Item 1A. Risk Factors
Our business involves a high degree of risk. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Additionally, new risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect financial performance.
If any of the following risks actually occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and our unitholders could lose all or part of their investment.
Risks Related to Cash Distributions
We may not have sufficient available cash to pay any quarterly distribution on our common units following the payment of expenses, funding of development costs and establishment of cash reserves.
We may not have sufficient available cash each quarter to pay distributions on our common units. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses, cash interest, development costs and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development, optimization and exploitation of our oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of available cash that we distribute to our unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:
• the amount of oil, natural gas and NGLs we produce;
• the prices at which we sell our oil, natural gas and NGL production;
• the amount and timing of settlements on our commodity derivative contracts;
• the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;
• the level of our operating costs, including payments to our general partner and its affiliates for general and administrative expenses;
• the restrictive covenants in the New Credit Agreement and other agreements governing indebtedness that limit our ability to pay dividends or distributions in respect of our equity; and
• the level of our interest expenses, which will depend on the amount of our outstanding indebtedness and the applicable interest rate.
Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.
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The amount of our quarterly cash distributions from our available cash, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution and could pay no distribution with respect to any particular quarter.
Our future business performance may be volatile, and our cash flows may be unstable. We do not have a minimum quarterly distribution. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero.
Risks Related to Our Business
Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition, results of operations, liquidity, ability to meet our financial commitments, ability to make our planned capital expenditures and our cash available for distribution.
Our revenues, operating results, cash available for distribution, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGLs we sell. We require substantial expenditures to replace our oil, natural gas and NGL reserves, sustain production and fund our business plans, including our development and exploratory drilling efforts. Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGLs, market uncertainty and other factors that are beyond our control, including:
• worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs, including the potential impact of any significant new tariffs;
• political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;
• actions of OPEC+ including the ability and willingness of the members of OPEC+ and other exporting nations to agree to and maintain oil price and production controls;
• changes in seasonal temperatures, including the number of heating degree days during winter months and cooling degree days during summer months;
• the level of oil, natural gas and NGL exploration, development and production;
• the level of oil, natural gas and NGL inventories;
• the level of U.S. LNG exports;
• the impact on worldwide economic activity of an epidemic, outbreak or other public health events;
• prevailing prices on local price indexes in the areas in which we operate;
• the proximity, capacity, cost and availability of gathering and processing facilities;
• localized and global supply and demand fundamentals and transportation availability;
• the cost of exploring for, developing, producing and transporting reserves;
• the spot price of LNG on world markets;
• changes in ocean freight capacity, which could adversely impact LNG shipping capacity or lead to material interruptions in service or stoppages in LNG transportation;
• political and economic conditions in or affecting major LNG consumption regions or countries, particularly Asia and Europe;
• weather conditions and natural disasters, including those influenced by climate change;
• technological advances affecting energy consumption;
• the impact of energy conservation efforts;
• the price and availability of alternative fuels;
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• activities to restrict the exploration, development and production of oil and natural gas to minimize greenhouse gas (“GHG”) emissions;
• speculative trading in oil and natural gas derivative contracts;
• increased end-user conservation;
• U.S. trade policies and their effect on U.S. oil and natural gas exports;
• expectations about future commodity prices; and
• U.S. federal, state and local and non-U.S. governmental regulation and taxes, including legislation or regulations addressing GHG emissions or requiring the reporting of GHG emissions or climate-related information.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved and reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI and Henry Hub strip prices may adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program, and result in the reduction of some of our proved undeveloped reserves and related PV-10. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash available for distribution, liquidity and ability to meet our financial commitments or cause us to delay our planned capital expenditures.
Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, production and acquisition activities, which are subject to numerous risks beyond our control. For example, we cannot assure you that wells we drill will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil, natural gas and NGLs often involves unprofitable efforts from wells that do not produce sufficient oil, natural gas and NGLs to return a profit at then-realized prices after deducting drilling, operating and other costs. In addition, our cost of drilling, completing and operating wells is often uncertain.
Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “ — Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”
Further, many factors may increase the cost of, curtail, delay or cancel our scheduled drilling projects, including:
• declines in oil, natural gas and NGL prices;
• increases in the cost of, and shortages or delays in the availability of, proppant, acid, equipment, services and qualified personnel or in obtaining water for hydraulic fracturing activities;
• equipment failures, accidents or other unexpected operational events;
• capacity or pressure limitations on gathering systems, processing and treating facilities or other related midstream infrastructure;
• any future lack of available capacity on interconnecting transmission pipelines;
• delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on freshwater sourcing, wastewater disposal, emissions of GHGs and hydraulic fracturing;
• pressure or irregularities in geological formations;
• limited availability of financing on acceptable terms;
• issues related to compliance with or liability arising under environmental laws and regulations;
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• environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the air, surface and subsurface environment;
• compliance with contractual requirements;
• competition for surface locations from other operators that may own rights to drill at certain depths across portions of our leasehold;
• lack of available gathering facilities or delays in construction of gathering facilities;
• adverse weather conditions, such as hurricanes, lightning storms, flooding, tornadoes, snow or ice storms and changes in weather patterns;
• the availability and timely issuance of required governmental permits and licenses;
• title issues or legal disputes regarding leasehold rights; and
• other market limitations in our industry.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
We have specifically identified and scheduled certain drilling locations as an internal estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, availability and cost of sand and other proppant used in hydraulic fracturing operations and acid used for acid stimulation, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution and disposal systems, access to and availability of saltwater disposal systems, regulatory approvals, the cooperation of other working interest owners and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other drilling locations. As such, our actual drilling activities may materially differ from those presently identified.
As a result of the limitations described in this Annual Report, we may be unable to drill many of our identified locations. In addition, although we plan to fund our drilling program entirely with cash flow from operations, if our cash flows are less than we expect or we alter our drilling plans, we may be required to borrow more under the New Credit Agreement than we expect or issue new debt or equity securities in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “ — Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which in turn could have a material adverse effect on the borrowing base under the New Credit Agreement or our future business and results of operations. Additionally, if we curtail or cancel our drilling program, we may be required to reduce our estimated proved reserves, which could in turn reduce the borrowing base under the New Credit Agreement.
Properties that we decide to drill may not yield oil and natural gas in commercially viable quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of geologic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess recoverable reserves, future oil and natural gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally
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consistent with industry practices, but such a review may not reveal all existing or potential problems. Such assessments are inexact and inherently uncertain. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as any groundwater contamination or pipe corrosion, when a review is performed. We also may be unable to obtain contractual indemnities from the seller for liabilities arising prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. For these reasons, the properties we have acquired or will acquire in the future may not produce as expected or may not increase our cash available for distribution.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
As of December 31, 2025, approximately 7% of our total estimated proved reserves were classified as PUDs using SEC Pricing. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PUDs on December 31, 2025 were approximately $1.1 billion over the next five years. Our ability to fund these expenditures is subject to a number of risks. See “— Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Delays in the development of our PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the PV-10 value of our estimated PUDs and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify some of our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our undeveloped reserves to developed reserves or that our PUDs will be economically viable or technically feasible to produce.
Further, SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. As a result, we may be required to reclassify certain of our PUDs if we do not drill those wells within the required five-year timeframe.
Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Difficulties that we face while completing our wells include:
• the ability to fracture stimulate the planned number of stages with the planned amount of proppant;
• the ability to source acid for our acid stimulation completion techniques;
• the ability to run tools through the entire length of the wellbore during completion operations; and
• the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. If our development and production results are less than anticipated, the return on our investment for a particular well or region may not be as attractive as we anticipated, and we could incur material write-downs of our undeveloped acreage and its value could decline in the future.
The marketability of our production is dependent upon gathering, treating, processing and transportation facilities, some of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues could decrease.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of gathering, treating, processing and transportation pipelines, plants and other midstream facilities, a significant portion of which is owned by third parties. Some of our oil and natural gas production is collected from the wellhead by third-party gathering lines and transported to a gas processing or treating facility or transmission pipeline. We do not control these third-party facilities and our access to them may be limited, curtailed or denied. Pipelines, plants, and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, and curtailments of receipts or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. The third-party facilities may
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experience unplanned downtime or maintenance for a variety of reasons outside our control and our production could be materially negatively impacted as a result of such outages. Insufficient production from our wells in the properties we do not operate to support the construction of pipeline facilities by third parties or a significant disruption in the availability of our or third-party midstream facilities or other production facilities could adversely impact our ability to deliver to market or produce our natural gas and thereby causing a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement gathering, treating, processing or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.
If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows and our ability to make cash distributions to our unitholders could be materially adversely affected.
Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the oil, natural gas and produced water that we gather and/or process, our revenues, cash flows and ability to make cash distributions to our unitholders could be materially adversely affected.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary materially from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates of proved reserves to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant change could materially affect the estimated quantities and present value of our reserves. Furthermore, our development plan calls for completing horizontal wells using tighter well spacing and acid stimulation, which may increase the risk that these wells interfere with production from existing or future wells in the same spacing section and horizon, which in turn may result in lower recoverable reserves. There can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated.
You should not assume that the present values of future net cash flows from our reserves presented in this Annual Report are the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in our present value estimates using SEC Pricing. If spot prices or future actual prices are below the prices used in our current reserve estimates, using those prices in estimating proved reserves may result in a decrease in proved reserve volumes due to economic limits. You should not assume that the standardized measure of proved reserves and PV-10 values of our estimated reserves are accurate estimates of the current fair value of our estimated oil, natural gas and NGL reserves.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the
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estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. For example, our estimated proved reserves as of December 31, 2025 were calculated under SEC rules using the unweighted arithmetic average first day of the month prices for the prior 12 months of $3.39/MMBtu for natural gas and $65.34/Bbl for oil at December 31, 2025, which, for certain periods during this period, were substantially different from the available spot prices. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards Codification 932, “Extractive Activities — Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Unless we replace our produced reserves with acquired or developed new reserves, our reserves and production will decline, which would adversely affect our future cash flows, results of operations and cash available for distribution.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas, secure trained personnel and raise additional capital.
Our ability to acquire additional oil and natural gas properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do. Those companies may be able to pay more for oil and natural gas properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Those larger companies may also have a greater ability to continue development activities during periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring natural gas properties, developing reserves, marketing our production, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Our midstream services contracts are generally structured as short-term and long-term, fixed-fee contracts, which may negatively impact our operating margins and cash flow during periods of lower oil and natural gas prices.
We have entered into short-term and long-term, fixed-fee contracts with third parties for gathering, processing and transportation services, including some firm transportation contracts. Under these short-term and long-term, fixed-fee arrangements, our gathering and processing expenses are generally fixed on a per unit basis for the term of the applicable contract and do not automatically adjust in response to a decline in oil and natural gas prices. In the event of a prolonged period of lower commodity prices, our revenue will decline while the per unit fees we pay for natural gas gathering, treating and compression services generally will not, which would negatively impact our operating margins and cash flow. In addition, during periods of depressed oil and natural gas prices, the market prices for such services may be lower than what we are contractually obligated to pay to our current third-party midstream service providers. Furthermore, to the extent certain future taxes or assessments are imposed on certain midstream assets we utilize, under certain circumstances we may be required by our midstream services contracts to reimburse the midstream service provider for such taxes or assessments, which could negatively affect our operating margins and cash flow. Our third-party midstream service providers are under no obligation to renegotiate their contracts with us. Our failure to obtain these services on competitive terms could materially harm our business.
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The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We depend on Mach Resources to provide us services necessary to operate our business. If Mach Resources were unable or unwilling to provide these services, it would result in a disruption in our business that could have an adverse effect on our financial position, financial results and cash flow.
We do not directly employ directors, officers or employees. Pursuant to the new management services agreement entered into with Mach Resources on October 27, 2023 in connection with the closing of the Offering (the “MSA”), an entity that is wholly owned by Tom L. Ward and his family, all of our executive management personnel are employees of Mach Resources, and we use a significant number of Mach Resources’ employees to operate our properties and provide us with general and administrative services. If Mach Resources were to become unable or unwilling to provide such services, we would need to develop these services internally or arrange for the services from another service provider. Developing the capabilities internally or by retaining another service provider could have an adverse effect on our business, and the services, when developed or retained, may not be of the same quality as provided to us by Mach Resources. Additionally, if the MSA were to terminate, we would lose our key personnel.
Certain factors could require us to write down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, drilling and completion results, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash impairment charge to earnings. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. We could experience further material write-downs as a result of other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless and adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 99% of our acreage is held by existing production, the remaining acreage is subject to expiration. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.
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We own non-operating interests in properties developed and operated by third parties and some of our leasehold acreage could be pooled by a third-party operator. As a result, we are unable, or may become unable as a result of pooling, to control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other contractual arrangements. Similarly, our acreage in Oklahoma and Texas may be pooled by third-party operators under state law. If our acreage is involuntarily pooled under state forced pooling statutes, it would reduce our control over such acreage, and we could lose operatorship over a portion of our acreage that we plan to develop.
We may not be able to maximize the value associated with acreage that we own but do not operate in the manner we believe appropriate, or at all. We cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our business, financial condition and results of operations.
We may be unable to make accretive acquisitions or may make opportunistic dispositions. Any such acquisitions, if not integrated or conducted successfully, or such dispositions, if not conducted successfully, may disrupt our business and hinder our growth potential.
We may be unable to make accretive acquisitions or may make opportunistic dispositions. Any such acquisitions, if not integrated or conducted successfully, or such dispositions, if not conducted successfully, may disrupt our business and hinder our growth potential. Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in cash available for distribution. In the future we may make acquisitions of assets or businesses that complement or expand our current business. There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions. In addition, from time to time, we may consider opportunistic dispositions, including dispositions of non-operating properties, having the potential to further limit future production.
The success of completed acquisitions will depend on our ability to effectively integrate the acquired businesses into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, the New Credit Agreement imposes certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could limit our ability to acquire assets and businesses.
Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.
