Insiders ranked by realized 90-day signed return on their open-market trades at Permian Resources Corp. Minimum 3 scored trades. Returns are signed - a sale followed by a rally counts against the insider.
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is 0.04pp more bullish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
+0.03pp
Flat
Net-tone change vs last year's 10-K.
MD&A
+0.05pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
endangerment+5
unable+1
incidents+1
shortages+1
costly+1
Positive rising
able+2
greater+2
better+2
strong+1
positive+1
Risk Factors (Item 1A)
26,710 words
Risk Factors Summary
The following is a summary of the principal risks that could materially adversely affect our business, financial condition and results of operations. Refer to Risk Factors under Part I, Item 1A of this Annual Report for a more detailed description of each risk factor.
Risks Related to Commodity Prices
• Commodity prices are volatile, and a sustained period of low commodity prices for oil, natural gas and NGLs could adversely affect our business, financial condition and results of operations.
• If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.
Risks Related to Our Reserves, Leases and Drilling Locations
• 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.
• Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would affect our future cash flows and results of operations.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
loss+2
losses+1
unpaid+1
negatively+1
conflicts+1
Positive rising
gains+1
greater+1
efficiencies+1
benefit+1
MD&A (Item 7)
6,846 words
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. The following discussion and analysis contain forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, NGLs and natural gas, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
We are an independent oil and natural gas company focused on driving returns to our stockholders through the acquisition, optimization and development of high-return oil and natural gas properties. Our assets and operations are located in the Permian Basin, with a concentration in the core of the Delaware Basin. Our principal business objective is to increase shareholder value by developing our oil and natural gas assets, with an overall objective of our rates of return and generating sustainable free cash flow.
• The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
• Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
• 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.
• Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Risks Related to Our Operations
• Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, or at all, which could lead to a decline in our ability to access or grow production and reserves.
• Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
• Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.
• Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
• Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
• Our ability to produce crude oil, natural gas and NGLs economically in commercial quantities could be impaired if we are unable to recycle or dispose of the produced water we produce in an economical and environmentally safe manner.
• Our producing properties are concentrated in the Permian Basin, making us vulnerable to risks associated with operating in a single geographic area.
• The marketability of our production is dependent upon transportation and other facilities, most of which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted and our revenues reduced.
• We have entered into multi-year agreements with some of our suppliers, service providers and the purchasers of our oil and natural gas, which contain minimum volume commitments. Any failure by us to satisfy the minimum volume commitments could lead to contractual penalties that could adversely affect our results of operations and financial position.
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• The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
• 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.
• We depend on a small number of significant purchasers for the sale of most of our oil, natural gas and NGL production.
• We may incur losses as a result of title defects in the properties in which we invest.
• Multi-well pad drilling may result in volatility in our operating results.
Risks Related to Our Derivative Transactions, Debt and Access to Capital
• Our derivative activities could result in financial losses or could reduce our earnings.
• Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on our outstanding debt.
• We may not be able to generate sufficient cash to service all of OpCo’s indebtedness and may be forced to take other actions to satisfy OpCo’s obligations under applicable debt instruments, which may not be successful.
• Restrictions in OpCo’s existing and future debt agreements may limit our growth and ability to take certain activities.
• If OpCo is unable to comply with the restrictions and covenants in the agreements governing its indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that OpCo has borrowed.
• Any significant reduction in the borrowing base under OpCo’s revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
• If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Risks Related to Legislative and Regulatory Initiatives
• 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 in the completion of oil and natural gas wells and adversely affect our production.
• Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
• 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.
• A negative shift in investor sentiment towards the oil and natural gas industry and increased attention to sustainability and conservation matters may adversely impact our business.
• Any restrictions on oil and natural gas development on federal lands have the potential to adversely impact operations.
Risks Related to Our Common Stock and Capital Structure
• Our cash flow is dependent upon the ability of our operating subsidiaries to make cash distributions to us, the amount of which will depend on various factors.
• If we experience any material weakness or otherwise fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, stockholders could lose confidence in our financial reporting, which would harm our business and the value of our Class A Common Stock.
• There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
• The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
• Provisions contained in our Charter and Bylaws, as well as provisions of Delaware law, could impair a takeover attempt, which may adversely affect the market price of our common stock.
• The Charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for substantially all actions and proceedings that may be initiated by stockholders, which could limit shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Overview
Permian Resources Corporation is an independent oil and natural gas company focused on driving returns to our stockholders through the acquisition, optimization and development of high-return crude oil and associated liquids-rich natural gas reserves. Throughout this Annual Report, unless the context otherwise indicates, all references to the “Company,” “Permian Resources,” “we,” “us,” or “our” refer to Permian Resources Corporation and its consolidated subsidiary, Permian Resources Operating, LLC (“OpCo”).
Our principal business objective is to generate leading shareholder returns by leveraging our technical expertise and operational flexibility to optimally develop our oil and natural gas resources. We are focused on enhancing our high-quality scaled asset base, executing a capital-efficient development program, maintaining a conservative balance sheet and financial policy, and maximizing returns to our shareholders. We also look for opportunities to optimize our portfolio of high-return, long-life inventory through accretive acquisitions that meet our strategic and disciplined financial objectives.
Description of Our Properties
Our assets are located in the Permian Basin, with a concentration in the core of the Delaware Basin consisting of large, contiguous acreage blocks in West Texas and New Mexico. As of December 31, 2025, we have approximately 480,000 net leasehold acres and over 105,000 net royalty acres. Approximately 67% of our net leasehold acreage is located in Texas and the remaining 33% is located in New Mexico.
2025 Acquisitions and Capital Investments
On June 16, 2025, we completed an acquisition of approximately 13,000 net leasehold acres with Apache Corporation for an unadjusted purchase price of $608 million. The acreage acquired is predominately located directly offsetting our existing asset position in the core of our New Mexico operating area.
Additionally, during the year ended December 31, 2025, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $471.1 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.
During 2025 we invested $1.97 billion of capital expenditures in our developmental drilling and completion program resulting in 190.7 net developmental wells being placed on production.
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Proved Oil and Gas Reserves
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The pre-tax PV 10% amounts shown in the following table are not intended to represent the current market value of our estimated proved reserves. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated, due to a number of factors. The following table should be read along with Item 1A. Risk Factors in this Annual Report.
The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows for the periods indicated:
December 31, 2025
December 31, 2024
December 31, 2023
Proved developed reserves:
Oil (MBbls)
NGL (MBbls)
Natural gas (MMcf)
Total proved developed reserves (MBoe) (1)
Proved undeveloped reserves:
Oil (MBbls)
NGL (MBbls)
Natural gas (MMcf)
Total proved undeveloped reserves (MBoe) (1)
Total proved reserves:
Oil (MBbls)
NGL (MBbls)
Natural gas (MMcf)
Total proved reserves (MBoe) (1)
Proved developed reserves %
Proved undeveloped reserves %
Reserve values (in millions):
Standard measure of discounted future net cash flows
Discounted future income tax expense
Total proved pre-tax PV 10% (2)
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2) Total proved pre-tax PV 10% (“Pre-tax PV 10%”) is a supplemental non-GAAP financial measure as defined by the U.S. Securities and Exchange Commission (“SEC”) and is derived from the standardized measure of discounted future net cash flows (the “Standardized Measure”), which is the most directly comparable U.S. generally accepted accounting principles (“GAAP”) financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.
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Proved Undeveloped Reserves. Our proved undeveloped (“PUD”) reserves increased by 41.7 MMBoe on a net basis from December 31, 2024 to December 31, 2025, and the following table provides a reconciliation of the changes to our PUD reserves that occurred during the year:
(MBoe)
Proved undeveloped reserves at January 1, 2025
Transfers to proved developed reserves
Revisions to previous estimates
Extensions and discoveries
Purchase of reserves in place
Proved undeveloped reserves at December 31, 2025
The increase in proved undeveloped reserves during 2025 was primarily attributable to adding 142.7 MMBoe of PUD reserves through extensions and discoveries stemming from our continuous drilling program, which added new locations primarily in the various Bone Spring and Wolfcamp formations on our acreage position in the Permian Basin. Additionally, we added 10.6 MMBoe of PUD reserves from properties acquired during the year. These positive additions were partially offset by converting 84.3 MMBoe of PUD reserves to proved developed reserves during 2025, for which we spent $772.5 million in capital expenditures. Additionally, PUD reserves were reduced during the year by a net amount of 27.2 MMBoe from revisions to previous estimates mainly related to (i) 36.0 MMBoe of PUD reserves that were reclassified to unproved reserves or removed due to changes made to our development plan, and (ii) 10.2 MMBoe of reduced PUD reserves from lower average commodity prices for the year ended 2025. These downward revisions were partially offset by 19.0 MMBoe of positive revisions primarily related to timing and performance. All of our PUD locations are scheduled to be drilled within five years of their initial booking. Our PUD to proved developed reserves conversion rate was 30% in 2025.
For additional information and for a discussion of material changes on our total proved reserves, see Supplemental Information About Oil & Natural Gas Producing Activities , Item 8. Financial Statements and Supplementary Data of this Annual Report.
Preparation of Reserve Estimates
Our proved reserves are estimated by an independent engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Reserve estimates are prepared in accordance with the definitions and regulations of the SEC and the Financial Accounting Standards Board (the “FASB”) using a deterministic method, which includes decline curve analysis, production performance analysis, offset analogies, and in some cases a combination of these methodologies.
Controls over Reserve Estimation
We maintain adequate and effective internal controls over the reserve estimation process and the underlying data which the reserve estimates are based upon. Our reserves estimation process is coordinated by our internal reserves department, which consists of qualified petroleum engineers and is overseen by our Reserves Manager. Reserve information, including models and other technical data, are stored on a secured database on our network. Certain non-technical inputs used in the reserves estimation process such as ownership interest percentages, oil and natural gas production, commodity prices, price differentials, operating and development costs and plug and abandonment estimates are obtained by other departments. Annually, our internal reserves department prepares a preliminary reserve database and meets with NSAI to discuss the assumptions and methods to be used in the year-end proved reserve estimation process and to review field performance and our future development plans. Following this review, the reserve database and supporting data is furnished to NSAI for their independent estimates and final report.
Qualifications of Responsible Technical Persons
Our Reserves Manager, Natalie La, is responsible for overseeing the preparation of the reserves estimates. Ms. La has held this position at Permian Resources since October 2025 and has over 10 years of relevant experience in reservoir engineering and reserve estimation. She holds a Master’s degree in Petroleum Engineering from the University of Texas at Austin and is a Registered Professional Engineer.
NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Ms. Lily W. Cheung and Mr. Zachary R. Long. Ms. Cheung, a Licensed Professional Engineer in the State of Texas (No. 107207), has been practicing consulting petroleum engineering at NSAI since 2007 and has over 4 years of prior industry experience. She graduated from Massachusetts Institute of Technology in 2003 with a Bachelor of Science Degree in Mechanical Engineering and from University of Texas at Austin in 2007 with a Master of Business Administration Degree. Mr. Long, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11792), has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. He graduated
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from University of Louisiana at Lafayette in 2003 with a Bachelor of Science Degree in Petroleum Geology and from Texas A&M University in 2005 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Production
The following table sets forth information regarding net production of oil, NGLs and natural gas, and certain price and cost information for each of the periods indicated:
Year Ended December 31,
Net production:
Oil (MBbls)
NGL (MBbls)
Natural gas (MMcf)
Total (MBoe) (1)
Average sales price (excluding effect of hedges):
Oil (per Bbl)
NGL (per Bbl)
Natural gas (per Mcf) (2)
Total per Boe (1)
Operating costs per Boe:
Lease operating expenses
Severance and ad valorem taxes
Gathering, processing and transportation expenses
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2) Natural gas average sales price includes the effects of $0.10 per Mcf of purchased gas sales for the year ended December 31, 2025.
Acreage
The following table sets forth information as of December 31, 2025 relating to our gross and net developed and undeveloped leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. The acreage classified as developed in the table below is considered such due to the existence of producing wells in a specific formation underlying such acreage. However, utilizing horizontal drilling, we are able to develop multiple stacked shale formations underlying the same surface acreage resulting in more development potential of such developed acreage.
Developed Acreage
Undeveloped Acreage
Total Acreage
Gross (1)
Net (2)
Gross (1)
Net (2)
Gross (1)
Net (2)
(1) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(2) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
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Certain leases included in the undeveloped acreage set forth in the table above may expire at the end of their respective primary lease terms unless production is established within the spacing units covering the acreage, the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, or pursuant to other terms of the lease agreements. As of December 31, 2025, approximately 10,000 net acres of our total net acreage may expire over the next five years. However, our development program includes the review of any lease before the contractual expiration date and in cases where additional time may be required to fully evaluate acreage, we have generally been successful in obtaining extensions. Such expirations have not had a material impact on our development plans or reserves and we do not expect them to have a future adverse impact based on our current operations.
Productive Wells
As of December 31, 2025, we owned an approximate 84% average working interest in 3,473 gross (2,923 net) operated productive wells, an approximate 12% average working interest in 1,203 gross (147 net) non-operated productive wells and a royalty interest only in 297 additional wells. The wells we own a working interest in are primarily oil wells (4,042 gross, 2,693 net productive oil wells) that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.
Drilling Results
The following table sets forth the results of our drilling activity, as defined by wells placed on production, for the periods indicated. Productive wells are exploratory, development or extension wells that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are exploratory, development or extension wells that prove to be incapable of producing hydrocarbons in sufficient quantities to justify incurring the costs associated with completion as an oil or gas well.
Year Ended December 31,
Gross
Net
Gross
Net
Gross
Net
Development Wells:
Productive
Dry (1)
Exploratory Wells:
Productive
Dry
Total
(1) The developmental dry hole category includes wells that were unsuccessful due to mechanical issues that occurred during drilling.
As of December 31, 2025, we had 159 gross (117.7 net) operated wells in the process of drilling or completion.
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Delivery Commitments
The table below summarizes our long-term firm sales agreements, which provides for gross firm sales over the contractual term:
NGL Volume Commitments (1)
Period
Total (Bbls)
Daily (Bbls/d)
Total
Natural Gas Volume Commitments (1)
Period
Total (Mcf)
Daily (Mcf/d)
Thereafter (2)
Total
(1) Above volumes represent the total gross volumes we are required to deliver pursuant to agreements with carriers, which gross volumes are not comparable to our net production presented in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation in this Annual Report, as amounts therein are reflected net of all royalties, overriding royalties and production due to others.
(2) These agreements have a contractual term through December 31, 2031.
These committed volumes are subject to under-delivery fees that would result in a financial obligation equal to a specified rate, subject to certain inflation factors. We expect our production and reserves will continue to be the primary means of fulfilling our future commitments. Refer to Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report for additional information on our delivery commitments.
Title to Properties
We believe that we have satisfactory title to substantially all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, working and other outstanding interests customary in the industry. In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.
Marketing and Customers
We market the majority of the production from properties we operate on account of both ourselves and that of the other working interest owners in these properties. We generally sell our oil, NGL and natural gas production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, and the majority of our revenue contracts have terms greater than twelve months.
We normally sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of our total net revenues in at least one of the periods presented:
Year Ended December 31,
Enterprise Crude Oil, LLC
Shell Trading (US) Company (1)
BP America (1)
(1) During the year ended December 31, 2025, these customers accounted for less than 10% of our total net revenues.
During these periods, no other purchaser accounted for 10% or more of our net revenues. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term. However, since crude oil and natural gas are
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fungible products with well-established markets and numerous purchasers that are based on current demand for oil and natural gas, we believe that the loss of any major purchaser would not have a material adverse effect on our financial condition or results of operations.
Competition
The oil and natural gas industry is a highly competitive environment. We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business including exploring, developing and operating our properties as well as transporting and marketing our production. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect the supply and demand for oil and natural gas production, such as price fluctuations (including basis differentials), domestic and foreign political conditions, weather conditions, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources. Our ability to acquire additional prospects 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.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production. The majority of our oil production is sold at the wellhead as it enters third-party gathering pipelines. The purchaser then transports the oil by pipeline or truck to a tank farm, another pipeline or a refinery. Our natural gas is either transported by gathering lines from the wellhead to a central delivery point and is then gathered by third-party lines to a gas processing facility or gathered by a third-party directly from the wellhead.
Regulation of the Oil and Natural Gas Industry
Our operations are subject to extensive federal, state and local laws and regulations. All of the jurisdictions in which we own or operate producing properties have statutory provisions regulating the development and production of oil and natural gas, including, but not limited to, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations including, but not limited to, the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Federal and state environmental and occupational health and safety laws impose certain performance or compliance standards, work practices and recordkeeping and reporting obligations on our operations.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted, unforeseen environmental, health or safety incidents may occur and past non-compliance may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional regulatory proposals and proceedings affecting the oil and natural gas industry are regularly considered by Congress, the states, regulatory authorities, including the Federal Energy Regulatory Commission (“FERC”) and the U.S. Environmental Protection Agency (the “EPA”), and the courts. We cannot predict when or whether any such outcomes of these proceedings will materially affect our operations.
Regulation of Production of Oil and Natural Gas
The production of oil, NGLs and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in New Mexico and Texas, which regulate drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of New Mexico and Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, NGLs and natural gas that we can produce from our wells and to limit the number of wells or the locations where we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, New Mexico and Texas impose a production or severance tax with respect to the production and sale of oil, NGLs and natural gas within their jurisdiction.
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Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, and as a result we do not expect compliance with such regulatory requirements to affect our operations in any way that is of material difference from our competitors who are similarly situated. However, the failure to comply with these rules and regulations can result in substantial penalties.
Regulation of Sales and Transportation of Oil
Sales of oil, NGLs and condensate from our producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.
Sales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We rely on third-party pipeline systems to transport the majority of crude oil produced by our wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil producers and marketers with which we compete.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (the “NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The federal Energy Policy Act of 2005 (the “EP Act of 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amended the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provided FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The maximum civil penalty authority under the NGA and NGPA is adjusted annually for inflation; as of January 14, 2025, FERC may now assess civil penalties under the NGA and NGPA of $1,584,648 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. The issued rules make it unlawful, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
We are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and those enforced by the US Commodity Futures Trading Commission (the “CFTC”) under the Commodity Exchange Act, as amended (the “CEA”) and CFTC regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, as well as the market for financial instruments on such commodity, such as futures, options and swaps. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowinglyinaccurate reports concerning market information or conditions that affect or tend to affect the
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price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damageclaims by, among others, sellers, royalty owners and taxing authorities.
Natural gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states. Section 1(b) of the NGA exempts companies that provide natural gas gathering services from regulation by FERC as a “natural gas company” under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, or vice versa, and depending on the scope of that decision, our costs of delivering gas to point-of-sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action that FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.
Regulation of Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent federal, state and local laws and regulations governing the occupational safety and health aspects of our operations, the discharge of materials into the environment, and protection of the environment and natural resources (including threatened and endangered species and their habitats). Numerous governmental entities, including the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring costlyinvestigation or actions. These laws and regulations may, among other things, (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment or injected into formations in connection with drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; (iv) require remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminalpenalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.
The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws and regulations, as amended from time to time, to which our business operations are or may be subject, and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Handling Wastes
The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and nonhazardous solid wastes. Pursuant to rules issued by the EPA, states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development and production of oil, NGLs and natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes currently classified as nonhazardous solid wastes could be re-classified as
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hazardous wastes in the future, as RCRA requires the EPA to periodically review (and revise if necessary) such determinations. Any such reclassification could increase our costs (and those of the oil, NGL and natural gas exploration and production industry) to manage and dispose of wastes, and materially adversely affect our results of operations and financial position. While the costs of managing waste (including hazardous waste) may be insignificant, we do not believe that our costs in this regard are materially more burdensome than those of similarly situated companies.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or the legality of conduct, on classes of persons considered responsible for the release of a hazardous substance into the environment. These persons include the current and former owners or operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for remediation costs, damages to natural resources, and the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment, and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damageallegedly caused by the hazardous substances released into the environment. We may generate materials in the course of our operations that may be regulated as hazardous substances.
We currently own, lease or operate numerous properties that have been used for oil, NGL and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Water Discharges
The Clean Water Act (the “CWA”) and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills, leaks of hazardous substances and placement of dredge and fill material into state waters and waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminalpenalties for noncompliance with discharge permits or other CWA requirements and analogous state laws and regulations.
There continues to be uncertainty as to the federal government’s jurisdictional reach under the CWA, including with respect to wetlands. The EPA and the U.S. Army Corps of Engineers (the “Corps”) under the Obama, Trump and Biden administrations have pursued multiple rulemakings since 2015 in the attempt of determining the scope of such reach. Following legal actions, implementation of the most recent rule is currently split across the country. The rule is subject to an injunction in 27 states, including Texas, resulting in implementation of the pre-2015 rule adjusted to take into account jurisdictional limitations decided by the Supreme Court in Sackett v. EPA . The other 23 states, including New Mexico, are subject to a WOTUS-defining rule published in September 2023. The Corps is currently pursuing a new post- Sackett rulemaking, the ultimate consequence of which cannot be predicted at this time.
