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

Commodity prices are volatile, and a sustained period of low commodity prices for oil, NGLs and natural gas and NGLs could adversely affect our business, financial condition and results of operations.

The prices we receive for our oil, NGLs and natural gas and NGLs heavily influence our revenue, cash flows, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, NGLs and natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the actual and expected supply of and demand for oil, NGLs and natural gas and NGLs and market uncertainty. Historically, oil, NGL and natural gas and NGL prices have been volatile and subject to fluctuations relating to a variety of additional factors that are beyond our control, including:

•worldwide and regional economic conditions impacting the global supply of and demand for oil, NGLs and natural gas and NGLs;

•the price and quantity of foreign imports of oil, NGLs and natural gas and NGLs;

•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South AmericaAmerica, such as the recent developments in Venezuela;

•actions of U.S., European Union and other governments and governmental organizations relating to Russia’s oil, natural gasNGLs and NGLs,natural gas, including through sanctions, import restrictions and commodity price caps;

•political, economic and other conditions that affect perceived or actual demand for oil, natural gasNGLs and NGLs,natural gas, including international conflict, trade disputes, the imposition of tariffs or sanctions and global health concerns;

•actions of U.S. and other governments to strategically release oil, NGLs and natural gas and NGLs from strategic reservesreserves, including any increased volumes of Venezuelan crude oil;

•technological advancesadvances, including AI and its increased use, affecting fuel economy, energy supply and energy consumption;

•laws, regulations and taxes in the U.S. and in foreign jurisdictions that impact the demand for oil, NGLs and natural gas and NGLs;

These factorsfactors, among others, and the volatility of the energy markets make it extremely difficult to predict future oil, NGL and natural gas and NGL price movements with any certainty.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. Our estimated proved reserves as of December 31, 2024,2025, and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $71.96$66.01 per barrel of oil (WTI Posted) and $2.13$3.39 per MMBtu (Henry Hub spot), which may be substantially higher or lower than the available spot prices in 2024.2025. For example, if the crude oil and natural gas prices used in our year-end reserve estimates were to increase or decrease by 10%, our proved reserve quantities at December 31, 20242025 would increase by 26.045.5 MMBoe (2.5%4.1%) or decrease by 27.169.5 MMBoe (2.6%6.2%), respectively, and the pre-tax PV 10% of our proved reserves would increase by $2.1$2.2 billion (19%24%) or decrease by $1.4$2.2 billion (13%23%).

Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, or at all, which could lead to a decline in our ability to access or grow production and reserves.

The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. Historically, we have funded our capital expenditures with cash flows from operations,operations and may from time to time utilize borrowings under OpCo’s revolving credit facility, proceeds from offering debt and equity securities and divestitures of non-core assets, and we intend to finance our future capital expenditures in a similar fashion. When we finance our capital expenditures through indebtedness, a portion of our cash flows from operations must be used to pay interest and principal on the indebtedness, which reduces our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, NGL and natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments.

If our revenues or the borrowing base under OpCo’s revolving credit facility decrease as a result of lower oil, NGL and natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under OpCo’s revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. This, in turn, could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. In addition to the risks we face in drilling for and producing oil and natural gas, some factors that may directly or indirectly negatively impact our scheduled operations include:

Our ability to produce crude oil, NGLs and natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to recycle or dispose of the produced water we produce in an economical and environmentally safe manner.

Our producing properties are geographically concentrated in West Texas and New Mexico in the Permian Basin. At December 31, 2024,2025, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages, regional power outages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gasNGLs or NGLs.natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

The marketability of our oil, NGLs and natural gas and NGLs production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil, NGLs and natural gas and NGLs production is generally transported from the wellhead by gathering systems that are either owned by us or third-party midstream companies. In general, we do not control the transportation of our production and our access to transportation facilities may be limited or denied. In some instances, we have contractual guarantees relating to the transportation of our production through firm transportation arrangements, but third-party systems may be temporarily unavailable due to pressure limitations, market conditions, mechanical failures, accidents or other reasons. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or third-party midstream companies or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, NGLs and natural gas and NGLs and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements, we may be required to shut in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil, NGLs and natural gas and NGLs produced from our fields, would materially and adversely affect our financial condition and results of operations.