The oil and gas industry is capital-intensive. A number of factors could cause our cash flow to be less than we expect, including the results of our drilling and completion program. Moreover, our capital budgets are based on a number of assumptions, including expected elections by working interest partners, drilling and completion costs, midstream service costs, oil and natural gas prices, and drilling results, and are therefore subject to change. If our cash flows are less than we expect, we decide to pursue acquisitions, or we change our capital budgets, we may be required to borrow more under credit facility than we expect or issue debt or equity securities to consummate such acquisitions or fund our drilling and completion program. The incurrence of additional indebtedness, either through borrowings under the New Credit Agreement, the issuance of additional debt securities or otherwise, would require that a portion of our cash flow from
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operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund capital expenditures, our development plan, acquisitions and cash distributions to unitholders. Additionally, the market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. The issuance of additional equity securities may be dilutive to our unitholders The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things: oil and natural gas prices; actual drilling results; the availability and cost of drilling rigs and labor and other services and equipment; the availability, cost and adequacy of midstream gathering, processing, compression and transportation infrastructure; and regulatory, technological and competitive developments.
Our cash flow from operations and access to capital are subject to a number of variables, including:
• the prices at which our production is sold;
• the amount of our proved reserves;
• the amount of hydrocarbons we are able to produce from existing wells;
• our ability to acquire, locate and produce new reserves;
• the amount of our operating expenses;
• cash settlements from our derivative activities;
• our ability to borrow under the New Credit Agreement; and
• our ability to access the debt and equity capital markets or sell non-core assets.
If our revenues or the borrowing bases under the New Credit Agreement decrease as a result of lower commodity prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to make acquisitions or sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under the New Credit Agreement are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations.
Increased costs of capital could adversely affect our business.
Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.
Changes in the global trade environment, including the imposition of tariffs, could adversely affect our business.
Escalating trade tensions, particularly between the U.S. and Canada, Mexico, China and other countries, may lead to the imposition of tariffs and trade restrictions. We may be materially adversely impacted by tariffs if we are not able to adapt our supply chain strategy. We may also face unanticipated costs in developing our domestic supply chain and increased competition for materials and components in the United States, which also would impact our business and results of operations. The imposition of tariffs may also create uncertainty in our industry. Increases in costs to drill and develop reserves as a result of tariffs coupled with lower commodity prices from increased domestic production could make producing such reserves no longer economically viable or technically feasible. Additionally, existing or future tariffs may negatively affect our customers, suppliers, and manufacturing partners. Such outcomes could adversely affect the amount or timing of our revenues, results of operations or cash flows, and continuing uncertainty could cause sales volatility and price fluctuations. Tariffs, the adoption and expansion of trade restrictions, the occurrence of a trade war, or other governmental action related to tariffs, trade agreements or related policies have the potential to adversely impact our supply chain and access to equipment, and our costs and ability to economically serve certain markets. Any such cost increases or decreases in availability could slow our growth and cause our financial results and operational metrics to suffer. There is uncertainty about the future relationship between the United States and other countries with respect to trade policies, taxes,
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government regulations, and tariffs and we cannot predict whether, and to what extent, U.S. trade policies will change in the future.
We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.
Historically, capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices and drilling activity in our areas of operation and other major shale basins throughout the United States. These cost increases result from a variety of factors beyond our control, such as increases in the cost of sand and other proppant used in hydraulic fracturing operations or acid used for acid stimulation, and steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities. Furthermore, high oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Higher levels of development activity in oil-focused shale basins have also historically resulted in higher levels of associated gas production that places downward pressure on natural gas prices. To the extent natural gas prices decline due to a period of increased associated gas production and we experience service cost inflation during such period, our cash flow, profitability and ability to make distributions to our unitholders may be materially adversely impacted.
The unavailability or high cost of drilling rigs, frac crews, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, frac crews, pipe and other equipment and supplies, including sand and other proppant used in hydraulic fracturing operations and acid used for acid stimulation, as well as for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices or drilling activity in our areas of operation and in other shale basins in the United States, causing periodic shortages of supplies and needed personnel and rapid increases in costs. Increased drilling activity could materially increase the demand for and prices of these goods and services, and we could encounter rising costs and delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to conduct our drilling and development activities, which could result in net production volumes being below our forecasted volumes. In addition, any such negative effect on net production volumes, or significant increases in costs could have a material adverse effect on our cash flow and profitability.
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.
For the year ended December 31, 2025, two purchasers each accounted for more than 10% of our revenue: Phillips 66 Company (23.3%) and NextEra Energy Marketing, LLC (20.6%). We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties — Marketing and Customers” included in Items 1 and 2 of Part I of this Annual Report.
The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond our control, including, but not limited to, the extent of domestic production and imports of oil, the proximity and capacity of oil, natural gas and NGL pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGLs sold in interstate commerce.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.
As of December 31, 2025, we had $1.15 billion outstanding under our New Credit Agreement. In the future, we and our subsidiaries may incur substantial additional indebtedness. The New Credit Agreement contains restrictions on the incurrence of additional indebtedness, and these restrictions will be subject to waiver and a number of significant
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qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial. Additionally, the New Credit Agreement permits us to incur certain amounts of additional indebtedness.
Our level of indebtedness could affect our operations in several ways, including the following:
• requiring us to dedicate a substantial portion of our cash flow from operations to service our debt, thereby reducing the cash available to finance our operating and investing activities;
• limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
• increasing our vulnerability to downturns and adverse developments in our business and industry;
• limiting our ability to raise capital on favorable terms;
• limiting our ability to raise available financing, make investments, lease equipment, sell assets and engage in business combinations;
• making us vulnerable to increases in interest rates;
• putting us at a competitive disadvantage relative to our competitors; and
• limiting our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities, due to covenants contained in our New Credit Agreement, including financial covenants.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
The New Credit Agreement contains a number of significant covenants, including restrictive covenants that, subject to certain qualifications, limit our ability to, among other things:
• make certain payments, including paying dividends or distributions in respect of our equity;
• incur additional indebtedness;
• make loans to others;
• make certain acquisitions and investments;
• make or pay distributions on our common units, if an event of default or borrowing base deficiency exists;
• merge or consolidate with another entity;
• hedge future production or interest rates;
• incur liens;
• sell assets; and
• engage in certain other transactions without the prior consent of the lenders.
In addition, the New Credit Agreement requires us to maintain compliance with certain financial covenants.
The restrictions in the New Credit Agreement also impact our ability to obtain capital to withstand a downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements may impose on us.
A breach of any covenant in the New Credit Agreement will result in a default under our New Credit Agreement and an event of default if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
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Any significant reduction in our borrowing base under the New Credit Agreement as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
The New Credit Agreement limits the amounts we can borrow up to certain borrowing base amounts, which the administrative agent in good faith and in accordance with its usual and customary procedures for evaluating oil and gas loans and related assets at that particular time and otherwise acting in its sole discretion, will determine and which will be approved by the required lenders or all lenders, as applicable in the case of an increase in the borrowing base, on a semi-annual basis based upon projected revenues from our natural gas properties, our commodity derivative contracts securing our loan and certain other information (including, without limitation, the status of title information with respect to the oil and natural gas properties and the existence of any other indebtedness, liabilities, fixed charges, cash flow, business, properties, prospects, management and ownership, hedged and unhedged exposure to price, price and production scenarios, interest rate and operating cost changes). In addition to the scheduled redeterminations, the Company and the required lenders may request unscheduled interim redeterminations of the borrowing base not more than once between scheduled redeterminations. Any increase in the borrowing base will require the consent of all lenders (other than defaulting lenders). If the requisite number of required lenders or all lenders, as applicable in the case of an increase in the borrowing base, do not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. We will be required to repay outstanding borrowings in excess of the borrowing base. The borrowing base may also automatically decrease upon the occurrence of certain events.
