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

•We cannot predict the impact of armed conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East.

•Dividend payments and repurchases of common stock are at the discretion of our Board of Directors and subject to numerous factors.

The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt anddebt, the payment of cash dividends, if any, the repurchase of our common stock, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2024,2025, oil prices averaged $75.76$64.73 per Bbl, as compared to $77.60$75.76 per Bbl in 2023,2024, ranging from a high of $86.91$80.04 per Bbl in early Aprilmid-January to a low of $65.75$55.27 per Bbl in mid-September,mid-December, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2024,2025, natural gas prices averaged $2.40$3.62 per MMBtu, as compared to $2.66$2.40 per MMBtu in 2023,2024, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2024,2025, natural gas prices ranged from a low of $1.58$2.70 per MMBtu in late MarchAugust to a high of $3.95$5.29 per MMBtu in lateearly December.

•the price and quantity of foreign imports and exports;

•speculative trading ofof, and other financial market conditions affecting, oil and natural gas futures contracts;

•weather conditions and natural disasters, including hurricanesfloods, andfires, tornadoes, droughts, hurricanes, tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin;

•public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturingfracturing, flaring, venting and produced water handling and disposal activities;

•tariffs andtariffs, trade restrictions and other supply chain constraints; and

InflationAlthough inflation in the U.S. has become much more significantsoftened in recent2024 years.and 2025, prices for many services, materials and equipment have remained elevated relative to pre-2022 levels. Since 2022, we have experienced significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Supply and demand fundamentals have been aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as related actions of the U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps. Should oil and natural gas prices remain at their current levels or increase, we expect to be subject to additional supply chain constraints and service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughoutaffecting the U.S. and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flows.

We cannot predict the impact of armed conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle EastEast, and the related humanitarian crises on the global economy, energy markets, geopolitical stability and our business.

Although our leasehold acreage is located primarily in the Delaware Basin, the broaderoccurrence consequencesor threat of terrorist attacks in the U.S. or any of the major energy producing regions of the world or elsewhere, anti-terrorist efforts and other armed conflicts involving the U.S. or other countries, including the conflicts between Russia and Ukraine and in the Middle East, which may include further sanctions, embargoes, export controls, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks,cyberattacks (including cyberattacks targeting energy and pipeline infrastructure), cause disruptions in global supply chains, increase transportation and insurance costs, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. Additionally, destructive forms of protest and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas activities could potentially result in personal injury to persons, damages to property, natural resources or the environment, or lead to extended interruptions of our or our customers’ operations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and gas. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our or our customers’ operations is destroyed or damaged. Expenses related to security and costs for insurance may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. We cannot predict the extent of eitherthese conflict’sevents’ effecteffects on our business and results of operations as well as on the global economy and energy markets.

•the prices at which we sell our production and prevailing basis differentials;

In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak or resurgence of contagious or pandemic diseases, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

At December 31, 2024,2025, approximately 40%39% of our total proved reserves were undeveloped and approximatelyless than 1% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production orproduction, acquiring new properties or securing necessary services and labor in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.

Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in the latter part of 2024 and early in 2025, these price differentials for natural gas remain wide and could widen further in future periods. Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024,2024 and 2025, we may again temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.

A component of our growth has come, and may comecontinue to come, through acquisitions, and our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth.

•potential environmental issues, unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with such acquisitions.

Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.areas and may require additional investments in personnel and infrastructure. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods.

If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have beenwere purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital marketsmarkets, the syndicated bank market and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations.

As of February 18,24, 2025,2026, the maximum facility amount under the Credit Agreement was $3.50 billion, the borrowing base was $3.25 billion and our elected borrowing commitment was $2.25 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). AtAs of February 18,24, 2025,2026, we had available borrowing capacity of approximately $1.55$1.88 billion under our Credit Agreement (after giving effect to outstanding letters of credit and subject to our compliance with the covenants noted below).

As of February 18,24, 2025,2026, the facility amount under the San Mateo Credit Facility was $800.0$1.10 million,billion, and San Mateo had available borrowing capacity of approximately $244.0$296.6 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.05$1.35 billion.

Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a loan based on the secured overnight financing rate administered by the Federal Reserve Bank of New York (“SOFR”). If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Overnight Bank Funding Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the Daily Simple SOFR (as defined in the Credit Agreement) on such day, plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% depending on the level of borrowings under the Credit Agreement. If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% depending on San Mateo’s Consolidated Total Leverage Ratio. The applicable margin for base rate loans and SOFR loans under the San Mateo Credit Facility will be decreased by 0.25% in the event of a Notes Offering (as defined in the San Mateo Credit Facility) or a Qualified IPO (as defined in the San Mateo Credit Facility). If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition.

Interest rates rose significantly during 2022 and remained elevated throughout 2023 and 2024 as the Federal Reserve sought to control inflation. Interest rates may remain high during 2025. Our Credit Agreement and the San Mateo Credit Facility have floating rates tied to SOFR or other interest rate benchmarks that generally increase or decrease alongside changes in the federal funds rates. As a result, interest expense on our existing floating rate debt rose during 2022 and 2023,2023 as the Federal Reserve increased interest rates, and our interest expense remained high during 20242024. andIn may2025, remainthe highFederal duringReserve lowered interest rates three times, resulting in decreased interest expense on our existing floating rate debt in 2025. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes contain, and any future indebtedness we or San Mateo incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our and San Mateo’s ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that restrict our or San Mateo’s ability toto, among other things:

•make certain investmentsinvestments, loans and acquisitions;

•create or incur certain liens;

•engage in transactions with affiliates; and

Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable andpayable, all applicable commitments to extend further credit could be terminated.terminated and the lenders under such debt agreements could seek to foreclose on any liens securing such debt. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indentures governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financingdebt agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

In March 2020, our corporate credit ratings from S&P Global Ratings and Moody’s Investors Service were downgraded in significant part due to the sudden decline in oil prices in early 2020. These corporate credit ratings were subsequently upgraded, and asAs of February 18,24, 2025,2026, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remainedwere “BB-,” “Ba3” and “BB-,BB,” respectively. We cannot guarantee you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. For example, in March 2020, our corporate credit ratings from S&P Global Ratings and Moody’s Investors Services were downgraded in connection with a sudden decline in oil prices in early 2020, although those ratings were subsequently upgraded. Any future downgrade could increase the cost of any indebtedness incurred in the future.

The payment of dividends and the repurchase of shares of our common stock will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock.factors.

In each of the first, second and third quarters of 2024,2025, our Board declared quarterly cash dividends of $0.20$0.3125 per share of common stock. In October 2024,2025, the Board amended our dividend policy to increase the quarterly dividend to $0.25$0.375 per share of common stock and also declared a quarterly cash dividend of $0.25$0.375 per share of common stock. In February 2025,2026, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a quarterly cash dividend of $0.3125$0.375 per share of common stock payable on March 14,10, 20252026 to shareholders of record as of February 28,27, 2025.2026. We intend to continue to pay a quarterly dividend in the future pursuant to the dividend policy adopted by our Board. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available.

WeIn doaddition, not presently intend to repurchase any shares of our common stock. Certaincertain covenants in our Credit Agreement and the indentures governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments onon, or repurchase shares of, our common stock and may cease such payments or repurchases at any time in the future. Any elimination of or downward revision in our dividend payout or Share Repurchase Program could have a material adverse effect on our stock price.

•adverse weather conditions, including hurricanesfloods, andfires, tornadoes, droughts, hurricanes, tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin;

Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implementedestablished newa rulesstatewide establishinginduced protocolsseismicity mitigation and response framework in response to seismic events in New Mexico. TheThese protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production. In addition, if such a seismic event occurred in the area of the Company’s or San Mateo’s operations, the Company or San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. ForPrevious example,seismic events have required the Company and San Mateo to curtail injection volumes and have increased reporting requirements for affected salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols.wells. Any such further events could adversely impact our and San Mateo’s revenues and cash flows.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Additionally, the proceeds of any such insurance may not be received in a timely manner. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 97%98% of our total oil and natural gas production for 20242025 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 20252026 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well opportunities in our South Texas and Haynesville shale positions.position.

Our operations may also be adversely affected by weather conditions and events such as floods, fires, tornadoes, droughts, hurricanes, tropical storms, floodsstorms and inclementsevere wintercold weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut-ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather.

Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. Further, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures being experienced throughoutaffecting the United States and global economy and the oil and natural gas industry may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows.