We have entered into certain multi-year supply and service agreements associated with energy and frac sand purchase agreements and have long-term agreements in place for drilling rigs, office rentals and other wellhead equipment. We also have various multi-year agreements that relate to the sale, transportation or gathering of our oil, NGLs and natural gas and NGLs and may in the future enter into multi-year agreements for contracts for other services. Some of these agreements contain minimum volume commitments that we must satisfy or contractual penalties in the form of volume deficiencies or other remedies may apply. For example, we have recently entered into firm transportation arrangements where we are obligated to pay fixed amounts on minimum volumes regardless of actual volume throughput under these contracts. We may be unable to use our full transportation capacity under existing firm transportation agreements, resulting in obligations to pay fees without receiving revenues on sales. As of December 31, 2024,2025, our aggregate long-term contractual obligation under theseour multi-year agreements was $396.1$1.5 million,billion, which represents the gross minimum obligation but does not include amounts that may be due under certain contracts that contain variable pricing or volumetric components as the future obligations cannot be determined. Further information about these agreements can be found at Delivery Commitments under Part I, Items 1 and 2 and Note 1413—Commitments and Contingencies under Part II, Item 8 of this Annual Report. Any failure by us to satisfy the minimum volume commitments in these agreements could adversely affect our results of operations and financial position.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted by tariffs or other trade restrictions imposed by the United States on imported goods from countries where these goods are produced. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages or cost increases could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Historically, our capital and operating costs have risen during periods of increasing oil, NGL and natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased tariffs and comparative taxes. Such costs may rise faster than increases in our revenue as commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

We depend upon a small number of significant purchasers for the sale of most of our oil, NGL and natural gas and NGL production.

We are heavily dependent on our information and operational technology systems and other digital technologies.

Our ability to effectively manage and operate our business depends significantly on information and operational technology systems and other digital technologies. The availability and integrity of these systems and technologies are essential for us to conduct our business and operations. Any failure of these systems to operate effectively and support our operations, challenge in transitioning to new upgraded or replacement systems, including any implementation or utilization of AI systems, difficulty in integrating systems and updates across our growing business, or a breach of these systems could materially and adversely impact the operations of our business. In addition, cybersecurity incidents, including deliberate attacks or unintentional events, have generally continued to increase in frequency and become increasingly sophisticated. The U.S. government has also issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats.

Any breach of our network may result in the loss of valuable business data or critical infrastructure, misappropriation of our customers’customers’, employees’ or employees’service providers’ personal information, or a disruption of our business,business and operations, which could harm our customer relationships and reputation, and result in lost revenues, finesremediation orand lawsuits.compliance costs, litigation, regulatory investigations and enforcements and penalties and fines. Although we utilize various procedures and controls to monitor, protect against and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing such threats from materializing, particularly given the unpredictability of the timing, nature, and scope of such breaches. While we endeavor to maintain insurance that covers certain cybersecurity incidents, we may not be insured for, or our insurance may be insufficient to protect us against, particular types of cybersecurity risks, and, in the future, such insurance may not continue to be available to us on reasonable terms, if at all. Furthermore, weaknesses in the cybersecurity of our vendors, suppliers, and other business partners could be used to facilitate an attack on our systems and networks.

Although, asAs of the date of this Annual Report, though the Company and its service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations and financial condition;condition. However, we acknowledge that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents, material or otherwise, remains. Consequently, it is possible that any such occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations. Additional information on our cybersecurity risk management, strategy and governance can be found at Part I, Item 1C of this Annual Report.

Since our production is not fully hedged, and we are also exposed to fluctuations in oil, NGL and natural gas and NGL prices as it relates to the price we receive from the sale of our unhedged volumes. We intend to continue to hedge a portion of our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility with regard to these unhedged volumes, and a decline in commodity prices could materially and adversely affect our business, financial condition and results of operations.

As of December 31, 2024,2025, we had approximately $4.2$3.5 billion of total long-term debt and additional borrowing capacity of $2.5 billion under OpCo’s revolving credit facility (after giving effect to $2.5 million of outstanding letters of credit),facility, all of which would be secured if borrowed. Subject to the restrictions in the instruments governing OpCo’s outstanding indebtedness (including OpCo’s revolving credit facility and senior notes), OpCo and its subsidiaries may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the instruments governing OpCo’s outstanding indebtedness do contain restrictions on the incurrence of additional indebtedness, these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.