In the future, we may not be able to access adequate funding under the New Credit Agreement as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a borrowing base redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. Furthermore, our borrowing base may be reduced if we sell assets in the future. Declines in commodity prices could result in a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions, make distributions to our unitholders or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under the New Credit Agreement bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our business, financial condition and results of operations and cash available for distribution remain unchanged.
The credit risk of financial institutions could adversely affect us.
We have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies and deposit accounts held at regional banks. In addition, if any lender under the New Credit Agreement is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit agreement.
Our ability to obtain financing on terms acceptable to us may be limited in the future by, among other things, increases in interest rates.
We require continued access to capital and our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. We may use the New Credit Agreement to finance a portion of our future growth, and these factors could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Volatility in the global financial markets, significant losses in financial institutions’ U.S. energy loan portfolios, or environmental and social concerns may lead to a contraction in credit availability impacting our ability to finance our operations or our ability to refinance the New Credit Agreement or other outstanding indebtedness. An
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increase in interest rates could increase our interest expense and materially adversely affect our financial condition. A significant reduction in cash flow from operations or the availability of credit could materially and adversely affect our ability to carry out our development plan, our cash available for distribution and operating results.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into derivative contracts for a portion of our projected oil and natural gas production, primarily consisting of swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosure About Market Risk — Commodity price risk — Commodity derivative activities.” Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
• production is less than the volume covered by the derivative instruments;
• the counterparty to the derivative instrument defaults on its contractual obligations;
• there is an increase in the differential between the underlying price in the derivative instrument and actual prices received for the sale of our production; or
• there are issues regarding legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures, make payments on our indebtedness and make distributions to our unitholders, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties and oil and natural gas prices.
The cost to drill and complete oil and natural gas wells often increases in times of rising oil and natural gas prices. To the extent our drilling and completion costs increase, but our derivative arrangements limit the benefit we receive from increases in oil and natural gas prices, our margins could be limited, which could have a material adverse effect on our financial condition. In addition, the amount we pay in severance taxes is calculated without taking our derivative arrangements into account, and if our derivative arrangements limit the benefit we receive from increases in oil and natural gas prices, the effective tax rate we pay in severance taxes could increase.
Our derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices our derivative contract receivable positions would generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our derivative contracts.
The failure of our hedge counterparties, significant customers or working interest holders to meet their obligations to us may adversely affect our financial results.
Our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make such party unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by a counterparty to these derivative contracts when they become due could have a material adverse effect on our financial condition and results of operations.
Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fail to pay us for any reason, we could experience a material loss. In addition, if any of our significant customers cease to purchase our oil and natural gas or reduce the volume of the oil and natural gas that they purchase from us, the loss or reduction could have a detrimental effect on our revenues and may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas.
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We also face credit risk through joint interest receivables. Joint interest receivables arise from billing entities who own partial working interests in the wells we operate. Though we often have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings, the inability or failure of working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Events outside of our control, including widespread public health crises, epidemics and outbreaks of infectious diseases, or the threat thereof, and any related threats of recession and other economic repercussions 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.
Widespread public health crises, epidemics, and outbreaks of infectious diseases, which can give rise to a threat of recession and related economic repercussions can create significant volatility, uncertainty and turmoil in the global economy and oil and gas industry. These variables are beyond our control and may have the effect of disrupting the normal operations of many businesses, including the temporary closure or scale-back of business operations and/or the imposition of either quarantine or remote work or meeting requirements for employees, either by government order or on a voluntary basis. Widespread public health crises, epidemics and outbreaks of infectious diseases spreading throughout the U.S. and globally could result in significant disruptions to our operations. The global economy, our markets and our business have been, and may continue to be, materially and adversely affected by widespread public health crises, epidemics and outbreaks of infectious diseases, which could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units.
Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, supply chain disruptions, the potential for significant new tariffs, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Between 2022 and 2024, the Federal Reserve raised the target range for the federal funds rate in an effort to curb inflation. As of December 31, 2025, the Federal Reserve’s target range for the federal funds rate was 3.50% to 3.75% in light of the progress on inflation. In December 2025, inflation was 2.7%. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services.
Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. We also may face shortages of these commodities and labor, which may prevent us from fully executing our development plan. These supply chain constraints and inflationary pressures will likely continue to adversely impact our operating costs and, if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost- effective manner, if at all, which could impact our ability to distribute available cash and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
We continue to take actions to mitigate supply chain and inflationary pressures. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient.
In addition, continued hostilities related to the Russian invasion of Ukraine and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, such as decreased demand from China, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations.
Additionally, an unpredictable or volatile political environment in the United States, including any social unrest and uncertainty as a result of the 2024 U.S. presidential election, could negatively impact business and market conditions, economic growth, financial stability and business, consumer, investor and regulatory sentiments, any one or more of which could have a material adverse impact on our financial condition and results of operations. It is difficult to predict the legislative and regulatory changes that may result due to the new administration. The new administration and make-up of the Senate and/or House of Representatives may cause broader economic changes due to changes in governing ideology
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and style. New appointments to the Board of Governances of the Federal Reserve could affect monetary policy and interest rates, which could in turn affect economic growth.
Oil and gas exploration and production companies are frequently subject to litigation claims from landowners, royalty owners and other interested parties, particularly during periods of declining commodity prices.
Title to oil and natural gas properties is often unclear and subject to claims by third parties. Additionally, oil and gas companies are frequently subject to claims with respect to underpayment of royalties, environmental hazards and contested ownership of properties, especially during periods of declining commodity prices and therefore revenue and royalty payments. The oil and gas exploration and production business is especially susceptible to increased cost of capital, hedging losses and declining revenues which can result in defaults on third-party obligations. These risks and others can result in the incurrence of significant attorney’s fees and other expenses incurred in the prosecution or defense of litigation.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We maintain insurance against some, but not all, operating risks and losses. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our operations are subject to all of the risks associated with drilling for and producing oil, natural gas and NGLs and operating gathering and processing facilities including the possibility of:
• environmental hazards, such as releases of pollutants into the environment, including groundwater, surface water, soil and air;
• abnormally pressured formations;
• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
• ruptures, fires and explosions;
• damage to pipelines, processing plants, compression assets, water infrastructure, and related equipment and surrounding properties caused by tornadoes, floods, freezes, fires and other natural disasters;
• inadvertent damage from construction, vehicles and farm and utility equipment;
• personal injuries and death;
• natural disasters; and
• terrorist attacks targeting oil and natural gas related facilities and infrastructure.
Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims by government agencies or third parties for:
• injury or loss of life;
• damage to and destruction of property, natural resources and equipment;
• pollution and other environmental harm;
• regulatory investigations and penalties; and
• repair and remediation costs.
These events may also result in curtailment or suspension of our gathering and processing facilities. A natural disaster or any event such as those described above affecting the areas in which we and our third-party customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to us and our third-party customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering facilities.
We may elect not to obtain insurance for certain of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, in some instances, certain insurance could become unavailable or available only for reduced amounts of coverage, including for pollution and other environmental risks. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
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Extreme weather conditions and the physical risks of climate change could adversely affect our ability to conduct drilling activities in the areas where we operate and the operations of our gathering and processing facilities and have a negative impact on our business and results of operations.