Many of our customers and service providers rely on permits obtained under the CWA for their oil and gas pipeline projects, the most common of which is Nationwide Permit 12 (“NWP 12”). NWP 12 is, from time to time, renewed or modified by the Corps, whose actions in turn may be subject to litigation. NWP 12 is expected to be reissued by the Corps in 2026. To the extent any action expands the scope of the CWA in areas where we or our suppliers, customers or service providers operate or imposes new or enhanced permitting requirements, our operations could be adversely impacted by increased compliance costs and energy infrastructure project delays or cancellations.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening WOTUS or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible
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party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.
Subsurface Injections
In the course of our operations, we produce water in addition to crude oil, NGLs and natural gas. Produced water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near below-ground disposal wells used for the injection of natural gas- and oil-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other fluids may increase our costs or have other adverse impacts on our operations. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies, as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil, NGL and natural gas producers, and we do not believe that the costs associated with the disposal of produced water will affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Air Emissions
The federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of our projects. Recently, there has been increased regulation with respect to air emissions from the oil and natural gas sector. For example, the EPA has promulgated rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”), and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Emissions Standards for Hazardous Air Pollutants program.
The EPA’s 2024 updates to NSPS regulations applicable to oil and natural gas sectors require, among many things, the phase out of routine flaring of natural gas from new oil wells, routine leak monitoring, detection and repair obligations at all well sites and compressor stations, and reductions in emissions via capture and control systems or the use of zero-emission equipment in certain processes. The 2024 NSPS rule also establishes a “Super Emitter Response Program” that would trigger certain operator investigation and repair requirements in response to an emissions event exceeding 200 pounds per hour, as detected by regulatory authorities or qualified third parties. The 2024 NSPS rule further obligates states to impose these requirements on existing sources through their respective state implementation plans . In March 2025, the EPA announced an intent to reconsider the 2024 NSPS rule’s provisions into late 2026 or early 2027. Because the 2024 NSPS and 2025 deadline extension rules are subject to ongoing litigation and the EPA is currently reconsidering the 2024 NSPS rule, future implementation of these regulations is uncertain at this time. The EPA’s NSPS regulatory program, and any new, more stringent emissions regulations promulgated by the EPA or any other federal or state agency, could raise our costs of regulatory compliance.
The EPA is also required by the CAA to set National Ambient Air Quality Standards (“NAAQS”) for six principal pollutants that are considered harmful to public health. Whether the air quality in a particular region is in “attainment” with the NAAQS for a particular pollutant impacts the stringency of certain air quality controls and restrictions in that area. The EPA periodically reviews each NAAQS and determines whether a revision is necessary. For example, in February 2024, the EPA issued a final rule lowering the primary annual NAAQS for particulate matter 2.5 from 12.0 μg per cubic meter to 9.0 μg per cubic meter. While the areas in which we operate were not likely to be redesignated as a result of this change, any adoption of a more stringent NAAQS has the potential to result in more restrictive permitting and pollution control requirements, increased permitting delays, or emission offset requirements.
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Compliance with one or more of these and other air pollution control and permitting requirements and rules has the potential to delay the development of natural gas, oil and NGL projects and increase our costs of development and production, which costs could be significant.
Regulation of GHG Emissions and Climate Change
In response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) preconstruction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions and impose performance standards for reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from large GHG emission sources in the United States, including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our operations. The Bureau of Land Management (“BLM”) has also, from time to time, considered or adopted rules regulating GHG emissions from oil and gas operation on federal lands. Nevertheless, there continues to be uncertainty surrounding the federal regulation of methane and other GHG emissions. Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several Presidential administrations. The current Trump administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and promulgated a final rule, in February 2026, repealing the EPA’s 2009 “Endangerment Finding” that forms the basis for most of the EPA’s GHG-related rules. However, whether or how such policies and the EPA’s rescission of its “Endangerment Finding” will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulations, cannot be predicted at this time.
While Congress has, from time to time, considered legislation to reduce emissions of GHGs, including proposals adopting cap-and-trade programs, carbon taxes, climate-related mitigation funds, and regulations that directly limit GHG emissions from select sources, no significant legislation has been adopted at the federal level. While Congress previously enacted the Inflation Reduction Act of 2022 (the “IRA”) to advance climate-related objectives and provide financial support for alternative or lower GHG-emitting energy production, many of these incentives were repealed or otherwise modified following the change in Presidential administrations and the enactment of the One Big Beautiful Bill Act in 2025 (“OBBBA”). However, any similar or future climate-related legislation and accompanying policy initiatives could increase operating costs within the oil and gas industry or accelerate a transition away from fossil fuels, which could in turn reduce demand for our products and adversely affect our business and results of operations.
In the absence of such federal climate legislation, a number of state and regional climate-related initiatives and regulations have emerged. In New Mexico, recent legislation codified a regulatory provision requiring operators to capture 98% of their produced natural gas. Routine venting and flaring is also prohibited in New Mexico. State, regional and local governments may also elect to continue to participate in international climate change initiatives, despite the Trump administration finalizing the United States’ withdrawal from such initiatives in 2026. The participation in, or support for, climate-related policies and initiatives by politicians, regulators, financial institutions, consumers, and other stakeholders could increase oppositionagainst, reduce funding for or lead to new limitations on, fossil fuel exploration and production activities.
Although it appears unlikely in the near term that new federal laws or regulations may be adopted or issued to address GHG emissions, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and NGLs we produce and lower the value of our reserves.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, NGLs and natural gas from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued permitting guidance under the SDWA for certain hydraulic fracturing activities involving the use of diesel fuels and published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. Many states, including Texas and New Mexico, have promulgated rules related to the
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public disclosure of substances used in hydraulic fluid and testing requirements for water wells near drilling sites. Some local governments have also sought to regulate the time, place, and manner of drilling and hydraulic fracturing activities within their jurisdictions, or to ban hydraulic fracturing within their jurisdiction altogether. In the event that new federal or more stringent state or local regulations relating to the hydraulic fracturing process are adopted in areas where we operate, we may incur additional costs to comply with such requirements that may be significant in nature, and we also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of our exploration, development, or production activities.
Activities on Federal and State Lands
Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, require compliance with detailed federal regulations and orders, including relating to plugging and abandonment, and are frequently subject to permitting delays. Federal oil and gas leasing programs have also been, from time to time, suspended by executive order or subject to collateral litigation.
Operations on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. The NEPA evaluation process has followed regulations issued by the Council on Environmental Quality (“CEQ”) for many years. However, in January 2026, CEQ issued a final rule rescinding its regulations following a D.C. Circuit decision limiting CEQ’s authority to promulgate such rules and regulations. Further, the U.S. Supreme Court’s recent Seven County decision directed lower courts to give substantial deference to the reviewing agency’s select scoping decisions in NEPA reviews. The ultimate outcome of these developments are not yet clear.
Our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations and the support of infrastructure projects that may be subject to the requirements of NEPA. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects. Individual authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial. However, any such adverse regulatory developments are expected to have no more than a minimal impact on our results, given our limited exposure of leases on federal lands.
Protected Species
The federal Endangered Species Act (“ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”). The extent of regulatory restrictions imposed by these laws depends on the implementing regulations promulgated by the U.S. Fish and Wildlife Service (“USFWS”) and the National Marine Fisheries Service (“NMFS”), which have varied between recent Presidential administrations. Congress, from time to time, has also considered legislation to reform certain aspects of the ESA and MBTA.
We may conduct operations on oil and natural gas leases in areas where certain species that are , were or are candidates to be listed as threatened or endangered are known to exist, including the Dunes Sagebrush Lizard and Lesser Prairie Chicken (the listing decisions of which are currently subject to ongoing litigation), and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Occupational Safety and Public Right-to-Know Regulations
We are subject to the requirements of the Occupational Safety and Health Act, as implemented by the Occupational Safety and Health Administration (“OSHA”), and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, the EPA’s Risk Management Program rule and comparable state statutes, and their implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.
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Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other activities and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.
Human Capital Resources
We aim to attract and retain top-tier talent in the oil and gas sector and empower our employees to be innovators in our industry. As of December 31, 2025, we had approximately 515 total employees. In addition, we hire independent contractors on an as needed basis. We are not a party to any collective bargaining agreements. We maintain an at-will employment relationship with our employees, and have not entered into any contracts guaranteeing ongoing employment.
We believe that our employees give us a sustainable competitive advantage, and we understand the need to attract, retain and develop the best team possible. We believe the wage rates provided to our employees assist in retention of our top talent, and our compensation programs are integrated with our overall business strategies to incentivize performance and maximize shareholder returns. We offer a variety of programs that are designed to retain our employees and also provide opportunities to grow their professional careers while continuing to deliver value to the Company. Additionally, we maintain a comprehensive suite of benefits that provide our employees with various options including retirement, health and wellness, and life and disability plans.
We are committed to a highly-qualified workforce and we believe employees with different skillsets, experiences and interests drive superior results. This commitment extends to our hiring, development and promotion practices, which recognize our employees for their various capabilities and contributions to the Company.
We strive to promote a safe and healthy working environment, prioritizing the safety and well-being of our employees, contractors, the public, and the environment in the communities where we operate. Through frequent training sessions and monthly safety meetings, we equip our field employees with the knowledge and tools to mitigate risks and uphold our strong safety culture. While we have consistently excelled in health, safety, and environmental performance, maintaining an impressive record of minimal workplace incidents, we remain vigilant. Any workplace injury reinforces the need for ongoing safety awareness and enhanced protocols to prevent future occurrences.
Offices
Our principal executive offices are located at 300 N. Marienfeld Street, Suite 1000, Midland, Texas, 79701, and our telephone number is (432) 695-4222. We also have offices located in Carlsbad, New Mexico; Denver, Colorado; Eunice, New Mexico; Gardendale, Texas; Greenwood, Texas; Pecos, Texas; San Angelo, Texas; and Woodlands, Texas.
Available Information
Our internet website address is www.permianres.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. Information on our website is not incorporated by reference into this Annual Report and should not be considered part of this document.
The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov.
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ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors together with all of the other information included in this Annual Report and our other reports filed with the SEC before investing in our securities. The occurrence of one or more of these risks could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our securities.