OpCo’s credit agreement with a syndicate of banks that provides for a secured revolving credit facility, maturing in February 2028 (the “Credit Agreement”), and the indentures governing its senior notes contain a number of significant covenants, including restrictive covenants that may limit OpCo’s ability to, among other things:

The restrictions in OpCo’s debt agreements may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictions imposedimpose on OpCo.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates, as a result of elevated rates of inflation or otherwise, or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets, due to the impositionimposition, or threat, of tariffs,tariffs and other trade restrictions, geopolitical conflictsconflicts, including in oil producing countries like Venezuela, or otherwise, may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the Railroad Commission of Texas (the “TRRC”) has issued rules that set the requirements for drilling, putting pipe down and cementing wells, testing and reporting obligations, and the disclosure of substances used in the hydraulic fracturing process. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. State and federal regulatory agencies, including Texas, have also recently focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and seismic activity. The TRRC has issued orders restricting the use of disposal wells it determined were likely influencing seismic activity. Separately, New Mexico has implemented protocols requiring operators to take various actions with respect to disposal wells within a specified proximity of recent seismic activity, including a requirement to limit injection rates if the seismic event in question reached a certain magnitude. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, production or development activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectly impact our business, financial condition and results of operations. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Fuel conservation measures, alternative fuel requirements, any increase in consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, including as a result of the renewable energy incentives contained in the IRA,devices could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

Certain environmental laws impose strict joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental, health and safety risks and costs or may not provide sufficient coverage if an environmental, health and safety claim is made against us. Moreover, public interest in the protection of the environment and human health has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. In the states of New Mexico and Texas, as an example, governmental authorities are investigating the practice of flaring natural gas and it is possible that such states could implement additional volumetric or other restrictions on this practice which may require us to curtail or shut in production which otherwise is or would be flared due to the unavailability of acceptable delivery, transportation or processing arrangements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected. Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion on the topics referenced above and additional information on existing and proposed laws and regulations related to environmental and occupational health and safety matters.

A negative shift in investor sentiment towards the oil and natural gas industry and increased attention to environmental, social and governance (“ESG”)sustainability and conservation matters may adversely impact our business.

IncreasingIncreased attention from companies’ investors, customers, employees, regulatory bodies and other stakeholders, as well as natural capital and societal expectations, on companies to address climate change, investor and societal expectations regarding voluntary ESGor mandatory sustainability initiatives and disclosures, and consumer demand for alternative sources of energy may result in increased costs (including but not limited to increased costs associated with compliance, stakeholder engagement, contracting, and insurance), reduced demand for our products and our product and services, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, heightened scrutiny of our statements and initiatives, and negative impacts on our stock price and access to capital markets. IncreasingIncreased attention to climate change and environmental conservation, for example, may result in demand shifts for our products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that liability could be imposed on us without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. Voluntary disclosures regarding ESGsustainability matters, as well as any ESGsustainability disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to pursue, implement ESGor make progress against sustainability strategies or achieve ESGsustainability goals or commitments, including any GHG reduction or neutralization goals or commitments, could result in governmental investigations or enforcement, private litigation and damage our reputation, cause our investors or consumers to lose confidence in our Company, and negatively impact our operations.

Any restrictions on oil and natural gas development on federal lands hashave the potential to adversely impact our operations.