The majority of the scientific community has concluded that climate change may result in more frequent and/or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. For example, our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, thunderstorms, tornadoes and snow or ice storms, or other climate-related events such as wildfires and floods, in each case which may cause a loss of operational efficiency or production from temporary cessation of activity or lost or damaged facilities and equipment. Further, these types of interruptions could result in a decrease in the volumes supplied to our gathering systems, and delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering and processing facilities, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our third-party customers and thereby give rise to certain termination rights or other liabilities under our contracts. Such extreme weather conditions and events could also impact other areas of our operations, including the costs or availability of insurance, access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary resources, such as water, and third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning.
Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and reduction in demand for oil and natural gas.
Increased attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial behavior, societal pressure on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives at the government, regulator, corporate and/or investor community levels, including alternative energy requirements, new fuel consumption standards, energy conservation, enhanced disclosure obligations and emissions reductions measures and responsible energy development; technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Such developments may also adversely impact, among other things, our stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business.
More broadly, the enactment of climate change-related legislation and regulatory initiatives may in the future result in increases in our compliance costs and other operating costs. For further discussion regarding the risks posed to us by climate change-related legislation and regulatory initiatives, see “— Climate change legislation or regulations restricting emissions of GHGs or requiring the reporting of GHG emissions or climate-related information could result in increased operating costs, impact the demand for the oil and natural gas we produce, and adversely affect our business.”
Negative perceptions regarding the Company’s industry and related reputational risks may also in the future adversely affect the Company’s ability to successfully carry out the Company’s business strategy by adversely affecting the Company’s access to capital. There have been efforts, for example, to influence the investment community, including
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investment advisors, insurance companies, and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Certain financial institutions and members of the investment community have shifted, and others may elect in the future to shift, some or all of their investment into non-fossil fuel related sectors. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Institutional lenders who provide financing to energy companies, such as the Company, have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Ultimately, this could make it more difficult to secure funding for exploration and production activities or adversely impact the cost of capital for both the Company and its customers, and could thereby adversely affect the demand and price of the Company’s securities. Limitation of investments in and financings for energy companies could also result in the restriction, delay, or cancellation of infrastructure projects and energy production activities.
Further, negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change or other sustainability-related matters, may also lead to increased reputational and litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new laws, regulations, guidelines and enforcement interpretations targeting our industry. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations, and such activism could materially and adversely impact our ability to operate our business and raise capital. The foregoing factors may result in downward pressure on the stock prices of oil and gas companies, including the Company’s, and cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. For example, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas, or claims alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customers. Although the Company is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way.
Our operations are subject to stringent environmental laws and regulations that may affect our operations and expose us to significant costs and liabilities that could exceed current expectations.
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, the release, disposal or discharge of materials into the environment, and occupational health and safety aspects of our operations. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated drilling activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the prohibition of noise-producing activities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including threatened and endangered species habitats; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Governmental authorities, such as 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. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. We may be required to make significant capital and operating expenditures or perform remedial or other corrective actions at our wells and properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.
There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations (including plugging and abandonment obligations) and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that could occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. For example, lawsuits in which
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landowners sue every operator in the chain of title for environmental damages to their property are not uncommon in states in which we operate. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In certain instances, citizen groups also have the ability to bring legal proceedings against us regarding our compliance with environmental laws, or to challenge our ability to receive environmental permits that we need to operate. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations or historical oil and natural gas production in our areas of operation, which have been producing oil in certain instances for several decades. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
The long-term trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. For example, in January 2021, the Biden administration directed the U.S. Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations. In August 2022, the U.S. Court of Appeals vacated and remanded the federal district court’s decision to block the pause on new oil and gas leasing, and the federal district court shortly thereafter enjoined the DOI from implementing the pause in the thirteen states that had challenged the pause, including Oklahoma and Texas. Litigation over leasing remains ongoing. However, in January 2025, President Trump issued executive orders (i) reversing the Biden administration’s leasing pause and executive orders withdrawing certain lands and waters from federal oil and gas leasing and (ii) directing all federal agencies to facilitate the leasing, siting, and generation of domestic energy resources, including on federal lands and waters. In addition, in November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule sought to impose emissions reduction standards on both new and existing sources in the oil and natural gas industry, expand the scope of Clean Air Act (“CAA”) regulation by making regulations in Subpart OOOOa more stringent and creating a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA. In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule sought to remove an emissions monitoring exemption for small wellhead-only sites and create a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters,” triggering certain investigation and repair requirements. In December 2023, the EPA announced a final rule, later published on March 8, 2024, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, in March 2025, EPA announced its intention to reconsider the Marh 8, 2024 ule, including Suparts OOOOb and OOOOc. By interim final rule published on July 3, 2025, and final rule published on December 3, 2025, EPA provided extensions for most compliance deadlines for equipment, leaks, and state plans under OOOOb and OOOOc to January 22, 2027. A final EPA rule reconsidering requirements promulgated under OOOOb and OOOOc is expected in or around July 2026. Consequently, future implementation and enforcement of the final rule remains uncertain at this time. Further, in August 2022, the Inflation Reduction Act of 2022 was signed into law, which incentivized the reduction of methane emissions by imposing a fee on methane produced by petroleum and natural gas facilities in excess of a specified threshold, among other initiatives. The Inflation Reduction Act amended the CAA to include a Methane Emissions and Waste Reduction Incentive Program, which required the EPA to impose a “Waste Emissions Charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program. Also in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the process to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the Waste Emissions Charge, and in May 2025, EPA issued a final rule to remove the Waste Emissions Charge regulations from the Code of Federal Regulations. Additionally, the One Big Beautiful Bill Act of 2025 delayed the effective date of the WEC until 2034. EPA, in September 2025, also proposed to permanently remove program obligations from the Greenhouse Gas Reporting Program for most source categories and suspend program obligations for some sources subject to subpart W (which applies to emission sources in certain segments of the petroleum and natural gas industry) until 2034. Consequently, future implementation and enforcement of these rules remains
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uncertain at this time. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry as well as our own results of operations, competitive position or financial condition. While the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo (“ Loper ”) to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. (“ Chevron ”) and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives are expected to continue. Consequently, legislation and regulatory programs to address climate change or reduce emissions of GHGs could have a material adverse effect on our business, financial condition or results of operations.
To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
Climate change legislation or regulations restricting emissions of GHGs or requiring the reporting of GHG emissions or climate-related information could result in increased operating costs, impact the demand for the oil and natural gas we produce, and adversely affect our business.
