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

•the restrictive covenants in the Term LoanNew Credit Agreement and the Revolving Credit Agreement (collectively, the “Credit Agreements”) and other agreements governing indebtedness that limit our ability to pay dividends or distributions in respect of our equity; and

As a result of the limitations described in this Annual Report, we may be unable to drill many of our identified locations. In addition, although we plan to fund our drilling program entirely with cash flow from operations, if our cash flows are less than we expect or we alter our drilling plans, we may be required to borrow more under the RevolvingNew Credit Agreement than we expect or issue new debt or equity securities in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “— Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which in turn could have a material adverse effect on the borrowing base under the RevolvingNew Credit Agreement or our future business and results of operations. Additionally, if we curtail or cancel our drilling program, we may be required to reduce our estimated proved reserves, which could in turn reduce the borrowing base under the RevolvingNew Credit Agreement.

As of December 31, 2024,2025, approximately 27%7% of our total estimated proved reserves were classified as PUDs using SEC Pricing. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PUDs on December 31, 20242025 were approximately $842.1$1.1 millionbillion over the next five years. Our ability to fund these expenditures is subject to a number of risks. See “— Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Delays in the development of our PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the PV-10 value of our estimated PUDs and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify some of our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our undeveloped reserves to developed reserves or that our PUDs will be economically viable or technically feasible to produce.

We have entered into short-term and long-term, fixed-fee contracts with third parties for gathering, processing and transportation services, including foursome firm transportation contracts,contracts. three of which are fully utilized and one that is partially utilized, with the remainder released to other shippers or unutilized. The impact of the unutilized portion of this contract is assumed under the weighted average sales price in the reserves. Total remaining payments as of December 31, 2024 under firm transportation contracts were $0.3 million. In addition, underUnder these short-term and long-term, fixed-fee arrangements, our gathering and processing expenses are generally fixed on a per unit basis for the term of the applicable contract and do not automatically adjust in response to a decline in oil and natural gas prices. In the event of a prolonged period of lower commodity prices, our revenue will decline while the per unit fees we pay for natural gas gathering, treating and compression services generally will not, which would negatively impact our operating margins and cash flow. In addition, during periods of depressed oil and natural gas prices, the market prices for such services may be lower than what we are contractually obligated to pay to our current third-party midstream service providers. Furthermore, to the extent certain future taxes or assessments are imposed on certain midstream assets we utilize, under certain circumstances we may be required by our midstream services contracts to reimburse the midstream service provider for such taxes or assessments, which could negatively affect our operating margins and cash flow. Our third-party midstream service providers are under no obligation to renegotiate their contracts with us. Our failure to obtain these services on competitive terms could materially harm our business.

In addition, the New Credit AgreementsAgreement imposeimposes certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could limit our ability to acquire assets and businesses.

The oil and gas industry is capital-intensive. A number of factors could cause our cash flow to be less than we expect, including the results of our drilling and completion program. Moreover, our capital budgets are based on a number of assumptions, including expected elections by working interest partners, drilling and completion costs, midstream service costs, oil and natural gas prices, and drilling results, and are therefore subject to change. If our cash flows are less than we expect, we decide to pursue acquisitions, or we change our capital budgets, we may be required to borrow more under credit facility than we expect or issue debt or equity securities to consummate such acquisitions or fund our drilling and completion program. The incurrence of additional indebtedness, either through borrowings under the RevolvingNew Credit Agreement, the issuance of additional debt securities or otherwise, would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund capital expenditures, our development plan, acquisitions and cash distributions to unitholders. Additionally, the market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. The issuance of additional equity securities may be dilutive to our unitholders The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things: oil and natural gas prices; actual drilling results; the availability and cost of drilling rigs and labor and other services and equipment; the availability, cost and adequacy of midstream gathering, processing, compression and transportation infrastructure; and regulatory, technological and competitive developments.

•our ability to borrow under the RevolvingNew Credit Agreement; and

If our revenues or the borrowing bases under the RevolvingNew Credit Agreement decrease as a result of lower commodity prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to make acquisitions or 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 the RevolvingNew Credit Agreement are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which 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.

For the year ended December 31, 2024,2025, two purchasers each accounted for more than 10% of our revenue: Phillips 66 Company (32.2%23.3%) and ShellNextEra OilEnergy CompanyMarketing, LLC (12.7%20.6%). We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties — Marketing and Customers” included in Items 1 and 2 of Part I of this Annual Report.