Risks Related to Commodity Prices
Commodity prices are volatile, and a sustained period of low commodity prices for oil, NGLs and natural gas could adversely affect our business, financial condition and results of operations.
The prices we receive for our oil, NGLs and natural gas heavily influence our revenue, cash flows, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, NGLs and natural gas are commodities, and their prices may fluctuate widely in response to relatively minor changes in the actual and expected supply of and demand for oil, NGLs and natural gas and market uncertainty. Historically, oil, NGL and natural gas prices have been volatile and subject to fluctuations relating to a variety of additional factors that are beyond our control, including:
• worldwide and regional economic conditions impacting the global supply of and demand for oil, NGLs and natural gas;
• the price and quantity of foreign imports of oil, NGLs and natural gas;
• political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America, such as the recent developments in Venezuela;
• actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
• actions of U.S., European Union and other governments and governmental organizations relating to Russia’s oil, NGLs and natural gas, including through sanctions, import restrictions and commodity price caps;
• actions of U.S. producers, and independent producers operating in other countries, relating to production levels;
• political, economic and other conditions that affect perceived or actual demand for oil, NGLs and natural gas, including international conflict, trade disputes, the imposition of tariffs or sanctions and global health concerns;
• the level of global exploration, development, production, and inventories;
• actions of U.S. and other governments to strategically release oil, NGLs and natural gas from strategic reserves, including any increased volumes of Venezuelan crude oil;
• the availability of refining and storage capacity;
• prevailing prices on local price indexes in the area in which we operate;
• the proximity, capacity, cost and availability of gathering and transportation facilities;
• the cost of exploring for, developing, producing and transporting reserves;
• weather conditions and other natural disasters, including winter storms, hurricanes, droughts, fires, earthquakes, flooding and tornadoes;
• terrorist attacks and cybersecurity risks targeting oil and natural gas related facilities and infrastructure;
• technological advances, including AI and its increased use, affecting fuel economy, energy supply and energy consumption;
• the effect of energy conservation measures, alternative fuel requirements and the price and availability of alternative fuels;
• laws, regulations and taxes in the U.S. and in foreign jurisdictions that impact the demand for oil, NGLs and natural gas;
• shareholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize emissions of carbon dioxide and methane GHGs or otherwise;
• localized and global supply and demand fundamentals; and
• expectations about future commodity prices.
These factors, among others, and the volatility of the energy markets make it extremely difficult to predict future oil, NGL and natural gas price movements with any certainty.
A sustained or extended decline in commodity prices may result in a shortfall in our expected revenues and cash flows and require us to reduce capital spending or borrow funds to cover any such shortfall. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained
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periods of low commodity prices for oil and natural gas and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone, moderate or eliminate our planned drilling and completions operations, or suspend production from current wells, which could result in the reduction of our expected production and some of our proved undeveloped reserves and related standardized measure. If we moderate or curtail our drilling, completion or production operations, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a sustained or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.
Accounting guidance requires 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, 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 charge to earnings. A sustained or extended decline in commodity prices could require that we recognize 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.
Risks Related to Our Reserves, Leases and Drilling Locations
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. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, seismic, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as commodity prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant inaccuracies in our interpretations of this technical data or in making our assumptions could materially affect the estimated quantities and present value of our reserves.
Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary 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 our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. Our estimated proved reserves as of December 31, 2025, and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $66.01 per barrel of oil (WTI Posted) and $3.39 per MMBtu (Henry Hub spot), which may be substantially higher or lower than the available spot prices in 2025. For example, if the crude oil and natural gas prices used in our year-end reserve estimates were to increase or decrease by 10%, our proved reserve quantities at December 31, 2025 would increase by 45.5 MMBoe (4.1%) or decrease by 69.5 MMBoe (6.2%) and the pre-tax PV 10% of our proved reserves would increase by $2.2 billion (24%) or decrease by $2.2 billion (23%).
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
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 exploration and 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 flows 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, particularly because competition in the oil and natural gas industry is intense, and many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. 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.
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The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
As of December 31, 2025, 29% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues 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 our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
As of December 31, 2025, over 96% of our total net acreage was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. Some of our leases also expire as to certain depths if continuous drilling obligations are not met. If our leases expire in whole or in part and we are unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
In the future, we may shut-in some or all of our production depending on market conditions, storage or transportation constraints and contractual obligations, and any prolongedshut-in of our wells could result in the expiration, in whole or in part, of the related leases, which could adversely affect our reserves, business, financial condition and results of operations.
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 estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, availability of gathering or transportation facilities, access to and availability of water sourcing and distribution systems, regulatory approvals, including permitting, and other factors. Because of these uncertain factors, we do not know if the numerous identified drilling locations will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
Properties that we decide to drill may not yield oil or 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 or completion costs or be economically viable. The use of micro-seismic 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.
Risks Related to Our Operations
Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, or at all, which could lead to a decline in our ability to access or grow production and reserves.
The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. Historically, we have funded our capital expenditures with cash flows from operations and may from time to time utilize borrowings under OpCo’s revolving credit facility, proceeds from offering debt and equity securities and divestitures of non-core assets, and we intend to finance our future capital expenditures in a similar fashion. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among
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other things, oil, NGL and natural gas prices; actual drilling results; the availability of drilling rigs and other services and equipment; 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;
• our proved reserves;
• the level of hydrocarbons we are able to produce from existing wells;
• our ability to acquire, locate and produce new reserves;
• the levels of our operating expenses; and
• our ability to borrow under OpCo’s revolving credit facility and to access the capital markets.
If our revenues or the borrowing base under OpCo’s revolving credit facility decrease as a result of lower oil, NGL and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under OpCo’s revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. This, in turn, could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. In addition to the risks we face in drilling for and producing oil and natural gas, some factors that may directly or indirectly negatively impact our scheduled operations include:
• lack of available gathering or transportation facilities or delays in constructing such facilities;
• abnormal pressure or irregularities in geological formations;
• shortages of or delays in obtaining equipment, qualified personnel, materials or resources;
• equipment failures, accidents or other unexpected operational events;
• delays imposed by or resulting from compliance with laws, regulations or litigation, including limitations resulting from wastewater disposal, emission of GHGs and limitations on hydraulic fracturing;
• environmental hazards, such as oil and 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 surface and subsurface environment;
• natural disasters and other weather events;
• personal injuries and death;
• terrorist attacks and cybersecurity risks targeting oil and natural gas related facilities and infrastructure;
• limited availability of financing at acceptable terms;
• title problems; and
• limitations in the market for oil and natural gas.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events, including those operating risks listed above, could materially and adversely affect our business, financial condition or results of operations. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. 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.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a
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result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include:
• landing a wellbore in the desired drilling zone;
• staying in the desired drilling zone while drilling horizontally through the formation; and
• spacing the wells appropriately to maximize production rates and recoverable reserves.
Risks that we face while completing wells include:
• the ability to fracture stimulate the planned number of stages;
• the ability to run tools the entire length of the wellbore during completion operations; and
• the ability to prevent unintentional communication with other wells.
If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in certain portions of Texas and New Mexico in past years. These drought conditions have led some local water districts to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Where practicable, we strive to use recycled water for our hydraulic fracturing operations. If we are unable to obtain water from water suppliers or our recycling operations, it may need to be obtained from non-local sources and transported to drilling sites, resulting in increased costs, or we may be unable to economically drill for or produce oil and natural gas, each of which could have an adverse effect on our financial condition, results of operations and cash flows.
Our ability to produce crude oil, NGLs and natural gas economically and in commercial quantities could be impaired if we are unable to recycle or dispose of the produced water we produce in an economical and environmentally safe manner.
Our operations could be impaired if we are unable to recycle or dispose of the produced water we generate in an economical and environmentally safe manner. Where practicable, we strive to recycle produced water for our future oil and gas operations. Produced water that is not recycled is generally disposed in disposal wells that are operated by us or third-party contractors. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection of produced water resulting from oil and gas activities, which has led to increased public and governmental scrutiny of injection safety. For instance, in response to concerns regarding induced seismicity, regulators in Texas have adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely, or determined, to be causing seismic activity. Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion regarding regulations affecting the handling and disposal of produced water.
Another potential consequence of produced water disposal activities and seismic events are lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Such developments could result in additional regulation and restrictions on our use of injection wells or commercial disposal wells to dispose of produced water. Increased regulation and attention given to water disposal and induced seismicity could also lead to greateropposition, including litigation, to limit or prohibit oil and gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in limitations on disposal well volumes, disposal rates and pressures or locations, require us or our vendors to shut down or curtail the injection into disposal wells, or cause delays, interruptions or termination of our operations, which events could have a material adverse effect on our business, financial condition and results of operations.
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Our producing properties are concentrated in the Permian Basin, making us vulnerable to risks associated with operating in a single geographic area.
Our producing properties are geographically concentrated in West Texas and New Mexico in the Permian Basin. At December 31, 2025, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionatelyexposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages, regional power outages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, NGLs or natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
The marketability of our production is dependent upon transportation and other facilities, most of which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted and our revenues reduced.
The marketability of our oil, NGLs and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil, NGLs and natural gas production is generally transported from the wellhead by gathering systems that are either owned by us or third-party midstream companies. In general, we do not control the transportation of our production and our access to transportation facilities may be limited or denied. In some instances, we have contractual guarantees relating to the transportation of our production through firm transportation arrangements, but third-party systems may be temporarily unavailable due to pressure limitations, market conditions, mechanical failures, accidents or other reasons. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or third-party midstream companies or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, NGLs and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements, we may be required to shut in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil, NGLs and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.
We have entered into multi-year agreements with some of our suppliers, service providers and the purchasers of our oil and natural gas, which contain minimum volume commitments. Any failure by us to satisfy the minimum volume commitments could lead to contractual penalties that could adversely affect our results of operations and financial position.
We have entered into certain multi-year supply and service agreements associated with energy and frac sand purchase agreements and have long-term agreements in place for drilling rigs, office rentals and other wellhead equipment. We also have various multi-year agreements that relate to the sale, transportation or gathering of our oil, NGLs and natural gas and may in the future enter into multi-year agreements for contracts for other services. Some of these agreements contain minimum volume commitments that we must satisfy or contractual penalties in the form of volume deficiencies or other remedies may apply. For example, we have recently entered into firm transportation arrangements where we are obligated to pay fixed amounts on minimum volumes regardless of actual volume throughput under these contracts. We may be unable to use our full transportation capacity under existing firm transportation agreements, resulting in obligations to pay fees without receiving revenues on sales. As of December 31, 2025, our aggregate long-term contractual obligation under our multi-year agreements was $1.5 billion, which represents the gross minimum obligation but does not include amounts that may be due under certain contracts that contain variable pricing or volumetric components as the future obligations cannot be determined. Further information about these agreements can be found at Delivery Commitments under Part I, Items 1 and 2 and Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report. Any failure by us to satisfy the minimum volume commitments in these agreements could adversely affect our results of operations and financial position.