More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply with such laws and regulations. In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and in the absence of comprehensive federal legislation on GHG emission control, the EPA has adopted regulations pursuant to the CAA to monitor, report, and/or reduce GHG emissions from various sources. The 2007 case Massachusetts v. EPA held that GHGs are air pollutants covered by the Clean Air Act, and that EPA must determine whether certain GHG emissions may reasonably be anticipated to endanger public health or welfare. In December 2009, EPA issued a final rule stating that current and projected concentrations of carbon dioxide, methane and other GHGs endanger public health and welfare (“2009 Endangerment Finding”). The 2009 Endangerment Finding served as legal support for subsequent EPA Clean Air Act rulemakings that have significantly affected industry operational costs, including New Source Performance Standards and Existing Source Guidelines rules requiring technology investments to detect and reduce methane leaks and emissions from new and existing oil and gas infrastructure. In the 2022 Supreme Court case West Virginia v. EPA , the Court held that EPA lacked clear statutory authority under the Clean Air Act, absent specific and explicit authorization from Congress, to implement an EPA rulemaking that mandated a shift for electricity production from higher greenhouse gas emissions sources to lower emissions sources. In the 2024 Supreme Court case Loper Bright Enterprises v. Raimondo , the Court held that courts must independently determine the best reading of a statute, rather than deferring to agency interpretations of ambiguous statutory language. On February 12, 2026, EPA issued a pre-publication copy of a final rule, submitted for publication in the Federal Register, rescinding the 2009 Endangerment Finding on the basis that the 2009 Endangerment Finding exceeded EPA authority, was not supported by specific and explicit authorization from Congress, and did not meet the best reading of the underlying Clean Air Act provision under the West Virginia and Loper Bright holdings. Litigation following the February 2026 final rule publication is expected, and on February 18, 2026, a coalition of environmental and public health groups filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit. The potential impact of the February 2026 final rule, potential subsequent revisions to existing emission standards, and the outcome of related litigation, including private nuisance litigation, remain uncertain and could affect our operations. We cannot predict the scope of any future methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility. We cannot predict the scope of any future methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions, such as by means of cap and trade programs. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In December 2015, the Paris Agreement (an international agreement from the 21 st Conference of the Parties (“COP”) to the United Nations Framework Convention on Climate Change in Paris, France) resulted in an agreement for signatory countries to nationally determine their contributions and set GHG emission reduction goals. In January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The withdrawal became effective in January 2026. In January 2026, President Trump announced the United States will also withdraw from the UN Framework Convention on Climate
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Change. At the same time, various state and local governments have committed to furthering the goals of the Paris Agreement.
Any legislation or regulatory programs addressing GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas we produce, and could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements, and to monitor and report on GHG emissions. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for lower-carbon fuel or zero-operating emissions vehicles, could reduce demand for the oil and natural gas we produce. Further, in January 2024, the Biden administration announced a temporary pause on pending decisions on exports of LNG to non-free trade agreement countries until the Department of Energy can update the underlying analyses for authorizations, including an assessment of the impact of GHG emissions. However, in January 2025, President Trump issued an executive order directing the Department of Energy to restart reviews of applications for approvals of LNG export projects as expeditiously as possible.
It is not currently possible to predict how these executive orders or any proposed or future GHG or climate change legislation or regulation promulgated by Congress, the states or multi-state regions and their respective regulatory agencies may impact our business. Further, the Supreme Court’s decision in Loper to overrule Chevron ended the concept of general deference to regulatory agency interpretations of laws and introduced new complexity for federal agencies and administration of climate change policy and regulatory programs. However, many such initiatives at the international, state and local levels are expected to continue and any climate change legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our products, and could have a material adverse effect on our business, financial condition and results of operations. For further discussion of certain existing and proposed climate-related rules and regulations, see “Business and Properties — Legislative and regulatory environment” included in Items 1 and 2 of Part I of this Annual Report.
Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation.
Companies across all industries continue to face increased scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating company. At the same time, others may disagree with certain ESG initiatives and recent political developments could subject ESG initiatives and the Company to increased risk of criticism or litigation risks from certain “anti-ESG” parties. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder confidence and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays, limit the areas in
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which we can operate, and reduce our oil and natural gas production, which could adversely affect our production and business.
Hydraulic fracturing is a common practice used to stimulate production of oil and/or natural gas from dense subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We and our third-party operators use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies or trigger seismic activity. Proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.
Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibiting the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
In addition, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. The EPA also finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. To date, the EPA has taken no further action in response to the 2016 report. In March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica, which went into effect in June 2018 and applies to use of sand as a proppant for hydraulic fracturing. The U.S. Department of the Interior’s Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. Following years of litigation, the BLM rescinded this rule in December 2017. However, California and various environmental groups filed lawsuits in January 2018 challenging the BLM’s rescission of the rule and, in March 2020, the U.S. District Court for the Northern District of California upheld the BLM’s decision to rescind the rule. However, there is ongoing litigation regarding the BLM rules, and future implementation of these rules is uncertain at this time. In April 2024, the BLM finalized a rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases. The final rule took effect in June 2024. However, in May 2024, the states of North Dakota, Texas, Montana, Wyoming, and Utah challenged the rule. In September 2024, the U.S. District Court for the District of North Dakota granted a motion prohibiting the BLM from enforcing the rule against those states pending the outcome of the litigation. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. The BLM has given notice that it is in the process of considering revisions to the final rule and has delayed enforcement of two provisions included in the April 2024 rule until December 10, 2026. The relevant provisions subject to delayed enforcement imposed measurement device and sampling requirements for flares flowing between 1,050 and 6,000 mcf/month and required operators to submit Leak Detection and Repair plans to the state BLM office; however, the obligation to repair leaks required under the regulations remains in effect. The state litigation against the April 2024 rule has been temporarily suspended pending the BLM’s reconsideration of the April 2024 rule. Accordingly, future implementation and enforcement of this rule is uncertain at this time. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.
Legislation or regulatory initiatives intended to address the disposal of saltwater gathered from our drilling activities could limit our ability to produce oil and natural gas economically and have a material adverse effect on our business.
We dispose of large volumes of saltwater gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other
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things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of saltwater gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
Limitation or restrictions on our ability to obtain or dispose of water may have an adverse effect on our operating results.
Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly.
In addition, the use, treatment and disposal of water has become a focus of certain investors and other stakeholders who may seek to engage with us on this and other environmental matters, which may result in activism, negative reputational impacts, increased costs or other adverse effects on our business, results of operations and financial condition. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition. Furthermore, our operations could be impaired if we are unable to recycle or dispose of the water we produce in an economical and environmentally safe manner.
The effects of climate change may also further exacerbate water scarcity in certain regions, including the areas in which we are active. If distinct weather events or gradual climatic processes were to require us to discontinue or curtail our operations, this could impair ability to economically produce our reserves and would have an adverse effect on our financial condition, results of operations and cash flows.
We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease our cash available for distribution.
