During the year ended December 31, 2024,2025, equity-based compensation expense decreasedincreased to $8.1$10.2 million from $32.2$8.1 million during the year ended December 31, 2023.2024. Equity-based compensation expense was higher in 20232025 due to retirementadditional vestingLTIP provisionsRSUs inand somePSUs ofawarded theto awardsemployees resultingand indirectors 1,863,000at restricteda stockhigher unitsgrant beingdate expensed upon award. The retirement vesting provisions were responsible for $26.8 million of expenses during the year ended December 31, 2023.price.

Interest Expense. Interest expense increased to $10.2 million for the year ended December 31, 2025 from $10.0 million for the year ended December 31, 2024 from $5.3 million for the year ended December 31, 2023.2024. The increase for the year ended December 31, 20242025 was due to a higher SOFR interest rate in the year ended December 31, 2024 and a higher average outstandingdebt balance on our Revolving Credit Facility during the year ended December 31, 20242025 compared to 2023.2024 Thepartially higheroffset by a lower interest rate was due to increases to the federal funds rate by the Federal Reserve during the first nine months of the year ended December 31, 2024.rate.

Commodity Derivative Gain (Loss) Gain.. The net commodity derivative gain was $27.9 million for the year ended December 31, 2025 compared with a loss wasof $2.3 million for the year ended December 31, 2024 compared with a gain of $12.5 million for the year ended December 31, 2023.2024. Gain (lossLoss) on commodityCommodity derivatives, netDerivatives is comprised of (i1) cash gains and losses we recognize on settled commodity derivativesderivative instruments during the period, and (ii2) non-cash mark-to-marketunsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

At December 31, 2024,2025, all of our derivative contracts were recorded at their fair value, which was a net asset of $3.7$14.4 million, aan decreaseincrease of $7.4$10.7 million from the $11.1$3.7 million net asset recorded as of December 31, 2023,2024. whileThe a net liability of $0.2 millionincrease was recorded as of December 31, 2022. The decrease in 2024 and asset increase in 2023 wasprimarily due to changesdecreases toin forward commodity prices since December 31, 2024 relative to prices on our open commodity derivative contracts and new contracts entered into in the respective years.contracts.

Income Tax Expense. We recorded income tax expense of $9.8 million and $7.7 million for the yearyears ended December 31, 20242025 and 2024, respectively, related to federal and state income taxes. The effective tax raterates of 27.9% and 26.7% for the yearyears ended December 31, 20242025 and 2024, respectively, differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to §162(m) limitations on certain covered employee compensation andcompensation, state income taxes.taxes and non-amortizable transaction costs.

Overview. At December 31, 20242025 and 2023,2024, we had $3.0$1.3 million and $0.6$3.0 million of unrestricted cash on hand and $128.0$125.5 million and $164.0$118.0 million available under the elected commitments in our Revolving Credit Facility, respectively. We expect that our liquidity going forward will be primarily derived from cash flows from our operations, cash on hand andhand, availability under the Revolving Credit Facility and proceeds from equity or debt offerings and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements for the next twelve months, as described below, including our planned capital expenditures program, as well as dividends and our share repurchase program. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings under our Revolving Credit Facility or the issuance of equity or debt. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and dividend payments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of revenueaccrued receivables,revenue, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments.

At December 31, 2024,2025, we had a working capital deficitsurplus of $49.4$0.9 million, compared to a deficit of $2.1$49.4 million at December 31, 2023.2024. Current assets decreasedincreased by $7.4$1.3 million while current liabilities increaseddecreased by $39.9$49.1 million at December 31, 2024,2025, compared to December 31, 2023.2024. The decreaseincrease in current assets in 20242025 as compared to 20232024 was primarily due to aan decreaseincrease of $6.2$10.4 million in our commodity derivative instruments due to forward oil price decreases as compared to hedged oil prices, andpartially offset by a decrease of $5.1$9.2 million in revenue receivable primarily due to lower oil and natural gasaccrued revenue in the fourth quarter, partially offsetdriven by animproved increase in our cash balance of $2.4 million and an increase in other receivables of $1.5 million primarily related to prepayments and a higher receivable from commodity derivative instruments.collections. The increasedecrease in current liabilities in 20242025 as compared to 20232024 was primarily due to an increasedecrease of $39.8$49.1 million in accounts payable and accrued liabilities as a result of increaseddecreased development activity.