As of December 31, 2024,2025, we had $763.1$1.15 millionbillion outstanding under our New Credit Agreements.Agreement. In the future, we and our subsidiaries may incur substantial additional indebtedness. The New Credit AgreementsAgreement containcontains restrictions on the incurrence of additional indebtedness, and 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. Additionally, the New Credit AgreementsAgreement permitpermits us to incur certain amounts of additional indebtedness.

•limiting our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities, due to covenants contained in our New Credit Agreements,Agreement, including financial covenants.

The New Credit AgreementsAgreement containcontains a number of significant covenants, including restrictive covenants that, subject to certain qualifications, limit our ability to, among other things:

In addition, the New Credit AgreementsAgreement requirerequires us to maintain compliance with certain financial covenants.

The restrictions in the New Credit AgreementsAgreement also impact our ability to obtain capital to withstand a 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 restrictive covenants under our debt arrangements may impose on us.

A breach of any covenant in the New Credit AgreementsAgreement will result in a default under our New Credit AgreementsAgreement and an event of default if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Any significant reduction in our borrowing base under the RevolvingNew Credit Agreement as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

The RevolvingNew Credit Agreement limits the amounts we can borrow up to certain borrowing base amounts, which the administrative agent in good faith and in accordance with its usual and customary procedures for evaluating oil and gas loans and related assets at that particular time and otherwise acting in its sole discretion, will determine and which will be approved by the required lenders or all lenders, as applicable in the case of an increase in the borrowing base, on a semi-annual basis based upon projected revenues from our natural gas properties, our commodity derivative contracts securing our loan and certain other information (including, without limitation, the status of title information with respect to the oil and natural gas properties and the existence of any other indebtedness, liabilities, fixed charges, cash flow, business, properties, prospects, management and ownership, hedged and unhedged exposure to price, price and production scenarios, interest rate and operating cost changes). In addition to the scheduled redeterminations, the Company and the required lenders may request unscheduled interim redeterminations of the borrowing base not more than once between scheduled redeterminations. Any increase in the borrowing base will require the consent of all lenders (other than defaulting lenders). If the requisite number of required lenders or all lenders, as applicable in the case of an increase in the borrowing base, do not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. We will be required to repay outstanding borrowings in excess of the borrowing base. The borrowing base may also automatically decrease upon the occurrence of certain events.

In the future, we may not be able to access adequate funding under the RevolvingNew Credit Agreement as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a borrowing base redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. Furthermore, our borrowing base may be reduced if we sell assets in the future. Declines in commodity prices could result in a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions, make distributions to our unitholders or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.

Borrowings under the New Credit AgreementsAgreement bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our business, financial condition and results of operations and cash available for distribution remain unchanged.

We have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies and deposit accounts held at regional banks. In addition, if any lender under the RevolvingNew Credit Agreement is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit agreement.

We require continued access to capital and our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. We may use the RevolvingNew Credit Agreement to finance a portion of our future growth, and these factors 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. Volatility in the global financial markets, significant losses in financial institutions’ U.S. energy loan portfolios, or environmental and social concerns may lead to a contraction in credit availability impacting our ability to finance our operations or our ability to refinance the New Credit AgreementsAgreement or other outstanding indebtedness. An increase in interest rates could increase our interest expense and materially adversely affect our financial condition. A significant reduction in cash flow from operations or the availability of credit could materially and adversely affect our ability to carry out our development plan, our cash available for distribution and operating results.

Concerns over global economic conditions, energy costs, supply chain disruptions, the potential for significant new tariffs, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Between 2022 and 2024, the Federal Reserve raised the target range for the federal funds rate in an effort to curb inflation. InAs Septemberof 2024December and31, November 2024,2025, the Federal Reserve lowered theReserve’s target range for the federal funds rate towas its current range of 4.25%3.50% to 4.5%3.75% in light of the progress on inflation. In December 2024,2025, inflation was 2.9%.2.7%. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services.