We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease our cash available for distribution. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and/or habitats. The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. The FWS may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and may materially delay or prohibit land access for natural gas development. In January 2021, the Department of the Interior finalized a rule limiting the application of the MBTA. In October 2021, the Biden administration published two rules that reversed those changes, and in June and July 2022, the FWS issued final rules rescinding prior Trump Administration regulations concerning the definition of “habitat” and critical habitat exclusions. In April 2024, the FWS finalized three rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. In August 2024, environmental groups challenged the new ESA regulations in federal district court, which litigation remains ongoing. However, in January 2025, the Trump administration issued an executive order directing (i) agencies to use, to the maximum extent permissible, the ESA regulation on consultations in emergencies, to facilitate the domestic energy supply and (ii) the Endangered Species Act Committee to meet at least quarterly to ensure a prompt and efficient review of all submissions for potential actions that could facilitate energy development. Additionally, in April 2025, the FWS and National Marine Fisheries Service proposed to redefine “harm” to mean affirmative acts that are directed immediately and intentionally against a particular animal, excluding acts or omissions that indirectly cause injury. Additionally, in
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November 2025, the Trump Administration proposed several rules that would significantly alter ESA protections for plants and animals. One proposed rule would rescind a rule that automatically extends protections for endangered species to threatened species. Another proposed rule would change regulations for listing species as endangered or threatened as well as for designating critical habitats. Additionally, a third proposed rule would reinstate the framework for evaluating the benefits and cost of designating a critical habitat by considering factors like economic impact, impact on national security, and other relevant impacts. The U.S. Fish and Wildlife Service is expected to issue final rules in 2026. The designation of previously unprotected species as threatened or endangered or new critical or suitable habitat designations in areas where we conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business, and it is possible the new rules could increase the portion of our lease areas that could be designated as critical habitat. Similar protections are offered to migratory birds under the MBTA, which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the United States. However, in April 2025, the U.S. Department of Interior issued a memo, M-37085, to repeal M-37065, which had previously declared that the Migratory Bird Treaty Act prohibited both the intentional and incidental “take” of migratory birds. The memo restored M-37050, clarifying that only the intentional “take” of migratory birds is prohibited. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered or further changes to regulations could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC to promulgate rules and regulations implementing the Dodd-Frank Act. On January 14, 2021, the CFTC published a final rule imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents, though certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC’s requirements for certain enumerated “bona fide” hedging transactions and positions. The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns ten percent or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of transactions. Moreover, such changes could materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low commodity prices. The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC on our business will not be known until all of the rules to be adopted under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.
In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to implement regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC.
We may be involved in legal and regulatory proceedings that could result in substantial liabilities.
Like many oil and gas companies, we are, or may be, from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, alleged violations of federal or state securities laws and personal injury, environmental damage or property damage matters, in the ordinary course of our business. Additionally, members of our management and our directors may, from time to time, be involved in various legal and other proceedings against the Company naming those officers or directors as co-defendants. Such legal and regulatory
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proceedings are inherently uncertain, and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition and affect the value of our common units. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. The defense of any legal proceedings against us or our officers or directors, could take resources away from our operations and divert management attention. As of the date of this Annual Report, the Company is not aware of any material legal or environmental proceedings contemplated to be brought against the Company or its management.
Loss of our information and computer systems could adversely affect our business. Our business could be negatively impacted by security threats, including cyber-security threats and other disruptions.
We are heavily dependent on our information systems and computer-based programs, including our well operations information, geologic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
We are subject to a number of privacy and data protection laws, rules and directives (collectively, data protection laws) relating to the processing of personal data.
The regulatory environment surrounding data protection laws is uncertain. Varying jurisdictional requirements could increase the costs and complexity of compliance with such laws, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.
Risks Inherent in an Investment in Us
Our general partner and its affiliates own a controlling interest in us and 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 general partner has control over all decisions related to our operations. The Sponsor and Tom L. Ward through his ownership of Mach Resources own all of the membership interests in our general partner which are in the same proportion to each other as their limited partner interest ownership in us. The Sponsor and Tom L. Ward through his ownership of Mach Resources also own approximately 74,850,632 and 13,858,781, respectively, of our outstanding common units as of March 5, 2026. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the executive officers and directors of our general partner also have a duty to manage our general partner at the direction of the Sponsor and Tom L. Ward through his ownership of Mach Resources. As a result of these relationships, conflicts of interest may arise in the future between the Sponsor, Tom L. Ward in his capacity as a member of
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our general partner through his ownership of Mach Resources and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand; provided, however, that under our code of business conduct, any such member of our management, so long as they are an executive officer, is required to avoid personal conflicts of interest and not compete against us, in each case unless approved by the Board. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our common unitholders. These conflicts include, among others, the following:
• Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
• Neither our partnership agreement nor any other agreement requires the Sponsor (excluding our general partner) to pursue a business strategy that favors us;
• The Sponsor is not limited in its ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;
• Our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
• Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
• Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
• Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
• Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 95% of the common units;
• Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Please read “Certain Relationships and Related Party Transactions and Director Independence” included in Item 13 of Part III of this Annual Report.
Our partnership agreement does not restrict the Sponsor from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit the Sponsor’s ability to compete with us and the Sponsor does not have any obligation to present business opportunities to us.
In addition, certain of our officers and directors may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests. In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these
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potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. The Sponsor will be under no obligation to make any acquisition opportunities available to us.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and holders of our common units.
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 partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with different contractual standards. For example, our partnership agreement provides that:
• whenever our general partner (acting in its capacity as our general partner), the Board or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or equitable principle;
• our general partner may make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners at the time our partnership agreement was entered into where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
• how to allocate corporate opportunities among us and its other affiliates;
• whether to exercise its limited call right;
• whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board; provided, however, the MSA will require our general partner to seek approval by the conflicts committee of the Board in connection with an amendment to the MSA that, in the reasonable discretion of our general partner, adversely affects our unitholders;
• how to exercise its voting rights with respect to the units it owns;
• whether to sell or otherwise dispose of any units or other partnership interests it owns; and
• whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
• our general partner will not have any liability to us or our unitholders for breach of any duty in connection with decisions made in its capacity as general partner so long as it acted in good faith (meaning that it subjectively believed that the decision was not adverse to our best interest);
• our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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• our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
• approved by the conflicts committee of the Board, although our general partner is not obligated to seek such approval;
• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
• determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
• determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and make acquisitions.
Our partnership agreement provides that we distribute each quarter all of our available cash, which we define as cash on hand at the end of each quarter, less reserves established by our general partner. As a result, we expect to rely primarily upon our cash reserves and external financing sources, including the issuance of additional common units and other partnership securities and borrowings under our New Credit Agreement, to fund future acquisitions and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our available cash may impair our ability to grow.
A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:
• general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;
• conditions in the oil and gas industry;
• the market price of, and demand for, our common units;
• our results of operations and financial condition; and
• prices for oil, natural gas and NGLs.
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are and will be no limitations in our partnership agreement or the New Credit Agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our business strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. In addition, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. This implied distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest
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rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt. See “— Increased costs of capital could adversely affect our business.”
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 general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.
Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors, which could reduce the price at which our common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.
Our unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The Board, including the independent directors, is chosen entirely by the Sponsor and Tom L. Ward through his ownership of Mach Resources, as a result of their ownership of our general partner, and not by our unitholders. Please read “Management of Mach Natural Resources” included in Item 10 of Part III of this Annual Report and “Certain Relationships and Related Party Transactions and Director Independence” included in Item 13 of Part III of this Annual Report. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our general partner has control over all decisions related to our operations. Since affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) collectively own and control the voting of an aggregate of approximately 52.7% of our outstanding common units as of March 5, 2026, the other unitholders do not have an ability to influence any operating decisions and are not able to prevent us from entering into any transactions. However, our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources)). Assuming we do not issue any additional common units and affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) do not transfer any of their common units, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will generally have the ability to control any amendment to our partnership agreement, including our policy to distribute all of our cash available for distribution to our unitholders. Furthermore, the goals and objectives of the affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “— Our general partner and its affiliates own a controlling interest in us and 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.”
Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.