Cash Flows. Our cash flows for the years ended December 31, 2024, 20232025 and 20222024 are presented below:

During the year ended December 31, 2024,2025, we generated $155.0$170.3 million of cash from operations, an increase of 9%10% from the year ended December 31, 20232024 driven by a 3%13% increase in total revenue. During the year ended December 31, 2023, we generated $141.9 million of cash from operating activities, a 3% decrease from the year ended December 31, 2022. Cash flows from operationsoperating activities are primarily affected by production volumesvolumes, which increased with the Lucero Acquisition, 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 24 months. A minimum level of derivative coverage is required by certain debt covenants. See Part II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Cash used in investing activities during the years ended December 31, 2024, 20232025 and 20222024 was $115.3$127.7 million, $120.7 million,million and $84.6$115.3 million, respectively. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. Development costs for the year ended December 31, 2025 included $11.0 million for completion costs on two wells from the Lucero Acquisition. Our cash used in investing activities reflects actual cash spending, which can lag several months from when the related costs were accrued. As a result, our actual cash spending is not always reflective of current levels of development activity. Acquisition and development 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 financial returns. We supplement development activity on our asset base with opportunistic acquisitions of near-term drilling opportunities when development activity by our operators on our existing properties does not meet our development objectives. Our cash spending for acquisition activities was $21.1 million, $35.7$6.6 million and $28.5$21.1 million during the years ended December 31, 2024, 20232025 and 2022,2024, respectively.

Material Cash Requirements. Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. AsIf commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts. Conversely, working capital requirements would be expected to decrease if commodity prices decline.

Our long-term material cash requirements from currently known obligations include settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating lease obligations. We cannot provide specific timing for repayments of outstanding borrowings on our Revolving Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity (including the Lucero Acquisition),activity, among other factors. We cannot provide specific timing for other current and long-term liability obligations where we cannot forecast with certainty the amount and timing of such payments, including asset retirement obligations, as the plugging and abandonment of wells is primarily at the discretion of the operators and any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. See NotesNote 4 (“Fair Value Measurements”) to the Consolidated Financial Statements—Note 4— Fair Value Measurements for further information on these contracts and their fair values as of December 31, 2024,2025, which fair values represent the estimated cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date.

Dividends. We paid cash dividends to our equity holders of $63.6$92.1 million during the year ended December 31, 2024.2025. While we believe that our future cash flows from operations will be able to sustain an increasing level offuture dividends, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations (the most common of which are limitations set forth in a company’s organizational documents and insolvency), business developments and the judgment of our Board. Future cash dividends to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will be able to pay dividends at current levels or at all or otherwise return capital to our investors in the future.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected financial returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, change in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control, including the Lucero Acquisition.control. For additional information on the impact of changing prices and market conditions on our financial position, see Part II. Item 7A Quantitative and Qualitative Disclosures About Market Risk.

For the years ended December 31, 2024, 2023,2025 and 20222024 we did not record any impairment expense.

Our business strategy is focused on creating long-term stockholder value through the profitable acquisition, development and production of oil and natural gas assets that provide an attractive return on invested capital, while maintaining a strong balance sheet and distributing a meaningful dividend to our stockholders. We invest in working and mineral interests in oil and natural gas properties with our core area of focus currently in the Bakken and Three Forks formations of the Williston Basin of North Dakota and Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of MarchJune 31,30, 2026, we had a working interest in 6,4276,579 gross (226.0237.4 net) productive wells and 303278 gross (6.26.4 net) wells that were being drilled or completed, and an additional 282320 gross (13.713.0 net) wells that had been permitted for development by our operators. In addition, we had a royalty only interest in 1,2991,289 gross (3.1 net) productive wells.