Federal leasing and permitting programs for oil and natural gas development on federal lands have been, from time to time, subject to suspension or cancellation by executive order, subject to litigation by third parties, or otherwise restricted by federal action. For example, theprevious BidenPresidential administrationadministrations have issued a 20-year banmoratoriums on new oil and gas leasingleasing. within a 10-mile radius of Chaco Culture National Historical ParkAdditionally, in Northern New Mexico in June 2023. Additionally,2024, the IRA legislated changes to the fiscal terms of federal oil and gas leases, increasing fees, rents, royalties, and bonding requirements, all of which have been implemented pursuant to a finalized BLM rule. The BLM has also finalized a rule that would requirerequiring operators to limit venting and flaring from well sites on federal lands and require operators require operators to submit a methane waste minimization plan or self-certification statement committing the operator to capture 100% of the gas produced from a well and pay royalties on lost gasgas, asthough partthis rule is currently subject to litigation, postponed implementation, and reconsideration by the Trump administration. Congress may also, from time to time, legislate changes to the fiscal terms and environmental performance obligations of thefederal permitoil applicationand process,gas thoughleases. theCertain rulelawmakers becamehave effectiveproposed, inand Junemay 2024,continue itsto implementationpropose, remainsto pausedreduce inor Texasban (amongfurther otherleasing states)on pendingfederal litigation.lands or to adopt further restrictions on oil and gas development on federal lands. While we cannot predict the ultimate impact of these changes or whether federal agencies will implement further reforms, any revisions to the federal leasing or permitting processprocess, by executive action, legislation or regulation, that make it more difficult or costly for us to pursue operations on federal lands may adversely impact our operations. However, any such adverse regulatory developments are expected to have no more than a minimal impact on our results, given our limited exposure of leases on federal lands. Additionally, theany additional actions the Trump administration will take with respect to oil and gas leasing on federal lands cannot be predicted at this time, though any such actions may be subject to litigation. Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion of the regulations affecting our operations on federal lands.

TaxChanges in tax laws andor regulations or the interpretation thereof or the imposition of new or increased taxes may changeincrease overour time,future andtax anyliabilities, such changeswhich could adversely affect our businessbusiness, results of operation, financial condition and financialcash condition.flows.

From time to time, U.S. federal and state level legislation has been proposed that, if enacted into law, would make significant changes to tax laws, including to certain key U.S. federal and state income tax lawsprovisions affectingcurrently theapplicable oil andto natural gas industry.and Suchoil proposed legislation has included, but has not been limited to, (i) eliminating the immediate deduction for intangible drillingexploration and development costs,companies. (ii)It repealingis the percentage depletion allowance for oil and natural gas properties, (iii) extending the amortization period for certain geological and geophysical expenditures, (iv) eliminating certain other tax deduction and relief previously available to oil and natural gas companies and (v) increasing the U.S. federal income tax rate applicable to corporations like us. No accurate prediction can be made as tounclear whether any such legislative changes will be proposed or enacted in the future or,and, if enacted, whathow thesoon specificany provisionssuch orchanges thecould effectivetake dateeffect. The passage of any such legislation would be. The passage of any legislation as a result of these proposals andor other similar changes in U.S. federal andor state income tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could increase our future tax liabilities, which could adversely affect our business, results of operations, financial condition and cash flow.flows.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. The following discussion and analysis contain forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, natural gasNGLs and NGLs,natural gas, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

We are an independent oil and natural gas company focused on driving returns to our stockholders through the responsible acquisition, optimization and development of high-return oil and natural gas properties. Our assets and operations are mainlylocated locatedin the Permian Basin, with a concentration in the core of the PermianDelaware Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in an environmentally and socially responsible way,assets, with an overall objective of improving our rates of return and generating sustainable free cash flow.

Our revenue, profitability and ability to return cash to stockholders can depend substantially on factors beyond our control, such as economic, political and regulatory developments. Prices for crude oil, NGLs and natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.

The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events, federal and state government regulations,regulations weather conditions, thegrowth global transition toin alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 20222023:

Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement and senior notes. Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to thesuch lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the Credit Agreement.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. AsThe commodity prices rise, costscost of oilfield goods and services generallyare alsoclosely increase;linked however, during periods ofto commodity price declines,trends, oilfieldrising costswhen typicallyprices lagincrease and dodecreasing not adjust downward as fast as oilwhen prices do.fall. In addition, the U.S. saw higher thanlevels normalof inflation during 20232024 and 2024.2025 due to concerns over international conflicts, tariffs and trade policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.

2025 Bolt-On AcquisitionAcquisitions

DuringAdditionally, during the year ended December 31, 2024,2025, we completed multiple other acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $392.3$471.1 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.