The majority of the scientific community has concluded that climate change may result in more frequent and/or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. For example, our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, thunderstorms, tornadoes and snow or ice storms, or other climate-related events such as wildfires and floods, in each case which may cause a loss of operational efficiency or production from temporary cessation of activity or lost or damaged facilities and equipment. Further, these types of interruptions could result in a decrease in the volumes supplied to our gathering systems, and delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering and processing facilities, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our third-party customers and thereby give rise to certain termination rights or other liabilities under our contracts. Such extreme weather conditions and events could also impact other areas of our operations, including the costs or availability of insurance, access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary resources, such as water, and third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. Given that our operations are concentrated exclusively in the Anadarko Basin, a number of our properties could experience any of the same weather 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 geographically diversified portfolio of properties. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning.

IncreasingIncreased attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial behavior, societal pressure on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives at the government, regulator, corporate and/or investor community levels, including alternative energy requirements, new fuel consumption standards, energy conservation, enhanced disclosure obligations and emissions reductions measures and responsible energy development; technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Such developments may also adversely impact, among other things, our stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business.

The long-term trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. For example, in January 2021, the Biden administration directed the U.S. Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations. In August 2022, the U.S. Court of Appeals vacated and remanded the federal district court’s decision to block the pause on new oil and gas leasing, and the federal district court shortly thereafter enjoined the DOI from implementing the pause in the thirteen states that had challenged the pause, including Oklahoma and Texas. Litigation over leasing remains ongoing. However, in January 2025, President Trump issued executive orders (i) reversing the Biden administration’s leasing pause and executive orders withdrawing certain lands and waters from federal oil and gas leasing and (ii) directing all federal agencies to facilitate the leasing, siting, and generation of domestic energy resources, including on federal lands and waters. In addition, in November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule sought to impose emissions reduction standards on both new and existing sources in the oil and natural gas industry, expand the scope of Clean Air Act (“CAA”) regulation by making regulations in Subpart OOOOa more stringent and creating a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA. In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule sought to remove an emissions monitoring exemption for small wellhead-only sites and create a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters,” triggering certain investigation and repair requirements. In December 2023, the EPA announced a final rule, later published on March 8, 2024, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply. Fines and penalties for violation of these rules can be substantial. However, the final rule is subject to ongoing litigation but remains in effect. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, in March 2025, EPA announced its intention to reconsider the Marh 8, 2024 ule, including Suparts OOOOb and OOOOc. By interim final rule published on July 3, 2025, and final rule published on December 3, 2025, EPA provided extensions for most compliance deadlines for equipment, leaks, and state plans under OOOOb and OOOOc to January 22, 2027. A final EPA rule reconsidering requirements promulgated under OOOOb and OOOOc is expected in or around July 2026. Consequently, future implementation and enforcement of the final rule remains uncertain at this time. Further, in August 2022, the Inflation Reduction Act of 2022 was signed into law, which incentivizesincentivized the reduction of methane emissions by imposing a fee on methane produced by petroleum and natural gas facilities in excess of a specified threshold, among other initiatives. The Inflation Reduction Act amendsamended the CAA to include a Methane Emissions and Waste Reduction Incentive Program, which requiresrequired the EPA to impose a “Waste Emissions Charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit Court of Appeals has commenced. In November 2024, the EPA finalized a regulation to implement the Inflation Reduction Act’s Waste Emissions Charge, which became effective in January, 2025. The fee imposed under the Methane Emissions Reduction Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026. However, in January 2025, Industry associations challenged the Waste Emissions Charge rule in the D.C. Circuit Court of Appeals. Also in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the process to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition,March based2025, onPresident theTrump timingsigned Congress’ Joint Resolution of Disapproval of the rule’sWaste finalizationEmissions Charge, and statementsin fromMay the2025, congressionalEPA Republicans,issued a final rule to remove the Waste Emissions Charge ruleregulations isfrom potentiallythe vulnerableCode of Federal Regulations. Additionally, the One Big Beautiful Bill Act of 2025 delayed the effective date of the WEC until 2034. EPA, in September 2025, also proposed to repealpermanently byremove Congressprogram underobligations from the CongressionalGreenhouse ReviewGas Act,Reporting Program for most source categories and thesuspend Inflationprogram Reductionobligations Actfor maysome also besources subject to amendmentsubpart orW repeal(which throughapplies Congressionalto budgetemission reconciliation.sources in certain segments of the petroleum and natural gas industry) until 2034. Consequently, future implementation and enforcement of these rules remains uncertain at this time. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry as well as our own results of operations, competitive position or financial condition. While the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo (“Loper”) to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. (“Chevron”) and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives are expected to continue. Consequently, legislation and regulatory programs to address climate change or reduce emissions of GHGs could have a material adverse effect on our business, financial condition or results of operations.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions, such as by means of cap and trade programs. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. AtIn theDecember international level, in February 2021, the Biden administration announced reentry of the U.S. into2015, the Paris Agreement (an international agreement from the 21st Conference of the Parties (“COP”) to the United Nations Framework Convention on Climate Change in Paris, France, whichFrance) resulted in an agreement for signatory countries to nationally determine their contributions and set GHG emission reduction goals) along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. In September 2021, the Biden administration publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030. Further, at the 28th COP, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems.goals. In January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change;Change. however,The atwithdrawal became effective in January 2026. In January 2026, President Trump announced the United States will also withdraw from the UN Framework Convention on Climate Change. At the same time, various state and local governments have vowedcommitted to continue to enact regulations to satisfy their proportionate obligations under the Paris Agreement. Most recently, at the 29th Conference of the Parties (“COP29”), delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits. Additionally, participants at COP29 representing 159 countries met to review progress towardfurthering the goals of the GlobalParis Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement.Agreement.