The unavailability or high cost of additional drilling rigs, 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, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted by
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tariffs or other trade restrictions imposed by the United States on imported goods from countries where these goods are produced. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages or cost increases could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
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, our capital and operating costs have risen during periods of increasing oil, NGL and natural gas prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased tariffs and comparative taxes. Such costs may rise faster than increases in our revenue as commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.
We depend upon a small number of significant purchasers for the sale of most of our oil, NGL and natural gas production.
We normally sell production to a relatively small number of customers, as is customary in our business. See Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part II, Item 8 of this Annual Report for significant purchasers that accounted for more than 10% of our revenues for the years ended December 31, 2025, 2024 and 2023. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term.
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 can 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.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may cause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
We intend to pursue a strategy focused on both reinvestment and future acquisitions. As part of this strategy, we intend to make future acquisitions of assets or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including:
• recoverable reserves;
• future commodity prices and their applicable differentials;
• operating costs; and
• potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Furthermore, 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. In addition, debt agreements impose certain limitations on our ability to enter into mergers or combination transactions and our ability to incur certain indebtedness, which could indirectly limit our ability to engage in certain acquisition activities.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business, asset or property into our existing operations. The process of integrating acquired businesses, assets and properties may involve
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unforeseendifficulties and may require a disproportionate amount of our managerial and financial resources. Additionally, the integration of acquisitions is a complex, costly and time-consuming process, and our management may face significant challenges in such process. Some of the factors affecting integration will be outside of our control, and any one of them could result in increased costs and diversion of management’s time and energy, and could materially and adversely affect our revenues.
We are heavily dependent on our information and operational technology systems and other digital technologies.
Our ability to effectively manage and operate our business depends significantly on information and operational technology systems and other digital technologies. The availability and integrity of these systems and technologies are essential for us to conduct our business and operations. Any failure of these systems to operate effectively and support our operations, challenge in transitioning to new upgraded or replacement systems, including any implementation or utilization of AI systems, difficulty in integrating systems and updates across our growing business, or a breach of these systems could materially and adversely impact the operations of our business. In addition, cybersecurity incidents, including deliberate attacks or unintentional events, have generally continued to increase in frequency and become increasingly sophisticated. The U.S. government has also issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats.
Any breach of our network may result in the loss of valuable business data or critical infrastructure, misappropriation of our customers’, employees’ or service providers’ personal information, or a disruption of our business and operations, which could harm our customer relationships and reputation, and result in lost revenues, remediation and compliance costs, litigation, regulatory investigations and enforcements and penalties and fines. Although we utilize various procedures and controls to monitor, protect against and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing such threats from materializing, particularly given the unpredictability of the timing, nature, and scope of such breaches. While we endeavor to maintain insurance that covers certain cybersecurity incidents, we may not be insured for, or our insurance may be insufficient to protect us against, particular types of cybersecurity risks, and, in the future, such insurance may not continue to be available to us on reasonable terms, if at all. Furthermore, weaknesses in the cybersecurity of our vendors, suppliers, and other business partners could be used to facilitate an attack on our systems and networks.
Moreover, we must comply with increasingly evolving, complex and rigorous regulatory standards enacted to protect business and personal data. New laws and regulations governing data privacy and the unauthorized disclosure of personal or confidential information may pose compliance challenges and could elevate our costs. Any failure to comply with these laws and regulatory standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against us by governmental entities or others, damage to our reputation and credibility, and could have a negative impact on revenues and profits.
As of the date of this Annual Report, though the Company and its service providers have experienced certain cybersecurity incidents, we are not aware of any cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations and financial condition. However, we acknowledge that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents, material or otherwise, remains. Consequently, it is possible that any such occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations. Additional information on our cybersecurity risk management, strategy and governance can be found at Part I, Item 1C of this Annual Report.
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 may be unable to compete effectively with larger companies, which may adversely affect our results of operations and financial condition.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us, particularly following recent consolidation within the industry. Many of our larger competitors not only drill for and produce oil and natural gas, but they also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. Our competitors may be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments, and acquiring resources and other materials in markets experiencing shortages. In addition, competition is strong for attractive oil and natural gas properties, oil and natural gas companies, and drilling rights. Our inability to compete effectively with our competitors could have a material and adverse impact on our business activities, financial condition and results of operations.
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Risks Related to Our Derivative Transactions, Debt and Access to Capital
Our derivative activities could result in financial losses or could reduce our earnings.
We may enter into derivative instrument contracts for a portion of our oil and natural gas production from time to time. As of December 31, 2025, we had entered into derivative contracts covering a portion of our projected oil and gas production through 2027 (refer to Note 8—Derivative Instruments under Part II, Item 8 of this Annual Report for a summary of our derivative instruments as of December 31, 2025). Accordingly, our earnings may fluctuate significantly as a result of changes in 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;
• there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
• there are issues with regard to 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 or interest rates 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 and make payments on our indebtedness, and which could also limit the size of OpCo’s borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile commodity prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.
Our commodity 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 accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
Since our production is not fully hedged, and we are also exposed to fluctuations in oil, NGL and natural gas prices as it relates to the price we receive from the sale of our unhedged volumes. We intend to continue to hedge a portion of our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility with regard to these unhedged volumes, and a decline in commodity prices could materially and adversely affect our business, financial condition and results of operations.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on our outstanding debt.
As of December 31, 2025, we had approximately $3.5 billion of total long-term debt and additional borrowing capacity of $2.5 billion under OpCo’s revolving credit facility, all of which would be secured if borrowed. Subject to the restrictions in the instruments governing OpCo’s outstanding indebtedness (including OpCo’s revolving credit facility and senior notes), OpCo and its subsidiaries may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the instruments governing OpCo’s outstanding indebtedness do contain restrictions on the incurrence of additional indebtedness, these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.
Our current and future level of indebtedness could affect our operations in several ways, including the following:
• require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;
• limit 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;
• increase our vulnerability to downturns and adverse developments in our business and the economy generally;
• limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses or to refinance existing indebtedness;
• place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
• make it more likely that a reduction in OpCo’s borrowing base following a periodic redetermination could require OpCo to repay a portion of its then-outstanding bank borrowings;
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• make us vulnerable to increases in interest rates as the indebtedness under OpCo’s revolving credit facility may vary with prevailing interest rates;
• place us at a competitive disadvantage relative to our competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
• make it more difficult for OpCo to satisfy its obligations under its debt and increase the risk that we may default on its debt obligations.
We may not be able to generate sufficient cash to service all of OpCo’s indebtedness and may be forced to take other actions to satisfy OpCo’s obligations under applicable debt instruments, which may not be successful.
OpCo’s ability to make scheduled payments on or to refinance its indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit OpCo to pay the principal, premium, if any, and interest on OpCo’s indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance OpCo’s indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require OpCo to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm OpCo’s ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The agreements governing OpCo’s indebtedness restrict OpCo’s ability to dispose of assets and OpCo’s use of the proceeds from such disposition. OpCo may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit OpCo to meet scheduled debt service obligations.
Restrictions in OpCo’s existing and future debt agreements could limit our growth and ability to engage in certain activities.
OpCo’s credit agreement with a syndicate of banks that provides for a secured revolving credit facility, maturing in February 2028 (the “Credit Agreement”), and the indentures governing its senior notes contain a number of significant covenants, including restrictive covenants that may limit OpCo’s ability to, among other things:
• incur additional indebtedness;
• make loans to others;
• make investments;
• merge or consolidate with another entity;
• make certain payments;
• hedge future production or interest rates;
• incur liens;
• sell assets; and
• engage in certain other transactions without the prior consent of the lenders.
These restrictions may be suspended when our debt instruments are assigned an investment grade rating (Baa3 or better by Moody’s Investors Service, Inc. or BBB- or better by S&P Global Ratings or Fitch Ratings Inc., or two out of three, as applicable). However, there can be no assurance that we will be able to achieve such ratings.
In addition, OpCo’s Credit Agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of December 31, 2025, we were in full compliance with such financial ratios and covenants.
The restrictions in OpCo’s debt agreements may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictions impose on OpCo.
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If OpCo is unable to comply with the restrictions and covenants in the agreements governing its indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that OpCo has borrowed.
Any default under the agreements governing OpCo’s indebtedness that is not cured or waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make OpCo unable to pay principal, premium, if any, and interest on such indebtedness. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on OpCo’s indebtedness, or if OpCo otherwise fails to comply with the various covenants, including financial and operating covenants, in the agreements governing OpCo’s indebtedness, OpCo could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
• the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;
• the lenders under OpCo’s revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and
• we could be forced into bankruptcy or liquidation.
If our operating performance declines, we may in the future need to obtain waivers under OpCo’s revolving credit facility to avoid OpCo being in default. If OpCo breaches the covenants under its revolving credit facility and seeks a waiver, OpCo may not be able to obtain a waiver from the required lenders. If this occurs, OpCo would be in default under the revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
Any significant reduction in the borrowing base under OpCo’s revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
OpCo’s revolving credit facility limits the amounts OpCo can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually in the spring and fall. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the loan. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted senior unsecured notes OpCo may issue in the future. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under OpCo’s revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. The elected commitments are currently $2.5 billion.
In the future, we may not be able to access adequate funding under OpCo’s revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent 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 the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, OpCo could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service OpCo’s indebtedness.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financing and trade credit and the terms of any financing or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates, as a result of elevated rates of inflation or otherwise, or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets, due to the imposition, or threat, of tariffs and other trade restrictions, geopolitical conflicts, including in oil producing countries like Venezuela, or otherwise, may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
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Risks Related to Legislative and Regulatory Initiatives
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 in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. 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 regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA and other federal agencies have asserted regulatory authority over aspects of the process. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.
Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The CEQ is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above-and-below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. To date, EPA has taken no further action in response to the December 2016 report. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These completed, ongoing, or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms. Additionally, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the Railroad Commission of Texas (the “TRRC”) has issued rules that set the requirements for drilling, putting pipe down and cementing wells, testing and reporting obligations, and the disclosure of substances used in the hydraulic fracturing process. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. State and federal regulatory agencies, including Texas, have also recently focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and seismic activity. The TRRC has issued orders restricting the use of disposal wells it determined were likely influencing seismic activity. Separately, New Mexico has implemented protocols requiring operators to take various actions with respect to disposal wells within a specified proximity of recent seismic activity, including a requirement to limit injection rates if the seismic event in question reached a certain magnitude. Increased regulation and attention given to induced seismicity could lead to greateropposition to, and litigation concerning, production or development activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectly impact our business, financial condition and results of operations. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
Conservation measures, technological advances and any negative shift in market perception toward the oil and natural gas industry could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, any increase in consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.
Certain segments of the investor community have previously expressed negative sentiment towards investing in the oil and natural gas industry and some financial institutions have previously developed investment funds that expressly exclude fossil fuel and other carbon-intensive businesses based on social and environmental considerations. Furthermore, certain other stakeholders have previously pressured commercial and investment banks to stop funding oil and gas projects.
The impact of the changing demand for oil and natural gas, together with any change in investor or consumer sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
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Our operations are subject to stringent, complex and evolving federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations or otherwise relating to protection of the environment and natural resources (including threatened and endangered species and their habitats). These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the requirement to engage in remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the 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. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminalpenalties, 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.
Certain environmental laws impose strict joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental, health and safety risks and costs or may not provide sufficient coverage if an environmental, health and safety claim is made against us. Moreover, public interest in the protection of the environment and human health has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. In the states of New Mexico and Texas, as an example, governmental authorities are investigating the practice of flaring natural gas and it is possible that such states could implement additional volumetric or other restrictions on this practice which may require us to curtail or shut in production which otherwise is or would be flared due to the unavailability of acceptable delivery, transportation or processing arrangements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected. Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion on the topics referenced above and additional information on existing and proposed laws and regulations related to environmental and occupational health and safety matters.
Climate change laws and regulations restricting emissions of GHGs could increase our costs and reduce demand for the oil and natural gas we produce.
The threat of climate change continues to attract attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor, limit, and report existing emissions of GHGs as well as to reduce such future emissions. While no comprehensive climate change legislation has been implemented at the federal level, certain federal laws, like the IRA, have been enacted to advance numerous climate-related objectives. The OBBBA rescinds or eliminates funding for multiple programs under the IRA aimed at reducing or monitoring GHG emissions and other air pollutants, such as the Greenhouse Gas Reduction Fund and methane monitoring initiatives. While the OBBBA will potentially affect federal efforts to address climate change and emissions reductions, various federal agencies have, from time to time, adopted climate change considerations into their rulemaking and decision-making processes and have promulgated regulations that seek to restrict, monitor, or otherwise limit GHG emissions. International climate commitments made by political, industrial, and financial and other stakeholders may also impact commercial, regulatory, and consumer trends related to climate change.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction and Title V operating permits for GHG emissions from certain large stationary sources, mandate monitoring and annual reporting of GHG emissions, and impose new standards for reducing methane emissions from oil and gas operations by limiting venting and flaring and implementing leak detection and repair programs. Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several Presidential administrations. The current Trump administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and, in February 2026, promulgated a final rule repealing the EPA’s 2009 “Endangerment Finding” and its motor vehicle GHG emission performance
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standards. This rescission of the “Endangerment Finding” eliminates the basis for EPA’s authority under the CAA for most of its regulations concerning GHGs. However, whether or how such policies and the EPA’s recission of its “Endangerment Finding” will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulation, cannot be predicted at this time.
At the international level, the United Nations-sponsored Paris Agreement encourages nations to limit their GHG emissions through nationally-determined, though non-binding, reduction goals. Recent Conferences of the Parties have resulted in reaffirmations of the objectives of the Paris Agreement, calls for parties to eliminate certain fossil fuel subsidies and pursue reductions in non-carbon dioxide GHG emissions, agreements to transition away from fossil fuels in energy systems and increase renewable energy capacity, financial commitments to fund energy transition efforts in developing countries, and similar initiatives, though none legally binding. However, in January 2025, President Trump ordered the revocation of any United States financial commitments on emission goals associated with international climate agreements. Then, in January 2026, the United States finalized its withdrawal from the Paris Agreement. The impacts of the United States’ withdrawal and other existing or future climate-related orders, pledges, agreements or any legislation or regulation promulgated in connection with the Paris Agreement, the Global Methane Pledge, or other international conventions cannot be predicted at this time. Further, state and local governments, financial institutions, and industry groups may elect to continue participating in international climate-related initiatives.
Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion on the topics referenced above and additional information on existing and proposed laws, regulations and international initiatives intended to address GHGs and other climate change issues. Existing and future laws and regulations relating to climate change and GHG emissions could increase our costs, reduce demand for our products, limit our growth opportunities, impair our ability to develop our reserves and have other adverse effects on our business. Climate change concerns could impact our stock price and access to capital to the extent certain stockholders, bondholders, and institutional lenders who elect to shift their investments to less carbon-intensive industries. While the landscape is evolving, certain U.S. and international banks, insurers or other financial institutions have also made “net zero” emission commitments or signed-on to initiatives related to reducing GHG emissions. Any reduction in the availability of capital or access to insurance products for us or our customers and suppliers could adversely impact our operations and financial performance.
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. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered or threatened species and their habitats 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 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. Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion on protected species regulations and developments.
A negative shift in investor sentiment towards the oil and natural gas industry and increased attention to sustainability and conservation matters may adversely impact our business.
Increased attention from companies’ investors, customers, employees, regulatory bodies and other stakeholders, as well as natural capital and societal expectations, on companies to address climate change, investor and societal expectations regarding voluntary or mandatory sustainability initiatives and disclosures, and consumer demand for alternative sources of energy may result in increased costs (including but not limited to increased costs associated with compliance, stakeholder engagement, contracting, and insurance), reduced demand for our products and services, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, heightened scrutiny of our statements and initiatives, and negative impacts on our stock price and access to capital markets. Increased attention to climate change and environmental conservation, for example, may result in demand shifts for our products and private litigationagainst us. To the extent that societal pressures or political or other factors are involved, it is possible that liability could be imposed on us without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. Voluntary disclosures regarding sustainability matters, as well as any sustainability disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to pursue, implement or make progressagainst sustainability strategies or achieve sustainability goals or commitments, including any GHG reduction or neutralization goals or commitments, could result in governmental investigations or enforcement, private litigation and damage our reputation, cause our investors or consumers to lose confidence in our Company, and negatively impact our operations.
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Any restrictions on oil and natural gas development on federal lands have the potential to adversely impact our operations.
We possess leases which are granted by the federal government and administered by the BLM, a federal agency. Operations we conduct on federal leases must comply with numerous additional statutory and regulatory restrictions. These leases contain relatively standardized terms requiring compliance with detailed regulations. Under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated. Any such suspension or termination of our leases could adversely impact the results of our operations.
Federal leasing and permitting programs for oil and natural gas development on federal lands have been, from time to time, subject to suspension or cancellation by executive order, subject to litigation by third parties, or otherwise restricted by federal action. For example, previous Presidential administrations have issued moratoriums on oil and gas leasing. Additionally, in 2024, the BLM finalized a rule requiring operators to limit venting and flaring and pay royalties on lost gas, though this rule is currently subject to litigation, postponed implementation, and reconsideration by the Trump administration. Congress may also, from time to time, legislate changes to the fiscal terms and environmental performance obligations of federal oil and gas leases. Certain lawmakers have proposed, and may continue to propose, to reduce or ban further leasing on federal lands or to adopt further restrictions on oil and gas development on federal lands. While we cannot predict the ultimate impact of these changes or whether federal agencies will implement further reforms, any revisions to the federal leasing or permitting process, by executive action, legislation or regulation, that make it more difficult or costly for us to pursue operations on federal lands may adversely impact our operations. However, any such adverse developments are expected to have no more than a minimal impact on our results, given our limited exposure of leases on federal lands. Additionally, any additional actions the Trump administration will take with respect to oil and gas leasing on federal lands cannot be predicted at this time, though any such actions may be subject to litigation. Please refer to Regulation of the Oil and Natural Gas Industry in Part I, Items 1 and 2 of this Annual Report for further discussion of the regulations affecting our operations on federal lands.
Changes in tax laws or regulations or the interpretation thereof or the imposition of new or increased taxes may increase our future tax liabilities, which could adversely affect our business, results of operation, financial condition and cash flows.
From time to time, U.S. federal and state level legislation has been proposed that, if enacted into law, would make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently applicable to natural gas and oil exploration and development companies. It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any such legislation or other changes in U.S. federal or state tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could increase our future tax liabilities, which could adversely affect our business, results of operations, financial condition and cash flows.
Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.
We are subject to laws, regulations and rules enacted by national, regional and local governments and NYSE. In particular, we are required to comply with certain SEC, NYSE and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time, including as a result of new policies and priorities by the Trump administration, and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.
Risks Related to Our Common Stock and Capital Structure
Our cash flow is dependent upon the ability of our operating subsidiaries to make cash distributions to us, the amount of which will depend on various factors.
We are a holding company and have no material assets other than our equity interest in OpCo, and we do not have any independent means of generating revenue. The amount of cash that our operating subsidiaries can distribute each quarter principally depends upon the amount of cash generated from operations, which may fluctuate from quarter to quarter based on, among other things:
• the amount of oil and natural gas our operating subsidiaries produce from existing wells;
• market prices of oil, NGLs and natural gas;
• any restrictions on the payment of distributions contained in covenants in OpCo’s revolving credit facility;
• our operating subsidiaries’ ability to fund their drilling and development plans;
• the levels of investments in each of our operating subsidiaries, which may be limited and disparate;
• the levels of operating expenses, maintenance expenses and general and administrative expenses;
• regulatory action affecting the supply of, or demand for, oil, NGLs and natural gas, and operating costs and operating flexibility;
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• prevailing economic conditions; and
• adverse weather conditions and natural disasters.
To the extent that we need funds and OpCo or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any current or future indebtedness agreements or the Eighth Amended and Restated Limited Liability Company Agreement of OpCo, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.
Moreover, because we have no independent means of generating revenue, our ability to make tax payments and fund our other obligations is dependent on the ability of OpCo to make distributions to us in an amount sufficient to cover our tax and other applicable obligations. This ability, in turn, may depend on the ability of OpCo’s subsidiaries to make distributions to it. The ability of OpCo, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by OpCo or its subsidiaries and other entities in which it directly or indirectly holds an equity interest.
If we experience any material weakness or otherwise fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, stockholders could lose confidence in our financial reporting, which would harm our business and the value of our Class A Common Stock.