From time-to-time,time to time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity, financial condition and the ability of San Mateo to attract third-party customers. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Additionally, financing for these development projects may not be available on economically acceptable terms or at all. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. While we have entered into natural gas processing, treating, compression and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. For example, in the fourth quarter of 2024,2025, we experienced temporary oil and natural gas pipeline and processing interruptions due to maintenance and constraints that are estimated to have resulted in approximately 3,0003,600 BOE per day of less production. We may experience similar interruptions and processing capacity constraints in the future as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2025.Basin. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering, treating, compression or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo and its subsidiaries, including Pronto.subsidiaries. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2024,2025, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $1.50$3.06 billion over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.

We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to construct and operate our midstream assets on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West TexasMexico and SouthWest Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

At December 31, 2024,2025, Matador held approximately 198,700212,500 net leasehold and mineral acres in the Delaware Basin, primarily in Eddy and Lea Counties, New Mexico and in Loving, Ward and Winkler Counties, Texas, of which approximately 65,50070,900 net acres, or about 33%, was on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. For example, on August 16, 2022, H.R. 5376, commonly known as the Inflation Reduction Act of 2022 (the “IRA”), was enacted. Pursuant to the IRA, the royalty rate for federal leases issued on or after August 16, 2022 was increased to 16.67 percent. On April 23, 2024, the BLM issued a final rule that revised the BLM’s oil and gas leasing regulations, including aligning royalty rates, rentals and minimum bids with the IRA, and updated the bonding requirements for leasing, development and production. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits, though the ultimate impact is uncertain given the Trump administration’s revocations of related executive orders. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. This process, including any additional requirements that may be implemented due to, or litigation regardingregarding, the process, has the potential to delay or even halt development of future oil and natural gas projects withsubject NEPAto applicability.review under NEPA. See “Business—Regulation—Oil and Natural Gas Regulation.”

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations related to the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant Nationwide Permits (“NWPs”) as such potential permit coverage relates to activities in the oil and natural gas sector, or the federal government could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA).

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect migratory birds or various wildlife.threatened or endangered species. For example, on March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of southeastern New Mexico where we operate. On May 20, 2024, the USFWS issued a final rule listing the dunes sagebrush lizard as endangered. We participate in candidate conservation agreements for the lesser prairie-chicken, as well as the dunes sagebrush lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. The listing of the dunes sagebrush lizard as endangered,our participation in such candidate conservation agreements or the USFWS’s designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.”

Historically, we have generated and carried forward net operating losses (“NOL”) in amounts sufficient to offset substantially all of our taxable income and, thus, have not incurred material federal or state income tax liabilities. As of December 31, 2022, we had utilized all of our federal NOL carryovers. Our federal and state income tax liabilities in 20252026 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods.

Additionally, theU.S. IRAfederal containsincome atax numberlaw ofprovides revisions to the Internal Revenue Code, includingfor a 15% corporate minimum income tax for certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending before the corporation’s current tax year. The impact of the 15% corporate minimum tax will depend on our results of operations each year. While weWe do not expect such minimum tax to have any immediate material impact, we will continue to evaluate its future impact as further information becomes available.impact.

We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

During the year ended December 31, 2024,2025, we completed and began producing oil and natural gas from 124151 gross (101.9121.2 net) operated and 127107 gross (8.38.1 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2024,2025, although we did participate in the drilling and completion of eight12 gross (0.1 net) non-operated Haynesville shale wells that began producing in 2024.2025.

Substantially all of our 20242025 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Ameredev Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin, including the Ameredev Acquisition.Basin.

Our average daily oil equivalent production for the year ended December 31, 20242025 was 207,070 BOE per day, including 119,723 Bbl of oil per day and 524.1 MMcf of natural gas per day, an increase of 21%, as compared to 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023.2024. Our average daily oil production in 20242025 was 99,808119,723 Bbl of oil per day, an increase of 32%,20%, as compared to 75,45799,808 Bbl of oil per day in 2023.2024. This increase in oil production was primarily a result of the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 20242025 was 425.7524.1 MMcf per day, an increase of 26%,23%, as compared to 338.1425.7 MMcf per day in 2023.2024. This increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% and 57% of our total production for each of the years ended December 31, 20242025 and 2023, respectively.2024.