Companies across all industries continue to face increasingincreased scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

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

In addition, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. The EPA also finalized rules under the Clean Water Act (“CWA”) in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. To date, the EPA has taken no further action in response to the 2016 report. In March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica, which went into effect in June 2018 and applies to use of sand as a proppant for hydraulic fracturing. The U.S. Department of the Interior’s Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. Following years of litigation, the BLM rescinded this rule in December 2017. However, California and various environmental groups filed lawsuits in January 2018 challenging the BLM’s rescission of the rule and, in March 2020, the U.S. District Court for the Northern District of California upheld the BLM’s decision to rescind the rule. However, there is ongoing litigation regarding the BLM rules, and future implementation of these rules is uncertain at this time. In April 2024, the BLM finalized a rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases. The final rule took effect in June 2024. However, in May 2024, the states of North Dakota, Texas, Montana, Wyoming, and Utah challenged the rule. In September 2024, the U.S. District Court for the District of North Dakota granted a motion prohibiting the BLM from enforcing the rule against those states pending the outcome of the litigation. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. The BLM has given notice that it is in the process of considering revisions to the final rule and has delayed enforcement of two provisions included in the April 2024 rule until December 10, 2026. The relevant provisions subject to delayed enforcement imposed measurement device and sampling requirements for flares flowing between 1,050 and 6,000 mcf/month and required operators to submit Leak Detection and Repair plans to the state BLM office; however, the obligation to repair leaks required under the regulations remains in effect. The state litigation against the April 2024 rule has been temporarily suspended pending the BLM’s reconsideration of the April 2024 rule. Accordingly, future implementation and enforcement of this rule is uncertain at this time. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and/or habitats. The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. The FWS may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and may materially delay or prohibit land access for natural gas development. In January 2021, the Department of the Interior finalized a rule limiting the application of the MBTA. In October 2021, the Biden administration published two rules that reversed those changes, and in June and July 2022, the FWS issued final rules rescinding Trump-eraprior Trump Administration regulations concerning the definition of “habitat” and critical habitat exclusions. In April 2024, the FWS finalized three rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. In August 2024, environmental groups challenged the new ESA regulations in federal district court, which litigation remains ongoing. However, in January 2025, the Trump administration issued an executive order directing (i) agencies to use, to the maximum extent permissible, the ESA regulation on consultations in emergencies, to facilitate the domestic energy supply and (ii) the Endangered Species Act Committee to meet at least quarterly to ensure a prompt and efficient review of all submissions for potential actions that could facilitate energy development. Additionally, in April 2025, the FWS and National Marine Fisheries Service proposed to redefine “harm” to mean affirmative acts that are directed immediately and intentionally against a particular animal, excluding acts or omissions that indirectly cause injury. Additionally, in November 2025, the Trump Administration proposed several rules that would significantly alter ESA protections for plants and animals. One proposed rule would rescind a rule that automatically extends protections for endangered species to threatened species. Another proposed rule would change regulations for listing species as endangered or threatened as well as for designating critical habitats. Additionally, a third proposed rule would reinstate the framework for evaluating the benefits and cost of designating a critical habitat by considering factors like economic impact, impact on national security, and other relevant impacts. The U.S. Fish and Wildlife Service is expected to issue final rules in 2026. The designation of previously unprotected species as threatened or endangered or new critical or suitable habitat designations in areas where we conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business, and it is possible the new rules could increase the portion of our lease areas that could be designated as critical habitat. Similar protections are offered to migratory birds under the MBTA, which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the United States. However, in April 2025, the U.S. Department of Interior issued a memo, M-37085, to repeal M-37065, which had previously declared that the Migratory Bird Treaty Act prohibited both the intentional and incidental “take” of migratory birds. The memo restored M-37050, clarifying that only the intentional “take” of migratory birds is prohibited. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered or further changes to regulations could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.