OnAs Marchpreviously 26,announced, 2026on weMay announced1, a2026, leadership transition withMr. Jamie Benard set to joinjoined our team as President and Chief Executive OfficerOfficer. effective May 1, 2026,On the resignationsame ofdate, Robert Gerrity as our Chief Executive Officer and Chairman and the transition on May 1, 2026 ofMr. Brian Cree ourtransitioned existingfrom President and Interim Chief Executive Officer transitioning to Senior AdvisorAdvisor, anda role he will hold until his retirement on December 31, 2026. This leadership transition does not change our overall business strategy.

Our financial and operating performance for the three months ended MarchJune 31,30, 2026 included the following:

■CashNet flows from operationsincome of $24.0$33.1 million.

■Total debt of $144.5$158.5 million at MarchJune 31,30, 2026.

Commodity prices are a significant factor impacting our earnings, operating cash flows and our acquisition and divestiture strategy, as well as the decisions of us and our operators in conducting operations. During the last several years, prices for oil and natural gas have experienced sustained volatility, impacted by general economic and political conditions, the conflict between Russia and Ukraine, conflict in the Middle East, including Iran, the situation in Venezuela, U.S. international trade and tariff policies and responses thereto, supply chain constraints, elevated interest rates and costs of capital, and changes in production by OPEC and its key member, Saudi Arabia, and certain other non-OPEC oil-producing countries. Most recently, the conflict in Iran and disruption of maritime traffic through the Strait of Hormuz has caused significant volatility in commodity prices.

General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. During the threesix months ended MarchJune 31,30, 2025, general and administrative expenses included non-recurring costs related to the Lucero Acquisition.Acquisition and an offset for reimbursement of past legal expenses as a result of a settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements.

Impairment expense. Under the successful efforts method of accounting, we review our oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and natural gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering, processing and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and natural gas properties in each depletion pool to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the aggregated oil and natural gas properties, no impairment is recorded. If the carrying amount of the oil and natural gas properties exceeds the undiscounted future net cash flows, we will record an impairment expense to reduce the carrying value to fair value as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows. There were no proved oil and gas property impairments during the three and six months ended MarchJune 31,30, 2026 and 2025.

The average firstsecond quarter 2026 NYMEX oil price was $72.43$92.38 per barrelbarrel, or 2%45% higher than the average NYMEX oil price per barrel in the firstsecond quarter of 2025. Our settled derivatives decreased andour increasedsecond ourquarter 2026 realized oil price per barrel by $4.91$20.84 and $0.75increased inour the firstsecond quarter of2025 2026realized andoil 2025,price respectively.per barrel by $4.71. Our average firstsecond quarter 2026 realized oil price per barrel after reflecting settled derivatives was $61.85$71.14 compared to $64.93$64.21 during the same period in 2025.

The average firstsecond quarter 2026 NYMEX natural gas price was $4.71$2.95 per MMBtu, or 14%8% higherlower than the average NYMEX price per MMBtu in the firstsecond quarter of 2025. In the firstsecond quarter of 2026, our settled derivatives decreasedincreased our realized natural gas price by $0.38 per Mcf by $0.75,Mcf, bringing our realized natural gas price after reflecting settled derivatives to $1.54$1.55 per Mcf. In the firstsecond quarter of 2025, we had no realizedmaterial natural gas derivativeprice settlementsderivatives in place and our realized natural gas price was $2.81$4.17 per Mcf.

We employ a hedging program that partially mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part I, Item 3 Quantitative and Qualitative Disclosures about Market Risk and Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements.

Three Months Ended MarchJune 31,30, 2026 Compared with Three Months Ended MarchJune 31,30, 2025

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $67.4$91.0 million for the three months ended MarchJune 31,30, 2026 from $66.2$81.8 million for the three months ended MarchJune 31,30, 2025. The increase in oil and natural gas revenue was due to a 7%22% increase in production volumes, driven by acquisition and development activity (including the Lucero Acquisition for a full period in the most recently completed quarter), which was partially offset by a 4% decrease in the average realized prices per Boe before hedginghedging, partially offset by an 8% decrease in production volumes for the three months ended MarchJune 31,30, 2026. The increase in production volumes increased oil and natural gas revenue by $4.2 million, while the decrease in average realized prices per Boe before hedging increased oil and natural gas revenue by $17.6 million, while the decrease in production volumes decreased oil and natural gas revenue by $2.9$8.4 million.