During the year ended December 31, 2024,2025, we declared and paid quarterly base dividends totaling $0.32$0.60 per share of Class A Common Stock and distributions totaling $0.32$0.60 per share of Class C Common Stock (each of which has an underlying common unit of OpCo (“Common Units”)). Additionally, during the year ended December 31, 2024, we declared and paid variable dividends totaling $0.39 per share of Class A Common Stock and distributions totaling $0.39 per share of Class C Common Stock. The cash dividends and distributions paid totaled $560.9$502.9 million for the year ended December 31, 2024.2025.

OnDuring AprilJune 5,2025, 2024,we repurchased $2.7 million of our senior notes due 2026 (the “2026 Senior Notes”) at a price equal to 99.7% of the principal amount paid plus accrued and unpaid interest up to, but excluding, the repurchase date. Subsequently, during September 2025, we redeemed all ofremaining OpCo’s2026 outstandingSenior 6.875% senior notes due 2027Notes at a redemption price equal to 100% of the aggregate principal amount outstanding of $356.4$286.7 million plus accrued and unpaid interest up to, but excluding, the redemption date.

Oil, NGL and Natural Gas and NGL Sales Revenues. Total net revenues for the year ended December 31, 20242025 increased by $1.9$64.5 billion,million, or 60%,1%, compared to the year ended December 31, 2023.2024. Revenues are a function of oil, NGL and natural gas and NGL volumes sold and average commodity prices realized.

Total net revenues increases were also driven by higher average realized sales prices of NGLs,natural which increased 4%gas for the year ended December 31, 20242025 compared to the same 20232024 periodperiod. asThis aincrease was the result of higher regional and national average Montindex Belvieu spotgas prices forbetween plant products during the year ended December 31, 2024.periods.

These increases were partially offset by lower average realized sale prices for oil and natural gasNGLs, which decreased 1%14% and 71%,12%, respectively, for the year ended December 31, 20242025 compared to the same 20232024 period. The 1%14% decrease in the average realized oil price was mainly the result of 2% lower NYMEX crude prices between periods, which was slightly offset by improved oil differentials.periods. The 12% decrease in the average realized salesNGL price ofbetween naturalperiods gaswas decreasedprimarily 71% mainly dueattributable to widerlower gasMont differentialsBelvieu realizedspot onprices ourfor gasplant sales,products which are primarily sold at Waha where the market price averaged $0.05 per MMBtu duringfor the year ended December 31, 20242025 compared to $1.52 for the same 2023 period due to location specific market constraints for the majority of the 2024 period as discussed under the “Market Conditions” section above.period.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year ended December 31, 20242025 increased $137.0$12.5 million compared to the year ended December 31, 2023.2024. Severance taxes are based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. SeveranceThe taxesincrease in severance and ad valorem tax expense for the year ended 2024 increased $120.4 million2025 compared to the same 20232024 period primarilyis due to an increase in severance taxes and is primarily related to higher operatingNGL and natural gas revenues between periods. Ad valorem taxes between periods increased by $16.6 million, mainly due to incurring a full year of ad valorem taxes on the proved developed properties acquired in the Earthstone Merger compared to two months in 2023.

For the year ended December 31, 2024,2025, DD&A expense amounted to $1.8$2.0 billion, an increase of $769.1$255.8 million from 2023.2024. The primary factor contributing to higher DD&A expense in 20242025 was the increase in our overall production volumes between periods, which increased DD&A expense by $776.9$248.4 million period over period, while ourmarginally lowerhigher DD&A raterates ofbetween $14.13periods per Boe decreasedincreased DD&A expense by $7.8$7.4 million between periods.million.

While cash G&A increased between periods, on a per Boe basis our cash G&A rate decreased 23%11% from $1.21 per Boe during the year ended December 31, 2023 to $0.93 per Boe during the year ended December 31, 2024 asto a$0.83 per Boe during the year ended December 31, 2025. This per Boe rate decrease was the result of improvedfocus operationalon executioncontrolling costs and realizationgrowing of cost synergies following the Earthstone Merger.production.