Our partnership agreement provides that we distribute each quarter all of our available cash, which we define as cash on hand at the end of each quarter, less reserves established by our general partner. As a result, we expect to rely primarily upon our cash reserves and external financing sources, including the issuance of additional common units and other partnership securities and borrowings under our RevolvingNew Credit Agreement, to fund future acquisitions and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our available cash may impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are and will be no limitations in our partnership agreement or the New Credit AgreementsAgreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our business strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

If at any time our general partner and its affiliates own more than 95% of the then outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act of 1934, as amended (the “Exchange Act”).Act.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. As a newly public company, we are not required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report to be filed with the SEC, but we are required to disclose material changes made to our internal controls and procedures on a quarterly basis. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in Oklahoma, KansasKansas, Texas, New Mexico and Texas,Colorado among other states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in Oklahoma, KansasKansas, Texas, New Mexico and Texas.Colorado. OklahomaOklahoma, Kansas, New Mexico and KansasColorado each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or entity-level income tax. It is the responsibility of each unitholder to file its own U.S. federal, state and local tax returns, as applicable.

We are an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Anadarko Basin region of Western Oklahoma, Southern Kansas and the panhandle of Texas; the San Juan Basin region of New Mexico and Colorado; and the Permian Basin region of West Texas, and we operate approximately 5,00012,000 PDP wells.

Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego, Woodford and MississippianMississippian, Mancos and Fruitland formations. Our experience in the Anadarko Basin andacross these formations allows us to generate significant cash available for distribution from these low declining assets in a variety of commodity price environments. We also own an extensive portfolio of complementary midstream assets that are integrated with our upstream operations. These assets include gathering systems, processing plants and water infrastructure. Our midstream assets enhance the value of our properties by allowing us to optimize pricing, increase flow assurance and eliminate third-party costs and inefficiencies. In addition, our owned midstream systems generate third-party revenue.

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand. The oil and natural gas industry is cyclical and commodity prices are highly volatile and we expect continued and increased pricing volatility in the crude oil and natural gas markets. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions,conditions and other substantially variable factorsfactors, influence market conditions for these products. Between January 1, 20232024 and December 31, 2024,2025, NYMEX WTI prices for crude oil ranged from $65.75$55.27 to $93.68$86.91 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.58 to $4.17$5.29 per MMbtu. The war in Ukraine and conflict in the Middle East,East and South America, uncertainty regarding interest rates, global supply chain disruptions, thetariff potentialvolatility, forOPEC+’s significantdecision newto tariffs,increase production in May and July 2025, concerns about a potential economic downturn or recession, and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2025.2026.

Between 2022 and 2024, the Federal Reserve raised the target range for the federal funds rate in an effort to curb inflation. In September 20242025, October 2025 and NovemberDecember 2024,2025 the Federal Reserve lowered the target range for the federal funds rate to its current range of 4.25%3.50% to 4.50%3.75% in light of the reduced inflation. In December 2024,2025, inflation, as measured by the consumer price index, was 2.9%.2.7%. We cannot predict the future inflation rate but to the extent we experience high inflation, we may see cost increases in our operations, including costs for drill rigs, workover rigs, tubulars and other well equipment, as well as increased labor costs. We continue to evaluate actions to mitigate supply chain and inflationary pressures and work closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient. Further, if we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

We have completed six acquisitions in the last two years.years, most notably the IKAV and Sabinal Acquisitions (as defined in Note 3) that closed in September 2025. These acquisitions are reflected in our results of operations as of and after the date of completion for each such acquisition. As a result, periods prior to each such acquisition will not contain the results of such acquired assets which will affect the comparability of our results of operations for certain historical periods. We may continue to grow our operations through acquisitions when economical, including by funding such acquisitions under our RevolvingNew Credit Agreement.