Our oil price differential to the weighted average benchmark price during the three months ended MarchJune 31,30, 2026 was negative $5.44$0.88 per barrel, as compared to a negative $6.72$4.17 per barrel during the three months ended MarchJune 31,30, 2025, primarily due to more favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the three months ended MarchJune 31,30, 2026 was $2.29$1.17 per Mcf, representing a 47%40% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $2.81$4.17 per Mcf during the three months ended MarchJune 31,30, 2025, representing a 68%130% realization relative to the weighted average NYMEX natural gas price. The lower realized price was primarily due to the legal settlement increasing the realized price per Mcf in the prior period. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner.

Lease Operating Expense. Lease operating expense increaseddecreased to $15.3$18.0 million for the three months ended MarchJune 31,30, 2026 from $13.9$19.6 million for the three months ended MarchJune 31,30, 20252025. The decrease is primarily asattributable ato resultan of8% a 7% increasedecrease in production volumes between periods.

Production Tax Expense. Total production taxes wereincreased $5.7to million and $5.8$8.5 million for the three months ended MarchJune 31,30, 2026 andfrom 2025,$6.2 respectively.million for the three months ended June 30, 2025. Production taxes are primarily based on oil revenue and natural gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 8.4%9.3% and 8.7%7.6% for the three months ended MarchJune 31,30, 2026 and 2025, respectively. The production tax rate was lower for the three months ended June 30, 2025 due to a legal settlement increasing revenue in the period.

DD&A. DD&A increased to $31.2$34.8 million for the three months ended MarchJune 31,30, 2026 compared with $26.6$34.6 million for the three months ended MarchJune 31,30, 2025. The increase of $4.6 million, or 17%, was the result of a 7% increase in production and a $1.99 per Boe increase in the DD&A rate for the three months ended MarchJune 31,30, 20262026, partially offset by an 8% decrease in production compared with the three months ended MarchJune 31,30, 2025. The increase in production accounted for a $1.9 million increase in DD&A expense while the increase in the DD&A rate accounted for a $2.7$3.4 million increase in DD&A expense while the decrease in production accounted for a $3.2 million decrease in DD&A expense.

For the three months ended MarchJune 31,30, 2026, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $21.51$21.85 per Boe compared with $19.56$19.88 per Boe for the three months ended MarchJune 31,30, 2025. The rate was primarily higher for the three months ended March 31, 2026 due to lower SEC oil prices used to estimate reserves between periods.

Equity-Based Compensation. During the three months ended MarchJune 31,30, 2026, equity-based compensation expense decreasedincreased to $0.7$2.7 million from $2.5$2.4 million during the three months ended MarchJune 31,30, 2025. Equity-based compensation expense was primarily lowerhigher in 2026 due to aadditional $1.4LTIP millionRSUs reversaland ofPSUs expenseawarded forto forfeitedemployees awardsand during the period.directors.

Interest Expense. Interest expense decreasedincreased to $2.6$3.0 million for the three months ended MarchJune 31,30, 2026 from $2.9$2.5 million for the three months ended MarchJune 31,30, 2025. The decreaseincrease was due to a lower average debt balance and lower interest rate duringfor the three months ended MarchJune 31,30, 2026 comparedwas primarily due to a higher average debt balance during the three months ended March 31, 2025.period.

Commodity Derivative (Loss),Gain, Net. The net commodity derivative lossgain was $55.0$22.0 million for the three months ended MarchJune 31,30, 2026 compared with a lossgain of $0.2$18.5 million for the three months ended MarchJune 31,30, 2025. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total Commoditycommodity derivative gain (loss), net in the statements of operations included in this Form 10-Q. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position.