The public unitholders are unable initially to remove our general partner without its consent because affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) own sufficient units to prevent the removal of our general partner. Our general partner may not be removed except by vote of the holders of at least 66⅔% of all outstanding units voting together as a single class is required to remove our general partner. As of March 5, 2026, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) own approximately 52.7% of our outstanding common units, which enable those holders, collectively, to prevent the removal of our general partner.
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Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the Sponsor or Tom L. Ward through his ownership of Mach Resources which controls our general partner, from transferring all or a portion of their ownership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and thereby influence the decisions made by the Board and officers.
We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval.
Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
• our unitholders’ proportionate ownership interest in us will decrease;
• the amount of cash available for distribution on each unit may decrease;
• the ratio of taxable income to distributions may increase;
• the relative voting strength of each previously outstanding unit may be diminished; and
• the market price of our common units may decline.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the Board, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
As of March 5, 2026, the Sponsor owns 74,850,632 common units, or approximately 44.5% of our limited partner interests, and management owns 14,405,597 common units, or approximately 8.6% of our limited partner interests. Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates, which includes the Sponsor and Tom L. Ward through his ownership of Mach Resources. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 95% of the then outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.
Our partnership agreement has designated the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders which would limit our unitholders’
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ability to choose the judicial forum for disputes with us or our general partner or its directors, officers or other employees.
Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court in the State of Delaware with subject matter jurisdiction) will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. The foregoing provision will not apply to any claims as to which the Court of Chancery determines that there is an indispensable party not subject to the jurisdiction of such court, which is rested in the exclusive jurisdiction of a court or forum other than such court (including claims arising under the Exchange Act), or for which such court does not have subject matter jurisdiction, or to any claims arising under the Securities Act and, unless we consent in writing to the selection of an alternative forum, the United States federal district courts will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules or regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such Securities Act claims. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, the partnership agreement provides that, unless we consent in writing to the selection of an alternative forum, United States federal district courts shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. There is uncertainty as to whether a court would enforce the forum provision with respect to claims under the federal securities laws. If a court were to find these provisions of our amended and restated agreement of limited partnership inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding, including any claim under the U.S. federal securities laws, to the fullest extent permitted by applicable law. If a lawsuit is brought against us under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in different outcomes than a trial by jury would have, including results that could be less favorable to the plaintiffs in any such action. No unitholder can waive compliance with respect to the U.S. federal securities laws and the rules and regulations promulgated thereunder. If the partnership or one of the partnership unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our partnership agreement. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations, provisions and obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us, our general partner and our general partner’s directors and officers.
Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf pursuant to the MSA will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.
We and our general partner have entered into a MSA with Mach Resources pursuant to which Mach Resources will manage and perform all aspects of our oil and gas and midstream operations and other general and administrative functions in exchange for reimbursement of certain expenses. On a monthly basis, we will reimburse our general partner and its affiliates for certain expenses they incur and payments they make on our behalf pursuant to the MSA. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses to our
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general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. For the year ended December 31, 2025, we paid $135.7 million to Mach Resources, which consisted of $7.4 million for a management fee and $128.3 million for reimbursements of its costs and expenses under the management services agreements among Mach Resources, the Company and the Mach Companies.
The NYSE does not require a publicly traded limited partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.
Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management of Mach Natural Resources” included in Item 10 of Part III of this Annual Report.
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a Delaware limited partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
• a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
• a unitholder’s right to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.
Our unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
If our common unit price declines, our unitholders could lose a significant part of their investment.
The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
• changes in commodity prices;
• changes in securities analysts’ recommendations and their estimates of our financial performance;
• public reaction to our press releases, announcements and filings with the SEC;
• fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded partnerships and limited liability companies;
• changes in market valuations of similar companies;
• departures of key personnel;
• commencement of or involvement in litigation;
• variations in our quarterly results of operations or those of other oil and natural gas companies;
• variations in the amount of our quarterly cash distributions to our unitholders;
• changes in tax law;
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• an election by our general partner to convert or restructure us as a taxable entity;
• future issuances and sales of our common units; and
• changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation. Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our common units less attractive to investors.
The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.
We have elected to take advantage of all of the reduced reporting requirements and exemptions available to emerging growth companies under the JOBS Act, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.
Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common units less attractive because we elected to rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our common unit price may be more volatile. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
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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.
Under our partnership agreement, our general partner may, without unitholder approval, cause us to be treated as an entity taxable as a corporation or subject to entity-level taxation for U.S. federal income tax purposes, whether by election of the partnership or conversion of the partnership or by any other means or methods. In addition and as part of such determination, affiliates of our general partner may choose to retain their partnership interests in us and cause us to enter into a transaction in which our interests held by other persons are converted into or exchanged for interests in a new entity, taxable as a corporation or subject to entity-level taxation for U.S. federal purposes, whose sole assets are interests in us. The general partner may take any of the foregoing actions if it in good faith determines (meaning it subjectively believes) that such action is not adverse to our best interests. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may be material to such unitholder and may vary depending on the unitholder’s particular situation and may vary from the tax liability of us or of any affiliates of our general partner who choose to retain their partnership interests in us. Our general partner will have no duty or obligation to make any such determination or take any such actions, however, and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in a manner not adverse to the best interests of us or our limited partners.
We incur increased costs as a result of being a publicly traded partnership.
We have a limited history operating as a publicly traded partnership. As a publicly traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to the Offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.
We are subject to the public reporting requirements of the Exchange Act. These rules and regulations increase certain of our legal and financial compliance costs and make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting.
We also incur additional expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the Board or as executive officers than it was prior to the Offering.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our units or if our operating results do not meet their expectations, our unit price could decline.
The trading market for our common units is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our unit price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common units or if our operating results do not meet their expectations, our unit price could decline.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. 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 (the “IRS”) were to treat us as a corporation for U.S. 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.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for
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U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for U.S. federal income tax purposes.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders could be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in Oklahoma, Kansas, Texas, New Mexico and Colorado among other states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes and differing interpretations. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.
Any changes to U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for U.S. federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes to U.S. federal income tax laws or interpretations thereof could adversely impact the value of an investment in our common units.
Certain U.S. federal income tax incentives currently available with respect to oil and natural gas exploration and production may be reduced or eliminated as a result of future legislation.
In recent years, legislation has been proposed that would, if enacted, make significant changes to U.S. tax laws, including the reduction or elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
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A successful IRS contest of the U.S. federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.
The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns (including any income tax returns filed by us or the Mach Companies in respect of periods beginning prior to the closing of the Offering), it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made or be effective in all circumstances. If we are unable to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our common units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially 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.
Because our unitholders will be treated as partners to whom we will allocate taxable income, our unitholders may be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.
Tax gains or losses on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation, depletion, amortization and accretion expense and intangible drilling costs. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (“business interest”) may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our common units.
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Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, raise issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. A tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult their tax advisors regarding the impact of these rules on an investment in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable marginal tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.
Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we will adopt depreciation, depletion, amortization and accretion positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.
Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.
In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in Oklahoma, Kansas, Texas, New Mexico and Colorado. Oklahoma, Kansas, New Mexico and Colorado each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or entity-level income tax. It is the responsibility of each unitholder to file its own U.S. federal, state and local tax returns, as applicable.
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A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult their tax advisors to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.
We have adopted and will continue to adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many of the relative fair market value estimates ourselves. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