Production increased 13,3206,002 MBoe, or 72%,19%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024. The increase was primarily a result of acquisitions andthat theclosed Corporateduring Reorganization2025 which added approximately 15,8648,271 MBoe, offset by natural declines on existing wells.

Midstream revenue decreasedincreased $2.0$3.2 million, or 8%,13%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023,2024, primarily due to lowerthe third-partyacquisition volumesof flowing through ouradditional midstream facilities forin the yearIKAV endedAcquisition Decemberin 31,September 2024, as compared to the year ended December 31, 2023.2025.

Product sales decreasedincreased $4.0$1.5 million, or 13%,6%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024. This decreaseincrease was primarily duea to the decreases in third-party volume resulting in lower overall product salesresult of $4.5 million. This decrease was partially offset with anthe increase in the average selling price of ournatural NGLs.gas. These changesincreases corresponded with the decreaseincrease in our cost of product sales noted below.

Gathering and processing expense increased by $66.7$32.7 million, or 169%,31%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023,2024, primarily as a result of higher fuel costs due to higher natural gas prices, the CorporateIKAV ReorganizationAcquisition which added $13.9 million of expenses, and acquisitionschanges in certain purchaser contracts in the second quarter of 2025, which resulted in certain post-production costs that closedwere inpreviously 2023,presented whichas contributeda reduction to increasedgas revenue are now presented as gathering and processing costs of $68.2 million. The increase in gathering expense per Boe is due to BCE-Mach having higher gathering and processing costs per Boe than the Predecessor.expense.

Lease operating expense increased $52.9$83.3 million, or 41%,for46%,for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023,2024, primarily as a result of acquisitions andin the Corporatefourth Reorganizationquarter inof 2023,2024 and throughout 2025, which increased lease operating expenses by $66.4$76.1 million. These increases were partially offset with a $16.5 million reduction in lease operating expense associated with our Predecessor’s lease operating expense, which was driven by a decrease in workover expense, utilities, and contract services. Lease operating expenses per Boe decreasedincreased by $1.24,$1.30, primarily as a result of the lower cost profiles of acquired properties from 2023, and the increase inoil-heavy production from acquiredthe propertiesSabinal asAcquisition discussedthat above.added to our overall cost profile.

Production taxes increased $13.8$3.1 million, or 43%,7%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024. This increase was primarily a result of increased production which resulted in additional production taxes of $16.0$3.5 million, partially offset with a decrease in pricing, which resulted in lower production taxes of $2.2 million.pricing. Production taxes as a percentage of oil, natural gas and NGL sales were consistent from year to year.

Cost of product sales decreasedincreased $4.1$1.9 million, or 14%,8%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024. This decreaseincrease was primarily a result of decreases in third-party volume resulting in lower overall cost of product sales of $4.5 million. This decrease was partially offset with anthe increase in the average purchaseselling price of NGLs.natural gas. These changesincreases correspondedwere consistent with the decreaseincrease in our product sales noted above.

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties increased by $130.8$18.5 million, or 100%,7%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024. The increase is primarily a result of acquisitions and the Corporate Reorganization in 2023 that increasedclosed theduring amortization base.2025.

General and administrative costs increased $13.2$15.8 million, or 48%,39%, for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024. The increase in general and administrative costs was primarily aacquisition resulttransaction expenses of the Corporate Reorganization which added approximately $5.9$17.8 million included in general and administrative expense.expense Additionallyfor therethe wasyear anended increaseDecember in31, our consulting and professional services of $6.1 million due to higher legal costs and additional public company expenses.2025.

We include in this Annual Report the supplemental non-GAAP financial performance measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, our most directly comparable financial measuresmeasure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) loss on derivative instruments, (4) equity-basedimpairment compensationon expense,oil and gas assets, (5) creditloss losseson anddebt extinguishment, (6) equity-based compensation expense and (gain7) lossgain on sale of assets, net.