Income Tax Expense: The following table summarizes our pre-tax income and income tax expense for the periods indicated.indicated:

For the year ended December 31, 2025 we generated pre-tax net income of $1.4 billion and recorded income tax expense of $284.2 million. Our provision for income taxestax expense for the yearsyear ended December 31, 20242025 andwas 2023less differs fromthan the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income primarily due to (i) the portion of pre-tax net income that is attributable to our non-controllingnoncontrolling interest andpartners whichthat is therefore not taxable to the Company; and (ii) othergeneral permanentbusiness differences;tax andcredits (iii)generated stateduring incomethe taxes.year. These decreases were partially offset by an increase in our unrecognized tax benefit recognized during the year ended December 31, 2025.

For the year ended December 31, 20242024, we generated pre-tax net income of $1.6 billion and recorded income tax expense of $300.3 million. During the year ended December 31, 2023, generated pre-tax net income of $1.0 billion and recorded income tax expense of $155.9 million. The primary factor decreasing our income2024 tax expense below the statutory U.S. statutoryfederal income tax rate for both periods was the portion of pre-tax income that was attributable to our non-controllingnoncontrolling interest partners and not taxable to the Company.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contain forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, NGLs and natural gas, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, international conflict, inflation, tariffs, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and the 2025 Annual Report; all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Oil prices declined through the end of 2025 and into early 2026, reflecting concerns regarding global economic growth, elevated interest rates, persistent inflation, increased global oil supply, and evolving tariffs and international trade policies. While global demand remained relatively strong and geopolitical risks persisted, higher‑than‑anticipated production increases from OPEC and the potential impact on global inventory levels contributed to additional downward pressure on prices during this period. More recently, oil prices have increased, with NYMEX WTI spot prices reaching a high of $102.88$112.95 per barrel on MarchApril 30,7, 2026, driven primarily by supply disruptions associated with heightened geopolitical tensions in the Middle East, including disruptions to key shipping routes in the Strait of Hormuz,Hormuz and the Red Sea, which havehas adversely affected global supply conditions. Significant uncertainty remains regarding the ability to resolve these conflicts, reopen trade and shipping routes and their ultimate impact on global oil supply and prices.

Throughout 2025 and 2026, natural gas prices in the Permian Basin have been adversely impacted by low demand as a result of pipeline capacity constraints out of the basin, pipeline maintenance, and higher production levels. These factors have led to lower or, during certain periods, negative regional gas prices being realized for natural gas sales at the Waha Hub in West Texas. Notably during the second quarter of 2026, Waha natural gas prices averaged negative $3.14 per Mcf and traded as low as negative $9.52 per Mcf on April 16, 2026.

The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events,events and conflicts, federal and state government regulations, weather conditions, growth in alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2024:

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. The cost of oilfield goods and services are closely linked to commodity price trends, rising when prices increase and decreasing when prices fall. In addition, the U.S. saw higher levels of inflation during 2025 and 2026 due to concernsconcerns, among other things, over international conflicts, tariffstariffs, potential sanctions and trade policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.

During the threesix months ended MarchJune 31,30, 2026, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $204.9$482.3 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.

DuringWe the three months ended March 31, 2026, wehave declared and paid quarterly base dividends of $0.16 per share of Class A Common Stock.Stock each quarter for a total of $0.32 per share for the six months ended June 30, 2026. The cash dividends paid totaled $134.9$269.1 million for the threesix months ended MarchJune 31,30, 2026.

On April 30, 2026, OpCowe entered into a new credit agreement with a syndicate of banks that provides for ana $3.0 billion senior unsecured revolving credit facility,facility maturing inon April 30, 2031 (the “New Credit Agreement”). In connection with our entryentering into the New Credit Agreement, we terminated our existing secured revolving credit facility (thewithout “Credit Agreement”).penalty. Refer to Liquidity and Capital Resources for additional information regarding the New Credit Agreement.

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

Oil and Gas Sales. Total net revenues for the three months ended MarchJune 31,30, 20262026, were $11.7$660.4 million (or 1%55%) higher than total net revenues for the three months ended MarchJune 31,30, 2025. Revenues are primarily a function of oil, NGL and natural gas volumes sold and average commodity prices realized.