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 maintain 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, which includes furnishing a report by management on, among other things, the effectiveness of our internal controls and whether management has identified any material weaknesses therein. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving 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 value of our Class A Common Stock.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
Dividends, whether fixed or variable, and stock repurchases are authorized and determined by our board of directors in its sole discretion and depend upon a number of factors, including the Company’s financial results, cash requirements and future prospects, restrictions in our debt agreements, as well as such other factors deemed relevant by our board of directors. In 2024, our board of directors authorized a stock repurchase program to acquire up to $1 billion of our outstanding common stock, which replaced our previous $500 million stock repurchase program. However, this stock repurchase program may be suspended from ti me to time, modified, extended or discontinued by our board of directors at any time. Similarly, any dividends, whether fixed or variable, we may declare in the future will be determined by our board of directors in its sole discretion. Any elimination of, or downward revision in, our stock repurchase program or dividend policy could have an adverse effect on the market price of our common stock.
Provisions contained in our Charter and Bylaws, as well as provisions of Delaware law, could impair a takeover attempt, which may adversely affect the market price of our common stock.
Our Amended and Restated Certificate of Incorporation (as amended and restated, the “Charter”) and Second Amended and Restated Bylaws (as amended and restated, the “Bylaws”) contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:
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• no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;
• the exclusive right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors;
• the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;
• a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders;
• the requirement that a special meeting of stockholders may be called only by the chairman of the board of directors, the chief executive officers, or the board of directors pursuant to a resolution adopted by a majority of the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;
• limiting the liability of, and providing indemnification to, our directors and officers;
• controlling the procedures for the conduct and scheduling of stockholder meetings;
• providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and
• advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.
These provisions, alone or together, could delayhostile takeovers and changes in control of the Company or changes in our board of directors and management.
As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.
The Charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for substantially all actions and proceedings that may be initiated by stockholders, which could limit shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our Charter provides that, unless we consent in writing to the selection of an alternative forum, the (i) Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (A) any derivative action or proceeding brought on our behalf, (B) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (C) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, the Charter or our Bylaws or (D) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein; and (ii) subject to the foregoing, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act, including all causes of action asserted against any defendant to such complaint. In the event the Delaware Court of Chancery lacks subject matter jurisdiction, then the sole and exclusive forum for such action or proceeding shall be the federal district court for the District of Delaware.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision 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 its business, financial condition, prospects, or results of operations.
efficiently
improving
Market Conditions
Our revenue, profitability and ability to return cash to stockholders can depend substantially on factors beyond our control, such as economic, political and regulatory developments. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.
Concerns regarding global economic growth, elevated interest rates, inflation, increases in global oil supply, tariffs and international trade policies have resulted in lower oil prices over the past year. Despite recent geopolitical tensions and strong global demand, higher than anticipated supply increases from OPEC and their potential impact to global inventories resulted in further downward pressure on prices through the end of 2025.
Throughout 2024 and 2025, natural gas prices in the Permian Basin were negatively impacted by low demand as a result of pipeline capacity constraints out of the basin, pipeline maintenance, and higher production levels. These factors have led to lower or, during certain periods, negative regional gas prices being realized for natural gas sales at the Waha hub in West Texas resulting in lower gas realizations on our production sold at these regional price points.
The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events, federal and state government regulations weather conditions, growth in alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2023:
Crude Oil (per Bbl)
Natural Gas (per MMBtu)
Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement and senior notes. Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to such lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the Credit Agreement.
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Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. The cost of oilfield goods and services are closely linked to commodity price trends, rising when prices increase and decreasing when prices fall. In addition, the U.S. saw higher levels of inflation during 2024 and 2025 due to concerns over international conflicts, tariffs and trade policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.
2025 Highlights and Future Considerations
2025 Bolt-On Acquisitions
On June 16, 2025, we completed an acquisition of approximately 13,000 net leasehold acres with Apache Corporation for an unadjusted purchase price of $608 million. The acreage acquired is predominately located directly offsetting our existing asset position in the core of our New Mexico operating area.
Additionally, during the year ended December 31, 2025, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $471.1 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.
Return of Capital Program
During the year ended December 31, 2025, we declared and paid quarterly base dividends totaling $0.60 per share of Class A Common Stock and distributions totaling $0.60 per share of Class C Common Stock (each of which has an underlying common unit of OpCo (“Common Units”)). The cash dividends and distributions paid totaled $502.9 million for the year ended December 31, 2025.
During the year ended December 31, 2025, we paid a total of $73.7 million to repurchase 4.4 million shares of our Class A Common Stock and 2.0 million Class C Common Stock at a weighted average price of $11.57 per share as part of our Repurchase Program. The shares that were repurchased were subsequently canceled.
Financing
During September 2025, we completed the redemption of all of our outstanding 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”) for a combination of shares of Class A Common Stock and cash (the “Redemption”). The Redemption resulted in the issuance of 30.6 million shares of our Class A Common Stock at a 179.9208 conversion rate per $1,000 principal amount of the Convertible Senior Notes as well as a cash payment of $0.1 million.
During June 2025, we repurchased $2.7 million of our senior notes due 2026 (the “2026 Senior Notes”) at a price equal to 99.7% of the principal amount paid plus accrued and unpaid interest up to, but excluding, the repurchase date. Subsequently, during September 2025, we redeemed all remaining 2026 Senior Notes at a price equal to 100% of the aggregate principal amount outstanding of $286.7 million plus accrued and unpaid interest up to, but excluding, the redemption date.
During January 2025, we redeemed $175 million of our senior notes due 2031 (the “2031 Senior Notes”) at a redemption price equal to 109.875% of the aggregate principal amount redeemed plus accrued and unpaid interest up to, but excluding, the redemption date. Following the redemption, the remaining aggregate principal amount of the 2031 Senior Notes outstanding was $325 million.
Corporation Reorganization
On January 7, 2026, we completed a corporate reorganization pursuant to which we, among other things, reorganized under a new public holding company (the “Reorganization”). In connection with the Reorganization, the public holding company prior to the Reorganization became a wholly owned subsidiary of the new public holding company, which, following completion of the Reorganization, changed its name to “Permian Resources Corporation,” became the successor issuer of the prior public holding company and replaced the prior public holding company, with its shares of Class A Common Stock continuing to trade on the NYSE on an uninterrupted basis.
In connection with the Reorganization, certain holders of our Class C Common Stock exchanged all of their Common Units for Class A Common Stock on a one-for-one basis (and their corresponding shares of Class C Common Stock were cancelled for no consideration). This resulted in approximately 35.5 million shares of Class C Common Stock remaining outstanding, reducing the noncontrolling interest ownership of OpCo to approximately 4% immediately following the Reorganization. Refer to Note 16—Subsequent Events under Part II, Item 8 of this Annual Report for additional information on the Reorganization that occurred after the reporting period.
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Results of Operations
For the Year Ended December 31, 2025 Compared to the Year Ended December 31, 2024
The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:
Year Ended December 31,
Increase/(Decrease)
Net revenues (in thousands):
Oil sales
NGL sales
Natural gas sales
Purchased gas sales, net
Oil and gas sales
Net production:
Oil (MBbls)
NGL (MBbls)
Natural gas (MMcf)
Total (MBoe) (3)
Average daily net production:
Oil (Bbls/d)
NGL (Bbls/d)
Natural gas (Mcf/d)
Total (Boe/d) (3)
Average sales prices:
Oil (per Bbl)
Effect of derivative settlements on average price (per Bbl)
Oil including the effects of hedging (per Bbl)
NGL (per Bbl)
Natural gas (per Mcf)
Effect of derivative settlements on average price (per Mcf)
Effect of purchased gas sales on average price (per Mcf)
Natural gas including the effects of hedging (per Mcf)
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Oil, NGL and Natural Gas Sales Revenues . Total net revenues for the year ended December 31, 2025 increased by $64.5 million, or 1%, compared to the year ended December 31, 2024. Revenues are a function of oil, NGL and natural gas volumes sold and average commodity prices realized.
Net production volumes for oil, NGLs and natural gas increased 14%, 17% and 12%, respectively, between periods. The increase in oil production resulted from additional production added from wells placed online or acquired since the fourth quarter of 2024. These oil volume increases were partially offset by normal production declines across our existing wells. NGLs and natural gas are produced concurrently with our crude oil volumes, which typically result in a high correlation between fluctuations in oil quantities sold and NGL and natural gas quantities sold, driving the respective 17% and 12% increases in NGL and gas volumes, respectively, between periods.
Total net revenues increases were also driven by higher average realized sales prices of natural gas for the year ended December 31, 2025 compared to the same 2024 period. This increase was the result of higher regional and national average index gas prices between periods.
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These increases were partially offset by lower average realized sale prices for oil and NGLs, which decreased 14% and 12%, respectively, for the year ended December 31, 2025 compared to the same 2024 period. The 14% decrease in the average realized oil price was mainly the result of lower NYMEX crude prices between periods. The 12% decrease in the average realized NGL price between periods was primarily attributable to lower Mont Belvieu spot prices for plant products for the year ended December 31, 2025 compared to the same 2024 period.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
Year Ended December 31,
Increase/(Decrease)
Change
Operating costs (in thousands):
Lease operating expenses
Severance and ad valorem taxes
Gathering, processing, and transportation expense
Operating cost metrics:
Lease operating expenses (per Boe)
Severance and ad valorem taxes (% of revenue)
Gathering, processing, and transportation expense (per Boe)
Lease Operating Expenses. Lease operating expenses (“LOE”) per Boe for the year ended December 31, 2025 was $5.26, which represents a 3% decrease compared to the same 2024 period. This decrease in our LOE per Boe rate was primarily driven by lower water disposal rates and wellhead chemicals that resulted from operational efficiencies. While LOE per Boe decreased period over period, total LOE for the year ended December 31, 2025 increased by $67.9 million compared to the year ended December 31, 2024 and was the direct result of our higher well count between periods primarily due to additional wells placed on production or acquired since December 31, 2024.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year ended December 31, 2025 increased $12.5 million compared to the year ended December 31, 2024. Severance taxes are based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. The increase in severance and ad valorem tax expense for the year ended 2025 compared to the same 2024 period is due to an increase in severance taxes and is primarily related to higher NGL and natural gas revenues between periods.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) on a per Boe basis decreased from $1.46 for the year ended December 31, 2024 to $1.40 per Boe for the year ended December 31, 2025. This decrease in rate was mainly attributable to lower GP&T rates based on the location of new wells placed on production since the fourth quarter of 2024. While our GP&T per Boe was lower period versus period, total GP&T for the year ended December 31, 2025 increased $16.5 million compared to the year ended December 31, 2024. This increase in expense was mainly attributable to higher NGL and natural gas volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and gathering costs being incurred.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated:
Year Ended December 31,
(in thousands, except per Boe data)
Depreciation, depletion and amortization
Depreciation, depletion and amortization per Boe
For the year ended December 31, 2025, DD&A expense amounted to $2.0 billion, an increase of $255.8 million from 2024. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods, which increased DD&A expense by $248.4 million period over period, while marginally higher DD&A rates between periods increased DD&A expense by $7.4 million.