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial performance measure used by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income adjusted for (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) loss on derivative instruments, (4) impairment on oil and gas assets, (5) loss on debt extinguishment, (6) equity-based compensation expense, (57) credit losses, (6) (gain) loss on sale of assets, net, (7) settlement of asset retirement obligations, (8) cash interest expense, netnet, (9) development costs and (10) change in accrued realized derivative settlements. Development costs include all of our capital expenditures, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measuresmeasure most directly comparable to cash available for distribution areis net income and net cash provided by operating activities.income. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.income.

Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and related notes included in Part I, Item I of this Quarterly Report and also with “Risk Factors” included in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2025. The following information updates the discussion of our financial condition provided in our previous filings,filings and analyzes the changes in the results of operations for the three and six months ended MarchJune 31,30, 2026 and 2025.

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand. The oil and natural gas industry is cyclical and commodity prices are highly volatile and we expect continued and increased pricing volatility in the crude oil and natural gas markets. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions and other substantially variable factors, influence market conditions for these products. Between January 1, 2025 and MarchJune 31,30, 2026, NYMEX WTI prices for crude oil ranged from $55.27 to $102.88$112.95 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $2.70$2.52 to $7.46 per MMbtu.MMBtu. The war in Ukraine and conflict in the Middle East and South America,East, uncertainty regarding interest rates, global supply chain disruptions, tariffthe volatility,potential for significant new tariffs, OPEC+’s decision to increase production in May and July 2025, and concerns about a potential economic downturn or recession, and instability in the financial sectorrecession have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2026.2025.

Between 2022 and 2024, the Federal Reserve raised the target range for the federal funds rate in an effort to curb inflation. In September 2025, October 2025 and December 2025, the Federal Reserve lowered the target range for the federal funds rate to its current range of 3.50% to 3.75% in light of the reduced inflation. In MarchJune 2026, inflation, as measured by the consumer price index, was 3.3%.3.5%. We cannot predict the future inflation rate but to the extent we experience high inflation, we may see cost increases in our operations, including costs for drill rigs, workover rigs, tubulars and other well equipment, as well as increased labor costs. We continue to evaluate actions to mitigate supply chain and inflationary pressures and work closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient. Further, if we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

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

Revenues from oil, natural gas and NGL sales increased $112.8$147.4 million, or 45%,67% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025. This increase was primarily related to a 95%78% production increase, which resulted in increased oil, natural gas and NGL sales of $139.7$100.2 million. TheseAdditionally, increasesthe wereincrease offsetin withoil and NGL prices resulted in an overallincrease in sales of $68.6 million, and the decrease in thenatural averagegas selling price of our products, whichprices resulted in a decrease in oil, natural gas, and NGLgas sales of $26.9$21.4 million.

Production increased 6,8965,943 MBoe, or 95%78% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025. The increase was primarily thea result of the IKAV and Sabinal Acquisitions, which added 6,7196,199 Mboe of production for the three-month period ending MarchJune 31,30, 2026.

For the three-month period ended MarchJune 31,30, 2026, we had realized gainslosses on derivative instruments of $6.9$18.2 million and unrealized lossesgains of $103.8$41.7 million for total lossesgains of $96.9$23.5 million. For the three-month period ended MarchJune 31,30, 2025, we had realized gains on derivative instruments of $1.6$7.0 million and unrealized lossesgains of $42.3$48.6 million for total lossesgains of $40.7$55.6 million. The increase in unrealizedrealized losses is primarily due to the significant increase in oil prices. The increase in realized gains is primarily due to $17.5 million in early settlements from unwinding a portion of our natural gas derivativesprices during the threethree-month month-periodperiod endedending MarchJune 31,30, 2026.

Product sales decreased $0.9$1.0 million, or 11%14% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025. This decrease was primarily a result of a decreases in the average selling price onof natural gas and NGLs.gas. These decreases corresponded with the decrease in our cost of product sales noted below.

Gathering and processing expense increased $31.1$16.2 million, or 110%,51%, and $0.31decreased $0.64 per Boe, or 8%,15%, for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025, primarily as a result of the 159%130% increase in natural gas production and the 18%19% increase in NGL production, driven by the IKAV Acquisition. Additionally,Gathering dueand toprocessing changesexpense inper certainBoe purchaserdecreased contracts in the second quarter of 2025, certain post-production costs that were previously presentedprimarily as a reductionresult toof gasthe revenueSabinal areAcquisition, nowwhere presentedoil asheavy production includes no gathering and processing expense.expense, as well as the lower gathering and processing cost profile of the IKAV properties.