Net production volumes for oil,oil NGLs and natural gasalso increased 10%,by 20% and 4%, respectively,12% between periods. TheThis increase in oil production resulted from additional production added from wells placed online or acquired since the firstsecond quarter of 2025.2025 These oil volume increasesthat were partially offset by normal production declines across our existing wells. NGLs and natural gas are produced concurrently with our crude oil volumes, which typically resultresults in a high correlation between fluctuations in oil quantities sold and NGL and natural gas quantities soldsold. driving the respective 20% and 4% increases inHowever, NGL and natural gas volumes decreased 12% and 17%, respectively, between periods.periods, NGLreflecting volumesproduction werecurtailments furtherof impactedcertain bywells processors operating inwith higher ethane-recoverygas-to-oil production ratios during the first quarterperiods of 2026negative as compared to the same 2025 period, resulting in a higher percentage of NGLs being recovered from our wetnatural gas stream between periods.prices.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended MarchJune 31,30, 20262026, decreasedincreased $6.7$48.8 million compared to the three months ended MarchJune 31,30, 2025. Our severance and ad valorem taxes as a percentage of revenues also decreased between periods from 7.8% for the three months ended March 31, 2025 to 7.3% for the three months ended March 31, 2026. Severance taxes are based on the market value of our oil and gas production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. TheSeverance lowertaxes rate infor the currentsecond quarter of 2026 increased $51.1 million, or 64%, compared to the same 2025 period was primarily drivendue byto the 55% higher total oil and gas sales asbetween wellperiods. asThis increase was partially offset by ad valorem taxes that decreased $2.3 million for the second quarter of 2026 compared to the same 2025 period primarily due to lower ad valorem tax assessments comparedbetween toperiods, which also drove the priordecrease period.in our severance and ad valorem taxes as a percentage of revenues between periods.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the three months ended MarchJune 31,30, 20262026, increaseddecreased $4.0$19.2 million as compared to the three months ended MarchJune 31,30, 2025. This increasedecrease in expense was mainly attributable to higherlower NGL and natural gas volumes sold between periods, which in turn resulted in a higherlower amount of plant processing fees and gathering costs being incurred. Additionally, the decrease was the result of changes to certain gathering agreements resulting in a greater portion of gathering, processing and transportation fees being reflected as a net reduction to our NGL and natural gas sales than as GP&T expense.

For the three months ended MarchJune 31,30, 2026, DD&A expense amounted to $526.3$500.2 million, ana increasedecrease of $52.1$6.3 million over the same 2025 period. The primary factor contributing to higherlower DD&A expense in 2026 was the increasedecrease in our overall production volumes between periods, which increaseddecreased DD&A expense by $50.4$11.5 million, while our slightly higher DD&A rate of $14.16$14.60 per Boe increased DD&A expense by $1.7$5.2 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, and impairments, as well as changes in proved developed and proved undeveloped reserves.

G&A expenses for the three months ended MarchJune 31,30, 20262026, were $43.8$48.0 million compared to $43.1$49.8 million for the three months ended MarchJune 31,30, 2025. HigherLower G&A for the firstsecond quarter of 2026 compared to the same 2025 period was primarily the result of $1.8 million higher cash G&A between periods mainly related to our increased headcount and overall corporate growth. These increased expenses were partially offset by a $1.0$1.1 million decrease in stock-based compensation between periods associatedbased withon the timing of grants and the vesting of our equity awards.

Interest expense decreased $6.8$13.1 million for the three months ended MarchJune 31,30, 20262026, as compared to the three months ended MarchJune 31,30, 20252025, primarily due to less interest incurred on our senior notes that were fully or partially redeemed or repurchased since MarchJune 31,30, 2025. Refer to Note 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report for additional information regarding our senior notes.

For the three months ended MarchJune 31,30, 2026, we generated pre-tax net income of $63.9$1.0 millionbillion and recorded income tax expense of $13.5$223.4 million.

During the three months ended MarchJune 31,30, 2025, we generated pre-tax net income of $490.9$307.5 million and recorded income tax expense of $100.3$62.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company.

We continually evaluate our capital needs and compare them to our capital resources. During the threesix months ended MarchJune 31,30, 20262026, our total capital expenditures incurred for drilling and development activity were $466.2$987.7 million. We funded our capital expenditures for the threesix months ended MarchJune 31,30, 20262026, entirely from cash flows from operations, and we expect to fund the remainder of our 2026 capital expenditures budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place.