For the year ended December 31, 2024,2025, our oil and natural gas revenues were $3.14$3.24 billion, an increase of 24%3% from oil and natural gas revenues of $2.55$3.14 billion for the year ended December 31, 2023.2024. Our oil revenues increased 29%2% to 2.77$2.84 billion, as compared to $2.14$2.77 billion for the year ended December 31, 2023.2024. The increase in oil revenues resulted from the 33%20% increase in our oil production noted above, which was partially offset by a 3%14% decrease in the weighted average oil price realized for the year ended December 31, 20242025 to $75.89$64.99 per Bbl, as compared to $77.88$75.89 per Bbl realized for the year ended December 31, 2023.2024. Our natural gas revenues decreasedincreased 7% to $371.5$398.6 million, as compared to $400.7$371.5 million for the year ended December 31, 2023.2024. The decreaseincrease in natural gas revenues resulted from a 23% increase in natural gas production for the year ended December 31, 2025 noted above, which was partially offset by a decrease in our weighted average realized natural gas price of $2.08 per Mcf in 2025, as compared to $2.38 per Mcf in 2024, as compared to $3.25 per Mcf in 2023, which was partially offset by the 26% increase in natural gas production for the year ended December 31, 2024 noted above.2024.

At December 31, 2025, our estimated total proved oil and natural gas reserves were 667.0 million BOE, including 376.0 million Bbl of oil and 1.75 Tcf of natural gas, with a Standardized Measure of $6.99 billion and a PV-10 of $8.24 billion. At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. Our estimated total proved reserves of 667.0 million BOE at December 31, 2025 represented a 9% year-over-year increase, as compared to 611.5 million BOE at December 31, 2024 represented a 33% year-over-year increase, as compared to 460.1 million BOE at December 31, 2023.2024. Our estimated proved oil reserves were 376.0 million Bbl at December 31, 2025, an increase of 4%, as compared to 361.8 million Bbl at December 31, 2024, an increase of 33%, as compared to 272.3 million Bbl at December 31, 2023, and our estimated proved natural gas reserves were 1.75 Tcf at December 31, 2025, an increase of 17%, as compared to 1.50 Tcf at December 31, 2024, an increase of 33%, as compared to 1.13 Tcf at December 31, 2023.2024. Proved oil reserves comprised 59%56% of our total proved reserves at eachDecember of31, 2025, as compared to 59% at December 31, 2024 and 2023.2024. At December 31, 2024,2025, 60%61% of our total proved reserves were proved developed reserves, as compared to 63%60% at December 31, 2023.2024. At December 31, 2024,2025, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.

Pronto owns and operatesDuring the Marlansecond Processing Plant, which has a designed inlet capacityquarter of 602025, MMcfSan Mateo completed the expansion of natural gas per day. Pronto is expanding the Marlan Processing Plant toby add an additional plant withadding a designed inlet capacity of 200 MMcf of natural gas per day, whichincluding woulda increasenitrogen rejection unit and additional related facilities. This expansion increased the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day.

At December 31, 2024, following the Pronto Transaction,2025, San Mateo’s midstream system included:

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025 and currently operate nine drilling rigs in the Delaware Basin.2026. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 20252026 estimated capital expenditure budget consists of $1.28$1.35 to $1.47$1.44 billion for D/C/E capital expenditures and $120.0$100.0 to $180.0$110.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 20252026 capital expenditures as well as the estimated 20252026 capital expenditures for other wholly-owned midstream projects. Substantially all of these 20252026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 20252026 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin,areas, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.

As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, weWe intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchasePurchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.2026.

Oil and natural gas revenues. Our oil and natural gas revenues increased $598.2$94.9 million, or 24%,3%, to $3.24 billion for the year ended December 31, 2025, as compared to $3.14 billion for the year ended December 31, 2024,2024. asOur comparedoil revenues increased $67.8 million, or 2%, to $2.55$2.84 billion for the year ended December 31, 2023.2025, Ouras oil revenues increased $627.5 million, or 29%,compared to $2.77 billion for the year ended December 31, 2024, as compared to $2.14 billion for the year ended December 31, 2023.2024. This increase in oil revenues resulted from a 33%20% increase in our oil production to 43.7 million Bbl of oil for the year ended December 31, 2025, as compared to 36.5 million Bbl of oil for the year ended December 31, 2024, as compared to 27.5 million Bbl of oil for the year ended December 31, 2023, which was partially offset by a 3%14% decrease in the weighted average oil price realized for the year ended December 31, 20242025 to $75.89$64.99 per Bbl, as compared to $77.88$75.89 per Bbl realized for the year ended December 31, 2023. The increase in oil production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.2024. Our natural gas revenues decreasedincreased by $29.2$27.1 million, or 7%, to $398.6 million for the year ended December 31, 2025, as compared to $371.5 million for the year ended December 31, 2024, as compared to $400.7 million for the year ended December 31, 2023.2024. The decreaseincrease in natural gas revenues was primarily attributable to a 23% increase in our natural gas production to 191.3 Bcf for the 27%year ended December 31, 2025, as compared to 155.8 Bcf for the year ended December 31, 2024, which was partially offset by a 13% decrease in the weighted average natural gas price realized for the year ended December 31, 20242025 to $2.38$2.08 per Mcf, as compared to $3.25$2.38 per Mcf realized for the year ended December 31, 2023, which was partially offset by a 26% increase in our natural gas production to 155.8 Bcf for the year ended December 31, 2024, as compared to 123.4 Bcf for the year ended December 31, 2023. The increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.2024.

Third-party midstream services revenues. Our third-party midstream services revenues increased $18.9$23.7 million, or 15%,17%, to $164.7 million for the year ended December 31, 2025, as compared to $141.0 million for the year ended December 31, 2024, as compared to $122.2 million for the year ended December 31, 2023.2024. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party producednatural watergas disposalgathering and processing revenues to $56.3$90.3 million for the year ended December 31, 2025, as compared to $67.5 million for the year ended December 31, 2024, as compared to $45.3 million for the year ended December 31, 2023 and (ii) an increase in our oil transportation revenues to $23.7 million for the year ended December 31, 2025, as compared to $17.3 million for the year ended December 31, 2024, aswhich comparedwere partially offset by (iii) a decrease in third-party produced water disposal revenues to $11.0$50.7 million for the year ended December 31, 2023.2025, as compared to $56.3 million for the year ended December 31, 2024.

Sales of purchased natural gas. Our sales of purchased natural gas increased $44.2$58.9 million, or 30%, to $253.0 million for the year ended December 31, 2025, as compared to $194.1 million for the year ended December 31, 2024, as compared to $149.9 million for the year ended December 31, 2023.2024. This increase was primarily the result of a 45%21% increase in natural gas volumes sold,sold which was partially offset byand an 11%8% decreaseincrease in natural gas prices realized. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $18.1 million for the year ended December 31, 2025, as compared to an unrealized gain of $13.3 million for the year ended December 31, 2024,2024. asDuring comparedthe year ended December 31, 2025, the aggregate net fair value of our open oil and natural gas costless collars and natural gas basis differential swap contracts changed from a net asset of approximately $16.0 million to a net asset of approximately $34.1 million, resulting in an unrealized lossgain on derivatives of $1.3approximately $18.1 million for the year ended December 31, 2023.2025. During the year ended December 31, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swapderivative contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023.

Lease operating expenses. Our lease operating expenses increased $97.9$90.7 million, or 40%,28%, to $341.5$415.8 million for the year ended December 31, 2024,2025, as compared to $243.7$325.1 million for the year ended December 31, 2023.2024. On a unit-of-production basis, our lease operating expenses increased 8%6% to $5.47$5.50 per BOE for the year ended December 31, 2024,2025, as compared to $5.06$5.20 per BOE for the year ended December 31, 2023.2024. These increases for the year ended December 31, 2024 were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition,us and other operators (where we own a working interest) and to operating cost inflation duringfor the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024.

Depletion, depreciationTransportation and amortization.processing. Our depletion, depreciationtransportation and amortizationprocessing expenses increased $257.6$8.2 million, or 36%,14%, to $974.3$66.8 million for the year ended December 31, 2024,2025, as compared to $716.7$58.6 million for the year ended December 31, 2023,2024. This increase in transportation and processing expenses is primarily asdue a result ofto the Ameredev Acquisition and a 30%21% increase in our total oil equivalent production between the respectivetwo periods. On a unit-of-production basis, our depletion, depreciationtransportation and amortizationprocessing expenses increaseddecreased 5%6% to $15.59$0.88 per BOE for the year ended December 31, 2024,2025, as compared to $14.90$0.94 per BOE for the year ended December 31, 2023,2024. This decrease per BOE primarily asresulted afrom resultthe mix of revenue contracts, including from San Mateo, between the Ameredevtwo Acquisition.periods.

General and administrative. Our general and administrative expenses increased $17.1$9.6 million, or 15%,8%, to $137.1 million for the year ended December 31, 2025, as compared to $127.5 million for the year ended December 31, 2024, as compared to $110.4 million for the year ended December 31, 2023, primarily due to increased compensation expensespayroll for our existing employees as well as thewith addition of newadditional employees joining Matador to support theour continued growth in ourincreased land, geoscience, drilling, completion, production, midstream and administration functions.functions as a result of our continued growth. Our general and administrative expenses on a unit-of-production basis decreased 11% to $1.81 per BOE for the year ended December 31, 2025, as compared to $2.04 per BOE for the year ended December 31, 2024, as compared to $2.29 per BOE for the year ended December 31, 2023, primarily as a result of the 30%21% increase in our total oil equivalent production between the two periods.

At December 31, 2024,2025, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 6.500% senior notes due 2032 Notes,(the “2032 Notes”), (iii) $750.0 million of outstanding 6.250% senior notes due 2033 Notes,(the “2033 Notes”), (iv) $595.5$398.0 million of borrowings outstanding under the Credit Agreement and (v) approximately $52.9$53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024.2025.

At December 31, 2024,2025, San Mateo had $615.0$883.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0$15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. OnIn NovemberDecember 26, 2024,2025, San Mateo and certain of its lenders entered into an amendment toamended the San Mateo Credit Facility to, among other things:to (i) extend the maturity date of the facility from December 9, 2026 to November 26, 2029, (ii) increase the lender commitments from $535.0$850.0 million to $800.0$1.10 millionbillion, (ii) reduce the borrowing rate and (iii) add sixone new banksbank to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in thelender commitments of the lenders to up to $1.05$1.35 billion.

The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024.2025.

In February 2024,2025, April 20242025 and July 2024,2025, our Board declared quarterly cash dividends of $0.20$0.3125 per share of common stock. In October 2024,2025, the Board amended our dividend policy to increase the quarterly dividend to $0.25$0.375 per share of common stock and also declared a quarterly cash dividend of $0.25$0.375 per share of common stock. In February 2025,2026, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a quarterly cash dividend of $0.3125$0.375 per share of common stock payable on March 14,10, 20252026 to shareholders of record as of February 28,27, 2025.2026.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025. We currently operate nine drilling rigs in the Delaware Basin.2026. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 20252026 estimated capital expenditure budget consists of $1.28$1.35 to $1.47$1.44 billion for D/C/E capital expenditures and $120.0$100.0 to $180.0$110.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 20252026 capital expenditures as well as the estimated 20252026 capital expenditures for other wholly-owned midstream projects. Substantially all of these 20252026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 20252026 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin,areas, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.

As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, weWe intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchasePurchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.2026.

Net cash provided by operating activities increased by $379.1$178.1 million to $2.43 billion for the year ended December 31, 2025 from $2.25 billion for the year ended December 31, 2024, as compared to net cash provided by operating activities of $1.87 billion for the year ended December 31, 2023.2024. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased by $15.0 million to $2.25 billion for the year ended December 31, 2025 from $2.23 billion for the year ended December 31, 2024 from $1.82 billion for the year ended December 31, 2023.2024. This increase was primarily attributable to thea 30%21% increase in total oil equivalent production during 2024,2025, as compared to 2023, which was2024, partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023.prices. Changes in our operating assets and liabilities between Decemberthe 31, 2023 and December 31, 2024periods resulted in a net decrease of approximately $36.9$163.1 million increase in net cash provided by operating activities for the year ended December 31, 2024,2025, as compared to the year ended December 31, 2023.2024.

Our operating cash flows are sensitive to a number of variables,variables including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factorsthat are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

Net cash used in investing activities increaseddecreased by $460.9$1.51 millionbillion to $2.16 billion for the year ended December 31, 2025 from $3.67 billion for the year ended December 31, 2024 from $3.21 billion for the year ended December 31, 2023.2024. This increasedecrease in net cash used in investing activities between the periods was primarily due to (i) a $1.83 billion decrease in expenditures related to the Ameredev Acquisition ofthat $1.83 billionoccurred in September 2024, which(ii) wasa $155.1$115.3 million higherdecrease thanin expenditures related to the Advance Acquisition of $1.68 billion in 2023, (ii) an increase between the periods of $266.8 million in acquisitionsacquisition of oil and natural gas properties,properties and (iii) ana $10.1 million increase in cash provided by proceeds from the sale of assets. The decreases in cash used in investing activities between the periods ofwere $118.2partially offset by (i) a $319.4 million in midstream capital expenditures and (iv) an increase of $30.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin.Basin, These(ii) increasesa were$110.3 partiallymillion offsetdecrease byin proceeds from the sale of ouran equity method investment in Piñonthe parent company of $113.6Piñon Midstream, LLC, and (iii) a $13.9 million forincrease thein yearmidstream endedcapital December 31, 2024.expenditures.

Net Cash Provided by (Used in) Provided by Financing Activities

We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see “Item 1A. Risk Factors” in the Annual Report. ThereExcept as set forth below, there have been no material changes to the risk factors we have disclosed in the Annual Report.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include those described in the “Risk Factors” section of the Annual Report, as well as the following factors, among others: general economic conditions, including the effects of inflation and interest rates; tariffs and trade tensions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and NGLs or the construction, expansion or operation of our midstream assets; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, capital markets, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitionsacquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition (each as defined below); the operating results of and availability of any potential distributions from our joint ventures; weather conditions, environmental conditions and natural disasters; our ability to consummate the Paloma Acquisition and the Ridge Runner Acquisition in the anticipated timeframes or at all; risks related to the satisfaction or waiver of the conditions to closing the Paloma Acquisition and the Ridge Runner Acquisition in the anticipated timeframes or at all; risks related to obtaining the requisite regulatory approvals for the Paloma Acquisition and the Ridge Runner Acquisition; disruption from our acquisitionsacquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitionsacquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition; evolving cybersecurity risks; the risk of litigation and/or regulatory actions related to our acquisitionsacquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition; and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:

•the integration of acquisitionsacquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, with our business;

FirstSecond Quarter Highlights

For the three months ended MarchJune 31,30, 2026, our total oil equivalent production was 18.719.6 million BOE, and our average daily oil equivalent production was 207,594215,631 BOE per day, of which 120,277126,106 Bbl per day, or 58%, was oil and 523.9537.1 MMcf per day, or 42%, was natural gas. Our average daily oil production of 120,277126,106 Bbl per day for the three months ended MarchJune 31,30, 2026 increased 5%3% year-over-year from 115,030122,875 Bbl per day for the three months ended MarchJune 31,30, 2025. Our average daily natural gas production of 523.9537.1 MMcf per day for the three months ended MarchJune 31,30, 2026 increased 4% year-over-year from 501.6516.8 MMcf per day for the three months ended MarchJune 31,30, 2025. The Delaware Basin contributed 100% of our daily oil production and 97% of our daily natural gas production in each of the second quarters of 2026 and 2025.

For the firstsecond quarter of 2026, we reported a net lossincome attributable to Matador shareholders of $35.9$390.7 million, or $0.29$3.15 per diluted common share, on a GAAP basis, primarily resulting from a $255.5 million unrealized loss on derivatives, as compared to net income attributable to Matador shareholders of $240.1$150.2 million, or $1.92$1.21 per diluted common share, for the firstsecond quarter of 2025. For the firstsecond quarter of 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $577.2$781.0 million, as compared to Adjusted EBITDA of $644.2$594.2 million during the firstsecond quarter of 2025.

For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see “—Liquidity and Capital Resources—Non-GAAP Financial Measures.” For more information regarding our financial results for the three and six months ended MarchJune 31,30, 2026, see “—Results of Operations” below.

OurOn 2026August 5, 2026, we increased our estimated capital expenditure budget consists of $1.35 to $1.44 billion for drilling, completing and equipping (“D/C/E”) capital expenditures for 2026 to a range of $1.48 to $1.56 billion from a range of $1.35 to $1.44 billion, which includes our expected D/C/E capital expenditures on acreage acquired in the BLM Acquisition and expected to be acquired in the Paloma Acquisition and Ridge Runner Acquisition. On August 5, 2026, we also adjusted our estimated midstream capital expenditures for 2026 to a range of $145.0 to $165.0 million from a range of $100.0 to $110.0 million for midstream capital expenditures,million, which includes our proportionate share of San Mateo’s estimated 2026 capital expenditures as well as the estimated 2026 capital expenditures for other wholly-owned midstream projects.

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

Oil and natural gas revenues. The increase in oil revenues resulted from the 5% increase in our oil production and the 1%53% increase in the weighted average oil price realized forand the three3% monthsincrease endedin Marchoil 31, 2026, as compared to the three months ended March 31, 2025.production. The decrease in natural gas revenues primarily resulted from the 82%139% decrease in the weighted average natural gas price realized for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025, which was partially offset byand the 4% increase in our natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”

Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $9.0$3.0 million increase in our third-party natural gas gathering and processing revenues during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025,revenues, which was partially offset by a $0.7 million decrease in our third-party water disposal revenues during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.revenues.

Sales of purchased natural gas. The increasedecrease in sales of purchased natural gas was primarily the result of ana 87%49% increasedecrease in natural gas volumesprice sold,realized, which was partially offset by a 31%20% decreaseincrease in natural gas pricevolumes realized in those sales.sold. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statements of operations.

Realized (loss) gain on derivatives. Our realized loss on derivatives was $14.5$72.5 million for the three months ended MarchJune 31,30, 2026, as compared to a realized gain of $2.7$6.9 million for the three months ended MarchJune 31,30, 2025. For the three months ended MarchJune 31,30, 2026, we recorded a net loss of $51.8$171.8 million related to our oil costless collarscollars, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $37.3$99.3 million primarily related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. For the three months ended MarchJune 31,30, 2025, we recorded a net gain of $2.7$6.9 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $4.79$14.97 per Bbl produced during the three months ended MarchJune 31,30, 2026, as compared to no realized gains or losses from oil derivatives during the three months ended MarchJune 31,30, 2025. We realized an average gain on our natural gas derivatives of approximately $0.80$2.03 per Mcf produced during the three months ended MarchJune 31,30, 2026, as compared to an average gain of approximately $0.06$0.15 per Mcf produced during the three months ended MarchJune 31,30, 2025. See Note 7,8, Derivative Financial Instruments, for further details on our derivatives.

Unrealized gain (loss) gain on derivatives. During the three months ended MarchJune 31,30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $221.4$136.0 million from a net assetliability of $34.1$221.4 million at DecemberMarch 31, 2025,2026, resulting in an unrealized lossgain on derivatives of $255.5$85.5 million for the three months ended MarchJune 31,30, 2026. During the three months ended MarchJune 31,30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net assetliability of $21.0$16.3 million from a net asset of $16.0$21.0 million at DecemberMarch 31, 2024,2025, resulting in an unrealized gainloss on derivatives of $5.1$37.3 million for the three months ended MarchJune 31,30, 2025. See Note 7,8, Derivative Financial Instruments, for further details on our derivatives.

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

Lease operating. The increase in lease operating expense was primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest) for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025..

Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 129%520% in average Waha pricing, which was partially offset by a 31%30% increase in volumes purchased due to the weaker market pricing, during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.pricing.

Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization was primarily a result of the 5%4% increase in our total oil equivalent production forand the threeaddition monthsof ended$282.2 Marchmillion 31,of 2026,proved as comparedreserves to the threefull monthscost endedpool Marchas 31,a 2025.result of the BLM Acquisition.

Taxes other than income. The decreaseincrease in taxes other than income iswas primarily due to the increase in oil revenues, partially offset by the decrease in natural gas revenues, partially offset by the increase in oil revenues between the two periods.revenues.

General and administrative. The increase in general and administrative expense was largely attributable to a $14.2 million increase in employee compensation costs, includingas a $6.8result of increased headcount and an $8.2 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. Additionally, the increase in general and administrative expense was due to a $1.3 million increase in director and officer insurance and approximately $1.1 million in transaction costs associated with the Cardinal Acquisition. These increases were partially offset by a $4.5 million increase in capitalized general and administrative expenses.