Lease operating expense increased $52.2$48.2 million, or 107%97% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025, primarily due to the IKAV and Sabinal Acquisitions. Lease operating expenses per Boe increased by $0.43$0.69 primarily as a result of the oil-heavy production from the Sabinal Acquisition that added to our overall cost profile.

CostProduction oftaxes productincreased sales decreased $1.2$8.0 million, or 15%77% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025. This decreaseincrease was primarilyin aline result ofwith the decreaseincrease in the average selling price onoil, natural gas and NGLs.NGL These decreases were consistent with the decrease in product sales noted above.sales.

Depreciation,Midstream depletion, amortization and accretionoperating expense for oil and natural gas properties increased by $32.8$1.8 million, or 54%55% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025.2025, Thedue increase is primarilyto the resultacquisition of additional midstream facilities in the IKAV andAcquisition Sabinalin AcquisitionsSeptember which added $1.3 billion to the balance of oil and gas properties subject to depletion.2025.

General and administrative costs decreasedincreased $2.1$1.9 million, or 19%21% for the three-month period ended MarchJune 31,30, 2026, as compared to the three-month period ended MarchJune 31,30, 2025. The decreaseincrease is primarily due to increases in generalcompensation and administrative costs was primarily a resultbenefits of $1.6 million, consulting and professional fees of $1.6 million and equity compensation of $1.3 million. These increases were partially offset by additional cost recovery per the terms of joint operating agreements from acquired wells subsequent to MarchJune 31,30, 2025. These reductions to general and administrative costs were offset by increases in compensation and benefits of $2.1 million, consulting and professional fees of $1.7 million and equity compensation of $1.4 million for the three-month period ended March 31, 2026, as compared to the three-month period ended March 31, 2025.

Our primary sources of liquidity and capital are cash flows generated by operating activities, borrowings under the New Credit Agreement, and proceeds from the issuance of equity and debt. At MarchJune 31,30, 2026, outstanding borrowings under the New Credit Agreement were $1.14$1.18 billion with $5.0 million in letters of credit outstanding, and the remaining availability under the New Credit Agreement was $305.0$270.0 million at MarchJune 31,30, 2026.

Historically, our business plan has focused on acquiring and then exploiting the development and production of our assets. We spent approximately $75.2$171.8 million during the three-monthsix-month period ended MarchJune 31,30, 2026 on development costs and our budget for 2026 is between $315.0$310.0 million and $360.0$340.0 million. For purposes of calculating our cash available for distribution, we define development costs as all of our capital expenditures, other than acquisitions. Our development efforts and capital for 2026 is anticipated to focus on a mix of drilling Oswego, Woodford, Red Fork and Mississippian wells.

During the three-monthsix-month period ended MarchJune 31,30, 2026, we spent approximately $60.9$130.4 million on drilling and completion activities and related equipmentequipment, and spud 3.7 net wells while bringing online 3 net wells, $9.6$31.8 million on remedial workovers and other capital projectsprojects, and $4.7$9.6 million on midstream and other property and equipment capital projects. Our operated drilling program spud 8.7 net wells while bringing online 7.7 net wells for during the six-month period ended June 30, 2026.

Net cash provided by operating activities increased $27.8$51.3 million for the three-monthsix-month period ended MarchJune 31,30, 2026, as compared to the three-monthsix-month period ended MarchJune 31,30, 2025. The increase in net cash provided by operating activities is primarily a result of an increase in cash receipts on settlement of derivative contracts of $12.8 million. In addition, there was an increaseincreases in production across all products,products whichand wasincreases in the average selling price of oil. These increases were offset withby a decrease in the average selling price of allnatural products.gas and a decrease in cash receipts (payments) on settlement of derivative contracts of $13.7 million.

Net cash used in investing activities decreased $17.0$56.4 million for the three-monthsix-month period ended MarchJune 31,30, 2026, as compared to the three-monthsix-month period ended MarchJune 31,30, 2025. The decrease in net cash used in investing activities is primarily a result of a decreasedecreases in cash used into acquisitionsacquire assets of $26.9$98.6 million.million in the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. This was slightly offset by increases in capital expenditures on our oil and gas properties and on our other property and equipment of $5.0$35.7 million and $3.7$5.8 million, respectively.respectively, due to increased drilling and completion activities in the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025.