We plan to return capital to shareholders primarily through our base dividend, in addition to opportunistic share repurchases. During the threesix months ended MarchJune 31,30, 2026, we declared and paid quarterly dividends totalingof $0.16 per share of Class A Common Stock.Stock for a total of $0.32 per share. The cash dividends paid totaled $134.9$269.1 million for the threesix months ended MarchJune 31,30, 2026.

In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise. During the second quarter of 2026, we redeemed our 8.00% senior notes due 2027 at a redemption price equal to 100% of the $550.0 million principal amount outstanding, plus accrued and unpaid interest. Additionally, on July 15, 2026, we redeemed our 9.875% senior notes due 2031 at a redemption price equal to 104.938% of the $325.0 million principal amount outstanding, plus accrued and unpaid interest.

For the threesix months ended MarchJune 31,30, 2026, we generated $815.1$2.3 millionbillion of cash from operating activities, aan decreaseincrease of $83.0$384.0 million from the same period in 2025. Cash provided by operating activities decreasedincreased primarily due to higher realized prices and production volumes for oil, more purchased gas sales, less cash interest expense and lower GP&T expense during the six months ended June 30, 2026, as compared to the same 2025 period. These increasing factors were partially offset by lower realized prices for NGLs and natural gas, less realized cash settlements on our derivative contracts, higher severance and ad valorem taxes and lease operating expenses and GP&Texpenses, as well as the timing of collections on our receivables and payments to our suppliers during the threesix months ended MarchJune 31,30, 20262026, as compared to the same 2025 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.

During the threesix months ended MarchJune 31,30, 2026, cash flows from operating activities and cash on hand were used to (i) fund $466.2$987.7 million of drilling and development cash capital expenditures; (ii) redeem $550.0 million of our senior notes; (iii) fund acquisitions of oil and gas properties of $204.9$534.3 million; and (iiiiv) pay $134.9$269.1 million in dividends to our shareholders.

During the threesix months ended MarchJune 31,30, 2025, cash flows from operating activities and proceeds of $176.0 million primarily from the sale of oil and natural gas gathering systems that were acquired during a prior year acquisition were used to (i) fund $500.7$1.0 millionbillion of drilling and development cash capital expenditures; (ii) redeemfund $175.0 millionacquisitions of ouroil seniorand notesgas properties of $650.3 million; (iii) pay $121.0$241.6 million in dividends and cash distributions to our shareholders and holders of our Common Units; and (iv) fundredeem acquisitions$177.7 million of oilour senior notes; and gas(v) propertiesrepurchase $43.3 million of $35.4our million.Class A Common Stock.

OpCoWe hadhave a secured revolving Credit Agreement withthat provides for a syndicatesenior ofunsecured banksrevolving maturingcredit in February 2028.facility. As of MarchJune 31,30, 2026, we had no borrowings outstanding and $2.5$3.0 billion in available borrowing capacity.capacity In connection with our entry into the New Credit Agreement, we terminatedunder the Credit Agreement. For further information on our Credit Agreement, refer to Note 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report.

The New Credit Agreement has a scheduled maturity date of April 30, 2031, and includes an option to extend the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the lenders holding greater than 50% of the commitments then outstanding under the New Credit Agreement. The New Credit Agreement commitsprovides the lenders thereunder to provide advances up to anfor aggregate principal amountcommitments of $3.0 billion outstanding at any given time,billion, with an option to request increases in the aggregate commitments to an amount not to exceed $4.0 billion, subject to certain terms and conditions.conditions The New Credit Agreement alsoand includes a swingline subfacility and a letter of credit subfacility.

AdvancesBorrowings under the New Credit Agreement willbear accrueinterest, interestat our election, based on either SOFR plus an applicable margin,margin or the Alternate Base Rate plus an applicable margin at our election.margin. The applicable marginmargins usedfor inSOFR connectionand withAlternate interestBase rates,Rate borrowings, as well as commitment fees for undrawn commitments, will beare based on our credit rating for our long-term senior unsecured indebtedness for borrowed money (not supported by third-party credit enhancement) at the applicable time.indebtedness. As of AprilJune 30, 2026, the applicable margin for SOFR and Alternate Base Rate Loans is 150 basis points and 50 basis points, respectively, and the commitment fee is 20 basis points.