In the three months ended MarchJune 31,30, 2026, approximately 61%84% of our oil volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $4.4$19.6 million. In the three months ended MarchJune 31,30, 2026, approximately half of our natural gas volumevolumes waswere covered by residue gas and NGL financial hedges, which resulted in a realized lossgain on gas and NGL derivatives of $2.4$1.4 million. In the three months ended MarchJune 31,30, 2025, approximately 65%58% of our oil volumes and noneno of ourmaterial natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $0.7$5.3 million.

At MarchJune 31,30, 2026, all of our derivative contracts were recorded at their fair value, which was a net liabilityasset of $33.8$6.4 million, aan decreaseincrease in value of $48.2$40.2 million from the $14.4$33.8 million net assetliability recorded as of DecemberMarch 31, 2025.2026. Derivative contract fair value is recorded in part based on published forward commodity prices. This declineincrease in fair value was largely driven by the NYMEX WTI price increasingdecreasing from $57.42/Bbl at December 31, 2025 to $101.38/Bbl at March 31, 2026 to $69.50/Bbl at June 30, 2026 and the corresponding change in forward commodity prices.

Income Tax Expense. During the three months ended MarchJune 31,30, 2026 and 2025,2026, we recorded an income tax benefitexpense of $9.5$6.8 million and $0.2 million, respectively, related to federal and state income taxes.taxes compared to an income tax expense of $9.9 million for the three months ended June 30, 2025.

The provision for income taxes for the three months ended MarchJune 31,30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to §162(m) limitations on certain covered employee compensation, other discrete permanent differences related to vesting of RSUs for non-covered employees and state income taxes.

Overview. At MarchJune 31,30, 2026, we had $3.2$0.9 million of unrestricted cash on hand and $105.5$116.5 million available under the elected commitments in our Revolving Credit Facility. At December 31, 2025, we had $1.3 million of unrestricted cash on hand and $125.5 million available under the elected commitments in our Revolving Credit Facility. We expect that our liquidity going forward will be primarily derived from cash flows from our operations, cash on hand, availability under the Revolving Credit Facility and proceeds from equity or debt offerings and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements for the next twelve months, as described below, including our planned capital expenditures program, as well as dividends and our share repurchase program. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings under our Revolving Credit Facility or the issuance of equity or debt. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and dividend payments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

At MarchJune 30, 2026 and December 31, 2026,2025, we had a working capital deficit of $38.3 million compared to a surplus of $0.9$3.1 million atand December$0.9 31,million, 2025.respectively. Current assets decreasedincreased by $3.4$6.2 million whileand current liabilities increased by $35.7$4.0 million at MarchJune 31,30, 2026, compared to December 31, 2025. The decreaseincrease in current assets during the threesix months ended MarchJune 31,30, 2026 was primarily due to an increase of $21.8 million in accrued revenue, partially offset by a decrease of $14.3$12.5 million in current derivative instrument assets due to forward oil price increases as compared to hedged oil prices, partially offset by a $10.7 million increase in accrued revenue due to an increase in the oil index price in March.prices. The changeincrease in current liabilities during the threesix months ended MarchJune 31,30, 2026 was primarily due to an increase of $32.0$4.3 million in current derivative instrument liabilities due to forward oil price increases as compared to hedged oil prices and a $3.8 million increase in accounts payable and accrued liabilities as a result increased development activity.prices.

Cash Flows. Our cash flows for the threesix months ended MarchJune 31,30, 2026 and 2025 are presented below:

During the threesix months ended MarchJune 31,30, 2026, we generated $24.0$49.5 million of cash from operating activities,operations, a 37%$34.0 increasemillion decrease from the threesix months ended MarchJune 31,30, 2025. Cash flows from operating activities are primarily affected by production volumes, commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. During 2025, we received a one-time $24.0 million legal settlement that impacted cash flows from operating activities. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. A minimum level of derivative coverage is required by certain debt covenants. See Part I, Item 3 Quantitative and Qualitative Disclosures about Market Risk.

One of the primary sources of variability in our cash provided by operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts. For more information on our outstanding derivatives, see Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements.