TXO Partners LP

FORWARD-LOOKING STATEMENTS

Some of the information in this Annual Report on Form 10-K may contain “forward-looking statements.” All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this Annual Report on Form 10-K.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and natural gas liquids (“NGLs”). We disclose important factors that could cause our actual results to differ materially from our expectations as discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statement include:

•commodity price volatility;

•the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations;

•uncertainties about our estimated oil, natural gas and NGL reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;

•the concentration of our operations in the Permian Basin, the San Juan Basin and the Williston Basin;

•difficult and adverse conditions in the domestic and global capital and credit markets;

•lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;

•lack of availability of drilling and production equipment and services;

•potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks;

•failure to realize expected value creation from property acquisitions and trades;

•access to capital and the timing of development expenditures;

•environmental, weather, drilling and other operating risks;

•regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas;

•competition in the oil and natural gas industry;

•loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production;

•our ability to service our indebtedness;

•cost inflation;

•political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, the Israel-Hamas war, attacks in the Red Sea and other continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

•evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insider or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

•risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.

Risk Factor Summary

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units, among other things. You should carefully consider the risks described in “Risk Factors” and the other information in this Annual Report on Form 10-K before investing in our common units. Some of the most significant challenges and risks we face include the following:

Risks Related to Cash Distributions

•We may not have sufficient available cash to pay any quarterly distribution on our common units following the establishment of cash reserves and payment of expenses.

Risks Related to Our Business and the Oil, Natural Gas and NGL Industry

•The volatility of oil, natural gas and NGL prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

•Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

•If commodity prices decline and remain depressed for a prolonged period, production from a significant portion of our properties may become uneconomic and cause downward adjustments of our reserve estimates and write downs of the value of such properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.

•Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations and cash distributions to unitholders.

•We operate certain of our properties through a joint venture over which we have shared control.

•Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition.

•Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, or the threat thereof, could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units.

•We opportunistically use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.

•Our Credit Facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

•Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Risks Related to Environmental and Regulatory Matters

•We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost or feasibility of conducting our operations or expose us to significant liabilities.

•Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil, natural gas and NGL exploration and production activities, and reduce demand for the oil, natural gas and NGLs we produce.

Risks Inherent in an Investment in Us

•Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

•Our partnership agreement replaces our general partner’s fiduciary duties to us and our unitholders with contractual standards governing its duties, and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

•Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain non-citizen unitholders.

•Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors (the “Board”), which could reduce the price at which our common units will trade.

•Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

•Even if our unitholders are dissatisfied, they are limited in their ability to remove our general partner without its consent.

•Control of our general partner may be transferred to a third party without unitholder consent.

•Our general partner may elect to convert or restructure us from a partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

•We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval.

•The NYSE does not require a publicly traded partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.

Tax Risks to Common Unitholders

•Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders could be reduced.

•Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Part I

Items 1 & 2. Business and Properties

Business Overview

We are focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas, and natural gas liquid reserves in North America. Our management team has significant industry experience acquiring and exploiting conventional oil and natural gas properties in multiple resource plays and basins. As a result of such experience, our operations focus primarily on enhancing the development and operation of producing properties through our concentration on efficiency and optimizing exploitation of current wells. Our current acreage positions are concentrated in the Permian Basin of West Texas and New Mexico, the San Juan Basin of New Mexico and Colorado and the Williston Basin of Montana and North Dakota, each of which we believe is characterized by low geologic risk, low decline rates and high recoveries relative to drilling and completion costs.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner which we refer to as “available cash”. We believe the low decline nature of our reserves and the relatively low cost to maintain production combined with our moderate leverage profile will support distributions to our unitholders. The amount of cash available for distribution with respect to any quarter, however, will be dependent on the then-prevailing commodity prices. To mitigate the risk associated with volatile commodity prices and to further enhance the stability of our cash flow available for distributions, from time to time we may opportunistically hedge a portion of our production volumes at prices we deem attractive to mitigate our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. Nevertheless, our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero.

We seek to maintain a flat to low growth production profile through a combination of low-risk development and exploitation of our existing properties, generally funded by cash flow from operating activities, and future acquisitions of producing properties. We believe this will allow us to increase our reserves and production and, over time, to increase distributions to our unitholders. To date we have been successful in offsetting the natural decline in production from reservoir depletion through acquisitions and drilling. Historically, funding sources for our capital expenditures, including acquisitions, have included proceeds from bank borrowings, cash from our partners and cash flow from operating activities. We expect to continue to fund our capital expenditures primarily with cash flow generated by operating activities, but may use borrowings under our Credit Facility in connection with acquisitions in particular. Additionally, we may seek to issue additional equity securities from time to time as market conditions allow to facilitate future acquisitions. Our development budget is approximately $30 - $50 million for 2025.

The members of our management team have over 30 years’ experience in the oil and gas industry on average. Our management team has successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets for more than 30 years, completing hundreds of acquisitions totaling over $15 billion. Additionally, our management team has collectively invested more than $500 million in us since our inception. We believe our management team has the experience, expertise and commitment to create significant value for our unitholders in the form of cash distributions combined with growth in revenues and production.

Our Business Strategies

Our primary business objective is to make increasing distributions to our unitholders over time. To achieve our objective, we intend to execute the following business strategies:

•Focus on long-lived, low decline assets. We believe that by focusing on the exploitation of our existing assets, we can maintain current production using a portion of our operating cash flow, while utilizing the remainder of our operating cash flow to acquire additional assets to exploit and make distributions to our unitholders.

•Maximize ultimate hydrocarbon recovery from our assets through enhancement and optimization of producing properties. We continuously seek efficiencies in our drilling, completion and production techniques to optimize ultimate resource recoveries, rates of return and cash flows. We will continue to work to unlock additional value and will allocate capital towards next generation technologies where applicable. In addition, we intend to take advantage of under-development in basins where we operate by expanding our geologic investigation of additional producing horizons on our acreage and adjacent acreage. We seek to expand our development beyond our known productive areas to add reserves to our inventory at attractive all-in costs.

•Focus on making cash distributions to, and providing long term value for, our unitholders. Our primary goal is to maximize investor returns through cash distributions and flat to low production and reserves growth over time in support of our strategy as a “production and distribution” enterprise.

•Maintain financial flexibility with a conservative capital structure and ample liquidity. We intend to conduct our operations primarily through cash flow generated from operations with a focus on maintaining a disciplined balance sheet with moderate outstanding debt. Due to our strong operating cash flows and liquidity, we have substantial flexibility to fund our capital budget and to potentially accelerate our drilling program as conditions warrant. Our focus is on the economic extraction of hydrocarbons while maintaining a prudent leverage ratio and strong liquidity profile. Although we may use leverage to make accretive acquisitions, we will do so with the long-term goal of maintaining our debt at a level that does not exceed a net debt-to-EBITDAX ratio of one times. Further, we expect that our hedging strategy will reduce our exposure to commodity price volatility.

•Execute attractive acquisitions and optimize assets through effective integration. Our management team has a history of successfully identifying, acquiring and optimizing assets over the past three decades. We believe our acreage positions in the Permian Basin, San Juan Basin and Williston Basin provide opportunities to increase production and reserves through the implementation of mechanical and operational improvements, workovers, behind-pipe completions, secondary and tertiary recovery operations, new development wells and other development activities. We plan to use the expertise of our management team to strategically acquire properties that complement our operations.

Our Strengths

We believe that the following strengths will allow us to successfully execute our business strategies:

•Experienced and personally invested management team with an extensive track record of value creation. We believe our management team’s significant industry experience is a distinct competitive advantage. The members of our management team have over 30 years’ experience in the oil and gas industry on average and have previously held executive roles at XTO Energy Inc. (“XTO”). Our management team has successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets for more than 30 years. Members of our management team have collectively personally invested more than $500 million in us since our inception.

•Stable, long-lived, conventional asset base with low production decline rates. The majority of our interests are in properties that have produced oil and natural gas for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. Our assets are characterized by long-lived reserves with low production decline rates, a stable development cost structure and low-geologic risk developmental drilling opportunities with predictable production profiles. For example, our base decline rate is currently estimated to be approximately 9%.

•Ability to source, integrate and optimize acquisitions. Our management team has demonstrated the ability to source and integrate acquisitions of various sizes. While at XTO, our management team completed hundreds of acquisitions for over $15 billion in consideration and successfully integrated such acquisitions, ultimately driving significant returns for shareholders. We have successfully drawn on this experience to identify and complete multiple acquisitions to establish our anchor positions in the Permian Basin, San Juan Basin and Williston Basin. We expect that our expertise in sourcing and completing acquisitions will allow us to successfully execute additional bolt-on acquisitions in our existing operating areas and, if and when appropriate, additional opportunistic acquisitions.

•Conservatively capitalized balance sheet, strong liquidity profile and financial flexibility. We have a strong and conservative financial position that allows us to effectively allocate capital and grow our reserves and production. Due to the significant existing vertical production and the predictable low-decline profiles associated with our existing production, our business generates significant operating cash flows. We expect to maintain a debt level that does not exceed a net debt-to-EBITDAX ratio of one times and to have substantial liquidity, which will provide us with further financial flexibility to fund our capital expenditures and grow production and reserves as part of our existing strategic plan. We may also opportunistically hedge to protect our future operating cash flows from volatility in commodity prices.

Our Properties

As of December 31, 2024, our assets consisted of 1,117,628 gross (549,229 net) leasehold and mineral acres located primarily in the Permian Basin, San Juan Basin and Williston Basin. As of December 31, 2024, our total estimated proved reserves were approximately 94 MMBoe, of which approximately 65% were liquids and approximately 89% were proved developed, both on a Boe basis. In 2024, we produced an average of 23,387 Boe per day, approximately 66% of which came from assets operated by us.

Permian Basin

We acquired our initial 79,970 gross leasehold and mineral acres in the Permian Basin in 2012 and 2013. We subsequently acquired 11,929 additional gross leasehold acres through leasing and multiple bolt-on acquisitions. In November 2021, we acquired producing properties, including 24,052 gross leasehold acres and a CO 2 processing plant in the Permian Basin within New Mexico and CO 2 assets in Colorado (the “Vacuum Properties”) from Chevron Corporation (“Chevron”). In December 2021, we acquired additional producing properties, including 21,112 gross leasehold acres in the Permian Basin within Texas from Chevron (the “Andrews Parker Acquisition”). We refer to these together as the “2021 Acquisitions.” In August 2022 we acquired additional interests in our producing properties and CO 2 gas processing plant in the Permian Basin of New Mexico (the “Additional Interest Vacuum Acquisition”).

The Permian Basin is one of the oldest and most prolific producing basins in North America. Consisting of approximately 75,000 square miles centered around Midland, Texas, the Permian spans across west Texas and southeast New Mexico. The Permian Basin has been a significant source of oil production in the United States since the 1920s and, according to the U.S. Energy Information Administration (“EIA”), accounted for approximately 48% of all oil production and approximately 23% of all natural gas production in the United States as of December 31, 2024. While horizontal development is the primary focus for many operators, there continues to be significant conventional oil and gas drilling throughout the Permian Basin. Through enhanced oil recovery methods such as CO 2 injection, operators like us are able to unlock incremental additional hydrocarbon production in these older, conventional assets at comparatively lower costs as compared to the drilling and completion costs of horizontal wells.

Our management team believes the development and exploitation of conventional assets in the Permian Basin is among the most economic oil and natural gas plays in the United States. Since completing the 2021 Acquisitions, we initially focused our efforts on returning wells to production as well as on other low-risk maintenance projects. Recently, we have increased our drilling and recompletion work. Substantially all of our acreage in the Permian Basin is held by production, which means we do not have to drill any wells to maintain ownership of our leases. We drilled or participated in the drilling of 6 gross wells in the Permian Basin during 2024. Based on current commodity prices, we expect to drill or participate in the drilling of approximately 1 gross well in 2025. We recompleted 3 gross wells in the Permian Basin in 2024 and expect to recomplete approximately 7 gross wells in 2025. Our base decline rate for our Permian Basin properties is currently estimated to be approximately 6%.

San Juan Basin

We acquired our initial 175,376 gross leasehold and mineral acres in the San Juan Basin in 2012 and 2013. We subsequently acquired 273,187 additional gross leasehold and mineral acres in June 2020.

The San Juan Basin covers approximately 7,500 square miles in northwestern New Mexico, southwestern Colorado, and parts of Utah and Arizona. Primarily producing natural gas, the San Juan Basin has multiple different formation targets including conventional and unconventional tight sands, coalbed methane and shale. The San Juan is one of the oldest producing basins in the United States, with the first conventional natural gas well drilled in 1921. With the discovery and development of coalbed methane reserves, the San Juan Basin was one of the most prolific natural gas basins in the United States in the 1980s and 1990s. Development activity within the San Juan Basin continued at a significant pace until 2008. With the collapse of commodity prices in 2007, development activity dropped to a very low rate, falling from approximately 40 drilling rigs into 2007 to less than five rigs by 2012. More recently, however, activity within the San Juan Basin has picked up through continued exploration of the unconventional Mancos Shale play. In 2016, the United States Geological Survey (“USGS”) estimated that there were 66.3 trillion cubic feet of recoverable natural gas in the Mancos Shale, which is a forty-fold increase from the 1.6 trillion cubic feet of recoverable natural gas estimated by USGS in 2003.

Our San Juan acreage includes substantial, predictable, low-decline natural gas production that provides for relatively stable cash flows. Our base decline rate for our San Juan Basin properties is currently estimated to be approximately 8%. Our existing production comes from primarily coalbed methane wells. Substantially all of our acreage in the San Juan Basin is held by production. Additionally, as of December 31, 2024, we own 84,679 gross acres in New Mexico in the Mancos Shale. We believe our Mancos Shale properties offer us significant potential upside that is held by production.

We drilled or participated in the drilling of 18 gross wells in the San Juan Basin during 2024. We expect to drill or participate in the drilling of approximately 14 gross wells in 2025 but we will periodically reassess our plans given the volatility in natural gas prices. We recompleted 14 gross wells in the San Juan Basin in 2024 and we expect to recomplete no gross wells in 2025.

Williston Basin

We acquired our initial 273,625 gross leasehold and mineral acres in the Williston Basin in 2024 in the Eagle Mountain Energy Partners and Kaiser Francis acquisitions (“the Williston Basin acquisitions”).

Known today primarily for the Bakken formation, the Williston Basin of eastern Montana, western North Dakota, South Dakota, and southern Saskatchewan encompasses over 300,000 square miles. The Bakken formation was discovered to contain oil in 1953 and was primarily seen as the source rock feeding shallower conventional petroleum deposits. According to the EIA, the Bakken region produced an average of 1.2 million barrels of oil per day, accounting for 9% of total U.S. crude oil production. Additionally, 842 new wells were drilled in 2024 with an average of 34 active drilling rigs.

Our management team believes the development and exploitation of our non-conventional assets in the Williston Basin is among the most economic oil and natural gas plays in our portfolio. We expect that we will focus almost 50% of our drilling and recompletion work in 2025 in the Williston Basin assets. Substantially all of our acreage in the Williston Basin is held by production, which means we do not have to drill any wells to maintain ownership of our leases. We drilled or participated in the drilling of 2 gross wells in the Williston Basin during 2024. Based on current commodity prices, we expect to drill or participate in the drilling of approximately 6 gross wells in 2025. We recompleted 5 gross wells in the Williston Basin in 2024 and expect to recomplete approximately 3 gross wells in 2025. Our base decline rate for our Williston Basin properties is currently estimated to be approximately 17%.

2024 Revenue Breakdown

For year ended December 31, 2024, our consolidated revenues were derived 66% from oil revenues, 24% from natural gas revenues and 10% from NGL revenues, in each case excluding the unrealized effects of our commodity derivative contracts. After giving effect to unrealized commodity derivative contracts, our revenues were derived 70% from oil revenues, 20% from natural gas revenues and 10% from NGL revenues over the same period. For the year ended December 31, 2024, our total average production was 23,387 Boe/d (approximately 32% oil, 54% natural gas, and 14% NGLs). Over the same period, our average production in the Permian Basin was 6,961 Boe/d (approximately 84% oil, 3% natural gas, and 13% NGLs), our average production in the San Juan Basin was 13,143 Boe/d (approximately 1% oil, 83% natural gas, and 16% NGLs) and our average production in the Williston Basin was 1,926 Boe/d (approximately 78% oil, 11% natural gas, and 11% NGLs). Our average daily production in the Williston Basin for the period subsequent to completion of the Williston Basin acquisitions was 5,668 Boe/d.

Development Plan and Capital Budget

Historically, our business plan has focused on acquiring and then exploiting producing assets. Funding sources for our acquisitions have included proceeds from bank borrowings, cash from our partners and cash flow from operating activities. We incurred $28.0 million of development capital in 2024 and expect to incur approximately $30 - $50 million for development in 2025. Much of our development time and capital is spent on workovers, recompletions and field optimizations of existing assets. We expect to use the additional information derived from this exploitation to inform our decisions about additional drilling opportunities to pursue, either in recently acquired assets or new acquisitions. To the extent that we complete any acquisitions during 2025, we may reduce our other expected capital plans to offset the acquisition cost and to temper production growth in favor of distributions to our unitholders.

During 2024, we spent approximately $17.4 million to drill 26 gross wells (4.3 net wells) and on related equipment, $8.5 million on recompletions of existing wells, $2.0 million on capital workovers and $0.1 million on other projects. We spent approximately $10.2 million in the Permian Basin, approximately $5.0 million in the San Juan Basin and approximately $12.8 million in the Williston Basin in 2024.

We expect to allocate a portion of our 2025 budget to projects focused on enhancing existing production. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2025 capital development programs from cash flow from operations. We held our 2024 capital program essentially flat at $28.0 million compared to $29.8 million in 2023.

Oil, Natural Gas and NGL Data

Reserves

Summary of Oil, Natural Gas and NGL Reserves. The following table presents our estimated net proved oil, natural gas and NGL reserves as of December 31, 2024, 2023 and 2022. The reserve estimates presented in the table below are based on reports prepared by Cawley, Gillespie & Associates, our independent petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting.

(1)Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $75.48 per barrel for oil and $2.13 per MMBtu for natural gas at December 31, 2024, were $78.22 per barrel for oil and $2.64 per MMBtu for natural gas at December 31, 2023 and were $93.67 per barrel for oil and $6.36 per MMBtu for natural gas at December 31, 2022. The base prices were based upon Henry Hub and WTI-Cushing spot prices, respectively. These base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these net adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $73.73 per barrel for oil,

$17.70 per barrel for NGLs and $1.14 per Mcf for natural gas for the year ended December 31, 2024, $76.58 per barrel for oil, $18.44 per barrel for NGLs and $1.58 per Mcf for natural gas for the year ended December 31, 2023 and $92.94 per barrel for oil, $29.72 per barrel for NGLs and $4.35 per Mcf for natural gas for the year ended December 31, 2022.

(2)PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Our PV-10 has historically been computed on the same basis as our standardized measure of discounted future net cash flows (“Standardized Measure”), the most comparable measure under GAAP, but does not include a provision for either future well abandonment costs or the Texas gross margin tax. PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of either well abandonment costs or income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

Additional information regarding our proved reserves and estimated future cash flows therefrom can be found in the notes to our financial statements included in Item 8 and in the reserve reports prepared by Cawley, Gillespie & Associates that are filed as exhibits.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2024, 2023 and 2022 included in this Annual Report on Form 10-K are based on evaluations prepared by the independent petroleum engineering firm of Cawley, Gillespie & Associates in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.

Under SEC rules, proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. If deterministic methods are used, the term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Our independent reserve engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and estimated ultimate recoveries (“EURs”) per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). All of our proved undeveloped reserves as of December 31, 2024, 2023 and 2022, relate to locations that are one offset away from an existing well.

Internal Controls

Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their preparation of reserve estimates. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” for more information. The reserves engineering group is responsible for the internal review of reserve estimates and includes Brandon Hudson, our Vice President—Reservoir Engineering. The

Reservoir Engineering Vice President is primarily responsible for overseeing the preparation of our reserve estimates and has more than 15 years of experience as a reserve engineer. The reserves engineering group is independent of any of our operating areas. The Reservoir Engineering Vice President is directly responsible for overseeing the reserves engineering group. The reserves engineering group reviews the estimates with our third-party petroleum consultants, Cawley, Gillespie & Associates, an independent petroleum engineering firm.

Cawley, Gillespie & Associates is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator that prepared the reserve report was W. Todd Brooker, P.E., President at Cawley Gillespie. Mr. Brooker has been a Petroleum Consultant at Cawley, Gillespie & Associates since 1992 and became President in 2017. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462) and a member of the Society of Petroleum Evaluation Engineers (SPEE) and the Society of Petroleum Engineers (SPE). Mr. Brooker meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Mr. Brooker is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2024, our proved undeveloped reserves were composed of 9,297.3 MBbls of oil, 599.5 MBbls of NGLs and 1,022.0 MMcf of natural gas for a total of 10,067.1 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs, for the years ended December 31, 2024, 2023 and 2022 (in MBoe):

Revisions of previous estimates of 52 MBoe during the year ended December 31, 2024 resulted primarily from forecast changes (83 MBoe) partially offset by lower commodity prices and higher costs ((31) MBoe). Revisions of previous estimates of (13,813) MBoe during the year ended December 31, 2023 resulted primarily from forecast changes due to our development plans to reduce the duration of the proved undeveloped reserves from five years to two years ((13,300) MBoe) and lower commodity prices and higher costs ((513) MBoe). Revisions of previous estimates of ((991) MBoe) during the year ended December 31, 2022 resulted primarily from forecast changes ((1,078) MBoe) partially offset by higher commodity prices (87 MBoe).

We converted none of our proved undeveloped reserves into proved developed reserves in 2024. Costs incurred relating to the development of oil and natural gas reserves were $28.0 million during the year ended December 31, 2024. We converted none of our proved undeveloped reserves into proved developed reserves in 2023. Costs incurred relating to the development of oil and natural gas reserves were $29.8 million during the year ended December 31, 2023. We converted 483.5 MBoe of our proved undeveloped reserves into proved developed reserves in 2022. Costs incurred relating to the development of oil and natural gas reserves were $29.8 million during the year ended December 31, 2022.

We drilled or participated in the drilling of 6 gross wells in the Permian Basin during 2022, 19 gross wells in the Permian Basin during 2023, and 6 gross wells in the Permian Basin during 2024. We expect to drill or participate in the drilling of approximately 1 gross well in the Permian Basin during 2025. Also, we participated in the drilling of 18 gross wells in the San Juan Basin during 2022, 19 gross wells in the San Juan Basin during 2023, and 18 gross wells in the San Juan Basin during 2024. We expect to drill or participate in the drilling of approximately 14 gross wells in the San Juan Basin during 2025. In addition, we participated in the drilling of 2 gross wells in the Williston Basin during 2024. We expect to drill or participate in the drilling of approximately 6 gross wells in the Williston Basin during 2025

All of our PUD drilling locations are scheduled to be drilled within two years of December 31, 2024. We drilled and completed or participated in the drilling and completion of no PUD locations during 2024. We anticipate drilling and completing or participating in the drilling and completion of approximately 16 PUD locations during 2025 and 18 during 2026. These PUD locations relate to 10.1 MMBoe of PUD reserves. Our development costs relating to the development of our PUDs at December 31, 2024 are projected to be $25.1 million in 2025 and $27.8 million in 2026 for a total of $52.9 million of future development costs. All of these PUD drilling locations are part of a development plan adopted by management. We expect that the cash flow generated by our existing wells, in addition to availability under our Credit Agreement, will be sufficient to fund our drilling program, maintenance capital expenditures and PUD conversion into proved developed reserves in accordance with our development schedule. Please see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Natural Gas, Oil and NGL Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding our production and operating data for the periods indicated.

Production data:

Sales:

Average realized sales prices:

Expense per Boe:

Productive Wells

As of December 31, 2024, we owned interests in the following number of productive wells:

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2024 relating to our developed and undeveloped acreage. Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Drilling Results

The following table sets forth the results of our drilling activity for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

(1)These 26 wells do not include any gross wells drilled by other operators during the year ended December 31, 2024 in which we elected not to participate.

(2)These 38 wells do not include any gross wells drilled by other operators during the year ended December 31, 2023 in which we elected not to participate.

(3)These 24 wells do not include any gross wells drilled by other operators during the year ended December 31, 2022 in which we elected not to participate.

The following table sets forth information regarding our drilling activities as of December 31, 2024 and December 31, 2023, including with respect to wells awaiting completion, undergoing completion activities and which we have begun drilling subsequent to December 31, 2024 and 2023.

Operations

General

We operated wells responsible for approximately 66% of our production for the year ended December 31, 2024 and 67% for the year ended December 31, 2023. As operator, we design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities on a day-to-day basis. We do not own the drilling rigs or other oil field services equipment used for drilling or maintenance on the properties we operate.

Independent contractors engaged by us provide a portion of the equipment and personnel associated with these activities. We currently engage independent contractors who are engineers and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Virtually all of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies. Maverick Natural Resources Corporation, Occidental Petroleum Corporation and Jo Mill Oil Company are the operators on more than 50% of our non-operated acreage in the Permian Basin.

Our assets include a 50% interest in Cross Timbers Energy, LLC (“Cross Timbers”). Certain affiliates of Exxon and XTO, which we refer to collectively as the “XTO Entities,” collectively own the remaining 50% interest in Cross Timbers. We account for our undivided interest in our investment in Cross Timbers using the proportionate consolidation method, pursuant to which we consolidate our proportionate share of assets (including reserves), liabilities, revenues and expenses of the joint venture. For the year ended December 31, 2024, Cross Timbers represents approximately 24% of our revenues excluding the effects of our commodity derivative contracts and approximately 24% of our proved reserves, on a proportional ownership basis, with assets primarily located in the Permian Basin of Texas and New Mexico and the San Juan Basin of New Mexico and Colorado.

In accordance with the limited liability company agreement governing Cross Timbers, or the “JV LLCA,” Cross Timbers is managed by us and governed by a member management committee comprised of six members, three of whom are appointed by us and three of whom are appointed by the XTO Entities. The JV LLCA requires that certain matters, including certain material contracts or acquisitions, mergers, sale of substantially all assets or other change of control transactions, and transfers of our interest to a third party, be approved by unanimous consent of the voting members of the management committee and therefore require the approval of the XTO Entities. While Cross Timbers is required to distribute all net cash flow to the members pro rata in accordance with their respective membership interests on a quarterly basis pursuant to the JV LLCA, we do not have sole control of the amount of distributions to be made by Cross Timbers.

Cross Timbers is also a party to an operating and services agreement with us pursuant to which we provide all administrative services and conduct operations that are necessary or proper for the development, operation, protection and maintenance of the assets held by Cross Timbers in exchange for a management fee. We earned management fees from Cross Timbers of $5.1 million for year ended December 31, 2024 and $6.2 million for the year ended December 31, 2023.

Marketing and Customers

We market the majority of the natural gas, NGL, crude oil and condensate production from the properties on which we operate. We also market products produced by third party working interest owners who participate in various wells or production units on which we operate. We proportionately pay our royalty owners from the sales attributable to our working interest. Production from our properties is marketed using methods that are consistent with industry practice. Purchasers of our production are selected on the basis of price, credit quality and service reliability. Sales prices are negotiated based on factors normally considered in the industry, such as index or spot price, differentials based on the distance from tailgate of processing plants to end users, commodity quality and prevailing supply and demand conditions. Market volatility due to fluctuating weather conditions, international political developments, overall energy supply and demand, economic growth rates and other factors in the United States and worldwide have had, and will continue to have, a significant effect on energy prices.

We sell the majority of our production under arm’s length contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers, as is customary in our industry. We generally sell natural gas, NGL, crude oil and condensate production through production sale agreements with customary terms and conditions for the oil and natural gas industry at prevailing market prices, adjusted for quality, transportation fees, fractionation fees, regional price differentials, and, in the case of natural gas, energy content. Typically, our sales contracts are based on pricing provisions that are tied to a market index or postings. None of our contracts have minimum volume commitments. We have no commitments beyond twelve months to deliver a fixed or determinable quantity of our oil or natural gas production under our existing contracts. However, our existing contracts for NGL production include commitments for an average of 10 months.

Additionally, we market our excess CO 2 production that we do not use for our enhanced oil recovery operations in the Permian Basin. This excess CO 2 is sold through a combination of an arm’s length contract to an external counterparty and by participating in other CO 2 production working interest owner’s sales under the terms of a unit agreement. The price we receive for this CO 2 is tied to oil prices as is customary in the industry.

For the year ended December 31, 2024, Chevron USA and Gunvor USA together accounted for almost 46% of our total revenues, excluding the impact of our commodity derivatives. For the year ended December 31, 2023, Chevron USA and CIMA Energy together accounted for more than 42% of our total revenues, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our total revenue during such period. We generally do not have long-term contracts with our customers but rather we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, including on a combined basis, to a relatively small number of customers. The loss of any such purchaser could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any such purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers. For more details, see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—We depend upon several significant purchasers for the sale of most of our oil, natural gas and NGL production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.”

Hedging

Our policy is to opportunistically hedge a portion of our production at commodity prices management deems attractive to mitigate our exposure to lower commodity prices. Effective with the Second Amendment entered in June 2023 (the “Second Amendment”), our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required tohedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. See “Management’s

Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for more information. While there is a risk that we may not be able to realize the benefits of rising prices, we enter into hedging agreements because of the benefits of predictable, stable cash flows.

We periodically enter futures contracts, energy swaps, options and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We also enter costless price collars, which set a ceiling and floor price to hedge our exposure to price fluctuations on natural gas sales. When actual commodity prices exceed the ceiling price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the floor price, we receive this difference from the counterparty. If the actual commodity price falls in between the ceiling and floor price, there is no cash settlement. For more details, see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—We opportunistically use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.”

For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in producing oil and natural gas properties, particularly during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

There is also competition between oil and natural gas producers and other industries producing energy and fuel and alternative technologies to reduce energy and fuel consumption. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the state and local jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Oil and Natural Gas Leases

The typical oil lease agreement covering our properties provides for the payment of royalties to the mineral owner for all hydrocarbons produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from less than 12.5% to 57.75%, resulting in a net revenue interest to us of 86.4% on average, on a 100% working interest basis. Based on the Standardized Measure, our value-weighted average net revenue interest on our properties was approximately 86.4%, on a 100% working interest basis, based on our December 31, 2024 reserve report. Substantially all of our leases are held by production and do not require continuous development.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a cursory review of the title to the properties in connection with the acquisition of producing wells and/or additional acreage. Typically, that examination is limited to the seller’s interest. At such time as we determine to conduct drilling operations, we administer a thorough title examination and perform curative work with respect to significant defects in title, prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects and/or other curative matters relative to those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title reports on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant leases and, depending on the materiality of properties, we will review previously obtained title opinions, update title, and in some cases have new title opinions rendered by a licensed oil and gas attorney. Our oil and natural gas properties are subject to customary royalty and perhaps other interests, possible liens for current taxes and potentially other encumbrances which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we hold satisfactory title to all of our material assets. Although title to these properties is subject to certain encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights of way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report on Form 10-K.

Seasonality

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers also may impact this demand. In addition, pipelines, utilities, local distribution companies and industrial end users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

In addition, our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes or lightning storms, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. See “Risk Factors—Risks Related to the Oil, Natural Gas and NGL Industry and Our Business—Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.”

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Regulation Affecting Production

The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and natural gas we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings affecting the oil and natural gas industry are regularly considered by Congress, the states, regulatory authorities, including the FERC, and the courts. We cannot predict when or whether any such proposals may become effective. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation Affecting Sales and Transportation of Commodities

Sales prices of oil, natural gas, condensate and NGLs are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil, natural gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.

The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of natural gas produced by us, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.

In addition to the regulation of natural gas pipeline transportation, FERC has jurisdiction over the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC’s jurisdiction pursuant to the EPAct 2005. Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the NGA to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 up to $1,496,035 per violation per day. The anti-manipulation rule applies to activities of otherwise non jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704 (defined below).

In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, any market participant, including a producer that engages in certain wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to the formation of price indices. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency of the wholesale natural gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.

Through several issuances, FERC has signaled its intention of undertaking a “rigorous review” of reasonably foreseeable greenhouse gas (“GHG”) emissions of new or expanded natural gas transportation facilities and their contribution to climate change, along with the enhanced consideration of other factors such as project need, landowner impacts and environmental justice, in determining the benefits of a project and the significance of its environmental impacts. FERC considers project benefits and environmental impacts in determining whether to issue a certificate to construct a new project under the Natural Gas Act and in its environmental analysis required under the National Environmental Policy Act. On March 24, 2022, FERC announced that it was seeking comments on these draft proposed policies, which initially had been issued as guidance. If adopted, these policy changes may create delays in, and potentially affect the outcomes of, FERC’s future assessments of the need for and environmental impacts of gas pipeline projects in determining whether a project is required by the present or future public convenience or necessity under the Natural Gas Act, which in turn may reduce the development of interstate natural gas pipeline projects and the future availability of pipeline capacity to transport our natural gas production.

The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including NGLs, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2021, FERC established an annual index adjustment equal to the change in the producer price index for finished goods minus 0.21%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market based rate authority (demonstrating the pipeline lacks market power), establishing rates by settlement with all existing shippers, or through a cost of service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for us.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or for new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

On February 17, 2022, FERC issued a Notice of Inquiry, seeking to explore oil pipeline capacity allocation issues that arise when anomalous conditions affect the demand for oil pipeline capacity and what actions FERC should consider to address those allocation issues. This proceeding was initiated in part by the impact of the COVID-19 pandemic on jet fuel shippers’ ability to access capacity on oil pipelines using historic-based prorationing. However, the Notice of Inquiry sought comments on the broader issue of diminished access to oil pipeline capacity during anomalous conditions. Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

In addition to FERC’s regulations, we are required to observe anti market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1,426,319 per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of approximately $1,404,520 or triple the monetary gain to the person for each violation.

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and the protection of the environment and natural resources (including threatened and endangered species and their habitat). Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.

These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and on-going operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. The cost of continued compliance with existing requirements is not expected to materially affect us. However, there is no assurance that compliance costs will remain the same in the future for such existing or any new laws and regulations or that costs related to such future compliance will not have a material adverse effect on our business and operating results.

In addition, governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political and regulatory risks in the United States, including climate change related pledges made by certain elected public officials. Although President Biden issued several executive orders focused on addressing climate change during his time in office, including orders that may impact the costs to produce, or demand for, oil and natural gas, actions undertaken by the second Trump administration may signal a shift in the United States’ energy policy and priorities. For example, on the first day of his second term, President Trump issued various executive orders directing federal agencies to identify and exercise emergency authorities to facilitate conventional energy production, including an executive order that revokes nearly 80 executive orders issued by President Biden. President Trump also initiated the process to withdraw the United States from the Paris climate change agreement, mandated ending financial commitments under the United Nations Framework Convention on Climate Change, and revoked the US International Climate Finance Plan. At this time, it is difficult to predict the long-term impact of such actions on our and our customers’ operations, if any.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Handling Wastes

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our, as well as the oil and natural gas exploration and production industry’s costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes under RCRA.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed of or arranged for the transportation or disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA.

We currently own, lease, or operate numerous properties that have been used for oil, natural gas and NGL exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA and the U.S. Army Corps of Engineers (“Corps”) has issued rules attempting to clarify the federal jurisdictional reach over WOTUS since 2015, including the Navigable Waters Protection Rule during the Trump administration, rules reverting back to the 1986 WOTUS definition during the Biden administration, and rules reinstating the pre-2015 definition finalized in January of 2023. In May 2023, the Supreme Court decided Sackett v. EPA, which sharply curtailed the EPA's and Corps’ jurisdictional reach by limiting the types of wetlands that fell under WOTUS. Sackett codified the definition of WOTUS as only "geographical features that are described in ordinary parlance as "streams, oceans, rivers, and lakes'" and to adjacent wetlands that are "indistinguishable" from those bodies of water due to a continuous surface connection. The EPA issued a final rule consistent with the Sackett decision on August 29, 2023. In September 2023, EPA and the Corps published a direct-to-final rule redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett. The final rule eliminated the “significant nexus” test from consideration when determining federal jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water. The final rule is currently subject to challenges in federal district courts. Future implementation of the WOTUS rule therefore remains uncertain at this time. Depending on the outcome of the pending litigation over the WOTUS rule, we could be subject to additional permitting obligations, which could lead to potential project delays and additional compliance costs.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Subsurface Injections

In the course of our operations, we produce water in addition to oil, natural gas and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near below ground disposal wells used for the injection of natural gas related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and natural gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.

Air Emissions

The federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Recently, there has been increased regulation with respect to air emissions resulting from the oil and natural gas sector. For example, the EPA promulgated rules in 2012 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Standards for Emission of Hazardous Air Pollutants program. With regard to production activities, these final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further requires that a subset of these selected wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.

Additionally, the EPA in July 2023 issued a proposed rule to expand the scope of its Greenhouse Gas Reporting Program for certain petroleum and natural gas facilities. The proposed rule would make the reach of the program both broader and more granular, creating reporting obligations for a wider set of methane and other gas emissions events and requiring increased technical detail for certain other preexisting reporting obligations. The proposed rule indicated an intended effective date of January 1, 2025, but the final rule remains pending at this time and any final effective date thus remains uncertain. Should this rule go into effect without major changes, it could raise our costs of regulatory compliance.

The EPA has also imposed increasingly stringent performance standards on oil and gas operations. In 2016, the EPA issued regulations under NSPS OOOOa that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In December 2023, the EPA published a final version of the rule that expands and strengthens emissions reduction requirements for new, modified, and reconstructed oil and natural gas sources. Specifically, among other things, the rule requires the phase out of routine flaring of natural gas from new oil wells 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 dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. The regulations are subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, future implementation of the standards is uncertain at this time. State agencies have similarly imposed increasing restrictions on emissions from oil and gas operations. For example, in 2022, the New Mexico Environment Department adopted new regulations establishing emission reduction requirements for storage vessels, compressors, turbines, heaters, engines, dehydrators, pneumatic devices, produced water management units, and other equipment and processes. Increasingly stringent requirements on new oil and gas facilities, or the application of new requirements to existing facilities, could result in additional restrictions on operations and increased compliance costs, which could be significant.

The Bureau of Land Management (the “BLM”) also finalized rules (the “BLM methane rule”) in November 2016 that seek to limit methane emissions from exploration and production activities on federal lands by imposing limitations on venting and flaring of natural gas, as well as requirements for the implementation of leak detection and repair programs for certain processes and equipment. After attempts by the Trump administration to delay implementation of the BLM methane rule, and legal challenges both to the BLM methane rule and the delays, the BLM issued a final rule in September 2018 rescinding many of the provisions of the 2016 BLM methane rule, including the requirement to implement leak detection and repair programs, and imposing certain new requirements in a manner the BLM considered would reduce unnecessary compliance obligations on the industry. In November 2022, the BLM issued a new proposed rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. BLM has now issued the final rule, which went into effect on June 10, 2024. The full impact of this new rule on our business is still not fully certain but could result in increases to our operating costs.

The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground level ozone from the current standard of 75 ppb for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards, and completed attainment/non-attainment designations in July 2018. EPA reviewed the 2015 standards in 2020, but retained the standard without revision. In October 2021, the EPA announced it will reconsider its December 2020 decision; however, in August 2023, the EPA announced a new review of the ozone NAAQS after considering advice provided by the Clean Air Scientific Advisory Committee (“CASAC”). As part of its new review, the EPA sought information from the scientific community and the public to guide CASAC’s development of the Integrated Science Assessment as part of its Integrated Review Plan. The first two volumes of the plan were released in December 2024, and the third and final volume, which will provide for quantitative analyses to be considered in the policy assessment, remains forthcoming. Impacts associated with the 2015 standard vary by geographic location, but could include additional fees and more stringent permitting requirements, among other things. None of the counties in which we operate have been designated as non-attainment. In addition, in November 2021, the EPA revised the 2015 ozone NAAQS designations, which expanded a New Mexico non-attainment area to include parts of El Paso County, Texas and designated Weld County, Colorado as a non-attainment area. The EPA’s designation of El Paso was vacated as impermissibly retroactive in June 2023 by the D.C. Circuit Court of Appeal, but the designation of Weld County was upheld. If the EPA were to adopt more stringent NAAQS for ground-level ozone as part of its reconsideration of the December 2020 decision, states are expected to implement more stringent permitting and pollution control requirements as a result of this new final rule, which could apply to our operation. In 2017, the EPA designated certain counties in southeastern New Mexico and West Texas located in the Permian Basin attainment/unclassifiable for the 2015 ozone NAAQS. In June 2022, EPA announced that it is considering a discretionary redesignation for these counties based on current monitoring data and other air quality factors, however EPA has yet to move forward with any redesignation. If the Permian Basin counties in which we operate were redesignated as nonattainment areas, this could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs.

Compliance with one or more of these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. In addition, our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions.

Regulation of GHG Emissions (Climate Change)

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large, GHG emission sources in the United States, including certain onshore and offshore oil and natural gas production sources, which include certain of our operations. As discussed above, federal regulatory action with respect to GHG emissions from the oil and natural gas sector has focused on methane emissions; however, implementation of the federal methane rules is uncertain at this time.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, the Inflation Reduction Act, adopted in 2022, imposes several new climate-related requirements on oil and gas operators, including a first-ever fee on GHG emissions from certain facilities through a fee for leaks or venting of methane, starting at $900 per ton in 2024 and rising to $1,200 per ton in 2025, and to $1,500 per ton in and after 2026. The act also appropriates significant federal funding for renewable energy initiatives. In November 2024, the EPA issued a final rule to implement the emissions charge with an effective date of January 17, 2025 for reporting year 2024 emissions. However, in February 2025, Congress passed a joint resolution to repeal this rule, which is currently pending President Trump’s approval. Further implementation of the emissions charge under the Inflation Reduction Act is therefore uncertain at this time. These regulatory developments, along with ongoing uncertainties, may make it harder for the oil and gas industry to attract capital. Additionally, the Biden administration had highlighted addressing climate change as a priority and had issued several executive orders addressing climate change, including one that calls for substantial action, such as the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. Additionally, the SEC issued a final rule in April 2024 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. However, the rule is stayed pending litigation, and Acting SEC Chairman Uyeda has instructed the SEC to revisit its position on the rule.

In the absence of comprehensive federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Similarly, various states (including Colorado) have adopted or are considering adopting laws requiring certain climate disclosures. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. While President Trump has initiated action to withdraw the United States from the Paris Agreement, this withdrawal is not immediate and may animate stronger actions by various other policymakers, including additional laws or regulations on the production or consumption of the fuels we produce.

Although it is not possible at this time to predict how new laws or regulations in the United States that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. New laws or regulations may also negatively impact our competitive advantage; for example, as discussed above, the Inflation Reduction Act of 2022 includes a variety of tax credits to incentivize the development and use of solar, wind, and other alternative energy sources while imposing several new requirements on oil and gas operators. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. We engage in hydraulic fracturing as part of our operations currently and may continue to do so in the future.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting and separately published in June 2016 an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 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 “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under certain limited circumstances.” To date, the EPA has taken no further action in response to the December 2016 report. However, in April 2024, the BLM issued a final rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases.

Some states have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing operations. State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for oil and natural gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. Aside from state laws, local land use restrictions may restrict drilling in general or hydraulic fracturing in particular. Municipalities may adopt local ordinances attempting to prohibit hydraulic fracturing altogether or, at a minimum, allow such fracturing processes within their jurisdictions to proceed but regulating the time, place and manner of those processes.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. In the event that a new, federal or state level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Activities on Federal Lands and State Lands

Oil and gas exploration, development and production activities on federal lands, including American Indian lands, are administered by the BLM. Operations on federal and tribal lands are frequently subject to permitting delays. Operations on these lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. In July 2020, the White House Council on Environmental Quality (“CEQ”) issued a final rule amending NEPA regulations designed to overhaul the system and speed up federal agencies’ approval of projects. Among other things, the rule narrows the definition of “effects” to exclude the terms “direct,” “indirect,” and “cumulative” and redefine the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.” However, several states and environmental groups have filed challenges to this rulemaking, and CEQ’s amendments are subject to reconsideration and may be subject to reversal or change. CEQ issued an Interim Final Rule in June 2021, which extended the deadline by two years (to September 14, 2023) for federal agencies to develop or update their NEPA implementing procedures to conform to the CEQ regulations, and in April 2022, CEQ issued the Phase 1 Final Rule. The rule finalizes a narrow set of changes to generally restore regulatory provisions that were in effect for decades before the 2020 rule modified them for the first time. In June 2023, the Fiscal Responsibility Act was signed into law by President Biden, which also included reforms to NEPA. In May 2024, the CEQ issued the Final Phase 2 Rule, which took effect on July 1, 2024. However, in January 2025, the D.C. Circuit Court declared in Marin Audubon Society v. Federal Aviation Administration that CEQ lacks authority to issue judicially enforceable regulations under NEPA. Additionally, on January 20, 2025, President Trump issued the Executive Order “Unleashing America Energy”, which directs CEQ to provide guidance on implementing NEPA and propose rescinding CEQ’s existing NEPA implementing regulations within 30 days.

The impact these updates may have to the NEPA regulations and statutory text still remains uncertain and could have an effect on our operations and our ability to obtain governmental permits. We currently have exploration, development and production activities on federal lands and our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial.

Moreover, the Biden administration’s January 2021 climate change executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices. In November 2021, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program,” which assessed the current state of oil and gas leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. In January 2022, a federal district court judge in Washington, D.C. vacated the results of the federal government’s Lease Sale 257, effectively canceling the sale, on the grounds that the federal government failed to consider foreign consumption of oil and natural gas from its GHG emissions analysis. However, in compliance with the Inflation Reduction Act of 2022, the Bureau of Ocean Energy Management (“BOEM”) reinstated Lease Sale 257 in September 2022. In February 2022, a federal district court judge in Louisiana blocked the Biden Administration’s method of calculating the social costs associated with GHGs, and specifically blocked federal agencies from considering the findings from the White House Interagency Working Group, which had been tasked with devising new metrics based on the Obama-era calculations. In response, also in February 2022, the Biden administration asked the court to stay the injunction, and announced that it would be suspending or delaying new federal oil and gas leases. The Biden administration resumed its federal leasing program in April 2022. These recent developments and the Biden administration’s and certain federal courts’ focus on the climate change impacts of federal projects could result in significant changes to the federal oil and gas leasing program in the future. Restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits, could have a material adverse impact on our operators and, in turn, our operations. Notably, executive actions in the early stages of the second Trump Administration have signaled a shift in the Biden-era policies on federal permitting and leasing practices.

In addition, the New Mexico state legislature in 2019 considered House Bill 206, which, if passed, would have enacted an Environmental Review Act comparable to NEPA. Specifically, the Environmental Review Act would require state governmental agencies at all levels to consider the qualitative, technical and economic factors relating to a project that may impact public health, ecosystems and the environment, the long-term as well as short-term benefits and costs of the proposed project, the cumulative impacts of the proposed project, and reasonable alternatives to proposed actions affecting the environment, communities or public health. If reconsidered and enacted in the future, the process contemplated by the Environmental Review Act has the potential, like NEPA, to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects in New Mexico, which costs could be substantial.

Endangered Species and Migratory Birds Considerations

The federal Endangered Species Act (“ESA”), and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of a 2011 settlement agreement, the

U.S. Fish and Wildlife Service (“FWS”) was required to make a determination on listing numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The FWS did not meet that deadline, but continues to review species for listing under the ESA. In March 2024, the Biden Administration issued a final rule concerning the procedures and criteria used for listing, reclassifying, and delisting protected species, and designating critical habitat. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. For example, the FWS issued a final rule in November 2022 listing two Distinct Population Segments (“DPS”) of the Lesser Prairie-Chicken. The listing, which came into effect on January 24, 2023, lists the Southern DPS of the Lesser Prairie-Chicken as endangered, and the Northern DPS as threatened. In addition, in July, 2023, FWS promulgated a Final Rule under Section 10(j) of the Endangered Species Act pertaining to “experimental populations” of threatened or endangered species, enabling the introduction of such species to areas outside their probable historical habitats when the agency finds it to be “necessary and appropriate” under certain criteria. Designation of areas in which we operate as new experimental habitat for threatened or endangered species could slow or narrow our operations and adversely affect our financial performance.

Similarly, if we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. In August 2019, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. Two more rules were finalized in 2020, which narrowed the definition of habitat and revised the criteria for designating and excluding critical habitat. A coalition of states and environmental groups has challenged the three 2019 rules. In November 2022, the U.S. District Court for the Northern District of California remanded (without vacatur) the 2019 rules to FWS for further review, with potential changes to the remanded rules planned for 2023. The 2020 rules were rescinded in the summer of 2022. In addition, the federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. In December 2017, the Department of Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a violation of the Migratory Bird Treaty Act. In August 2020, a federal district court struck down the December 2017 opinion, and the Department of the Interior responded by issuing a new rule in January 2021 that reduced the activities that could incur liability under the MBTA. The Biden administration has since revoked the January 2021 rule; published an Advanced Notice of Proposed Rulemaking announcing an intent to solicit comments to help develop proposed regulations establishing a permitting system to authorize, under certain circumstances, the incidental take of migratory birds; and issued a Director’s Order “establishing criteria for the types of conduct that will be a priority for enforcement activities with respect to incidental take of migratory birds.”

OSHA

We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. There can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Human Capital Resources

As of December 31, 2024, we had 209 total employees, 201 of which were full-time employees. From time to time, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements, and have not experienced any strikes or work stoppages. In general, we believe that employee relations are satisfactory.

We are focused on attracting, engaging, developing, retaining and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with best-in-class training and career development opportunities to enable employees to thrive and achieve their career goals. The health, safety, and well-being of our employees is of the utmost importance.

Available Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and related amendments, exhibits and other information with the Securities and Exchange Commission, or the SEC. You may access and read our filings without charge through the SEC’s website at www.sec.gov or through our website at www.txopartners.com, as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Information contained on, or accessible through, our website shall not be deemed incorporated into and is not a part of this Annual Report on Form 10-K.