DD&A per Boe was $14.18 for the year ended December 31, 2025 compared to $14.13 for the same period in 2024. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.
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General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
Year Ended December 31,
(in thousands, except per Boe data)
Cash general and administrative expenses
Stock-based compensation expense
General and administrative expenses
Cash general and administrative expenses per Boe
G&A expenses for the year ended December 31, 2025 were $186.5 million compared to $174.6 million for the year ended December 31, 2024. Stock-based compensation increased $8.7 million primarily related to additional grants of performance stock units and restricted stock since the fourth quarter of 2024. This was partially offset by less expenses associated with accelerated vestings of equity awards that occurred during the year ended of December 31, 2024 that did not reoccur during the same 2025 period. Cash G&A was $3.1 million higher between periods mainly related to increased employee expenses and consulting and professional services related to our increased headcount and overall corporate growth.
While cash G&A increased between periods, on a per Boe basis our cash G&A rate decreased 11% from $0.93 per Boe during the year ended December 31, 2024 to $0.83 per Boe during the year ended December 31, 2025. This per Boe rate decrease was the result of focus on controlling costs and growing production.
Other Income and Expense.
Interest Expense. The following table summarizes interest expense for the periods indicated:
Year Ended December 31,
(in thousands)
Credit Facility
5.375% Senior Notes due 2026
7.75% Senior Notes due 2026
6.875% Senior Notes due 2027
8.00% Senior Notes due 2027
3.25% Convertible Senior Notes due 2028
5.875% Senior Notes due 2029
9.875% Senior Notes due 2031
7.00% Senior Notes due 2032
6.25% Senior Notes due 2033
Amortization of debt issuance costs, debt discount and debt premium
Other interest expense
Total
Interest expense was $13.1 million lower for the year ended December 31, 2025 compared to the year ended December 31, 2024 mainly due to (i) $45.1 million less interest incurred between periods due to various redemptions and repurchases of our senior notes during the 2024 and 2025 periods (refer to Note 5—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding these transactions); and (ii) less interest expense incurred on our credit facility due to lower weighted average borrowings outstanding during the 2025 period. These decreases were partially offset by $37.2 million in additional interest incurred on our 6.25% Senior Notes due 2033 that were issued in July 2024.
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Loss on extinguishment of debt. The loss on extinguishment of debt incurred during the year ended December 31, 2025 of $270.1 million was primarily related to the Redemption of our Convertible Senior Notes. This loss was determined based on the difference in the value of our Class A Common Stock issued and cash paid for the Redemption and the carrying amount of the Convertible Senior Notes less professional fees incurred in connection with the Redemption. The 2025 loss was greater than prior debt redemption losses as the Convertible Notes were redeemed mainly by issuing Class A Common Stock, which has risen significantly in value since the Convertible Senior Notes were issued in 2021. Refer to Note 5—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding the redemption.
During the year ended December 31, 2024, we recognized $8.6 million of loss on extinguishment of debt related to the redemptions of our 7.75% senior notes due 2026 and 6.875% senior notes due 2027.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:
Year Ended December 31,
(in thousands)
Realized cash settlement gains (losses)
Non-cash mark-to-market derivative gain (loss)
Total
Income Tax Expense: The following table summarizes our pre-tax income and income tax expense for the periods indicated:
Year Ended December 31,
(in thousands)
Income before income taxes
Income tax expense
For the year ended December 31, 2025 we generated pre-tax net income of $1.4 billion and recorded income tax expense of $284.2 million. Our provision for income tax expense for the year ended December 31, 2025 was less than the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income primarily due to (i) the portion of pre-tax net income that is attributable to our noncontrolling interest partners that is not taxable to the Company; and (ii) general business tax credits generated during the year. These decreases were partially offset by an increase in our unrecognized tax benefit recognized during the year ended December 31, 2025.
For the year ended December 31, 2024, we generated pre-tax net income of $1.6 billion and recorded income tax expense of $300.3 million. The primary factor decreasing our 2024 tax expense below the statutory U.S. federal income tax rate was the portion of pre-tax income that was attributable to our noncontrolling interest partners and not taxable to the Company.
For the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2024 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023.
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Liquidity and Capital Resources
Overview
Our primary sources of liquidity have been cash flows from operations, borrowings under our revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for drilling and development activity during the year ended December 31, 2025 were $1.97 billion. We expect our total drilling, completion and facilities capital expenditures budget for 2026 to be between $1.75 billion to $1.95 billion. We funded our capital expenditures for 2025 entirely from cash flows from operations, and we expect to fund our 2026 capital expenditures budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place.
We are the operator of a high percentage of our acreage and can control the amount and timing of our capital expenditures. Accordingly, we can choose to defer or accelerate a portion of our planned capital expenditures depending on a variety of factors, including but not limited to: (i) prevailing and anticipated prices for oil and natural gas; (ii) oil and gas storage or transportation constraints; (iii) the success of our drilling activities; (iv) the availability of necessary equipment, infrastructure and capital; (v) the receipt and timing of required regulatory permits and approvals; (vi) seasonal conditions; (vii) property or land acquisition costs; and (viii) the level of participation by other working interest owners.
We plan to return capital to shareholders primarily through our base dividend, in addition to opportunistic share repurchases. During the year ended December 31, 2025, we declared and paid quarterly base dividends totaling $0.60 per share of Class A Common Stock and distributions totaling $0.60 per share of Class C Common Stock (each of which has an underlying Common Unit of OpCo). The cash dividends and distributions paid to common unitholders totaled $502.9 million for the year ended December 31, 2025. Additionally, we repurchased 4.4 million shares of Class A Common Stock for $46.8 million and 2.0 million shares of Class C Common Stock for $26.9 million under our Repurchase Program during the year ended December 31, 2025.
Our Repurchase Program can be used to reduce our shares of common stock outstanding. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt agreements and other factors.
In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise. During the year ended December 31, 2025, we (i) redeemed an aggregate principal amount of $175 million of our 2031 Senior Notes at a price equal to 109.875% of the aggregate principal amount; (ii) repurchased and redeemed an aggregate principal amount of $289.4 million of our 2026 Senior Notes; and (iii) redeemed the aggregate principal amount of $170 million of our Convertible Senior Notes for 30.6 million shares of our Class A Common Stock at a conversion rate of 179.9208 shares per $1,000 principal amount of Convertible Senior Notes as well as a cash payment of $0.1 million.
Although we cannot provide any assurance that cash flows from operations or other sources of needed capital will be available to us at acceptable terms, or at all, and noting that our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control, we believe that based on our current expectations and projections, we will have sufficient capital available to fund our capital expenditure requirements through the 12-month period following the filing of this Annual Report and the long-term.
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
Year Ended December 31,
(in thousands)
Net cash provided by operating activities
Net cash used in investing activities
Net cash (used in) provided by financing activities
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Cash Flows from 2025 Compared to 2024. For the year ended December 31, 2025, we generated $3.6 billion of cash from operating activities, an increase of $195.6 million from 2024. Cash provided by operating activities increased primarily due to (i) higher production volumes, realized derivative gains and realized prices for gas, (ii) lower merger and integration and interest expense, and (iii) the timing of payments to our suppliers for the year ended December 31, 2025 as compared to the same 2024 period. These increasing factors were partially offset by lower realized prices for oil and NGLs, higher costs including lease operating expenses, GP&T expense, severance and ad valorem taxes and cash G&A as well as the timing of our receivable collections for the year ended December 31, 2025 as compared to the same 2024 period. Refer to Results of Operations for more information on the impact of volumes and prices on revenues and on fluctuations in our operating expenses between periods.
For the year ended December 31, 2025, cash flows from operating activities, cash on hand and proceeds of $176.7 million primarily from the sale of oil and natural gas gathering systems that were acquired during a prior year acquisition were used to (i) fund $1.97 billion of drilling and development cash expenditures; (ii) fund acquisitions of oil and gas properties of approximately $1.1 billion; (iii) pay $502.9 million in dividends and cash distributions to shareholders and holders of our Common Units; (iv) redeem $464.5 million of our senior notes; and (v) repurchase $73.7 million of our Class A and C Common Stock.
Cash Flows from 2024 Compared to 2023. For the year ended December 31, 2024, we generated $3.4 billion of cash from operating activities, an increase of $1.2 billion from 2023. Cash provided by operating activities increased primarily due to higher production volumes and lower merger and integration expense for the year ended December 31, 2024 as compared to the same 2023 period. These increasing factors were partially offset by lower realized prices for oil and natural gas, higher costs including lease operating expenses, severance and ad valorem taxes, interest expense, GP&T expense, and cash G&A as well as the timing of our receivable collections for the year ended December 31, 2024 as compared to the same 2023 period.
For the year ended December 31, 2024, cash flows from operating activities, proceeds from the issuance of our 6.25% Senior Notes due 2033 and proceeds from an underwritten public offering of 26.5 million Class A Common Stock were used to: (i) fund $2.1 billion of drilling and development cash capital expenditures; (ii) fund acquisitions of oil and gas properties of approximately $1.0 billion; (iii) redeem $656.4 million of our senior notes; (iv) pay $560.9 million in dividends and cash distributions to our shareholders and holders of our Common Units; and (v) repurchase $61.0 million of our Class C Common Stock.
Credit Agreement
OpCo, our consolidated subsidiary, has a secured revolving Credit Agreement with a syndicate of banks maturing in February 2028 that, as of December 31, 2025, had a borrowing base of $4.0 billion and elected commitments of $2.5 billion. As of December 31, 2025, we had no borrowings outstanding and $2.5 billion in available borrowing capacity. The elected commitments and borrowing base were reaffirmed during the spring and fall 2025 borrowing base redeterminations.
The Credit Agreement contains restrictive covenants that limit our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
The Credit Agreement also requires OpCo to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of OpCo’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, which is the ratio of total funded debt to consolidated EBITDAX (with such terms defined within the Credit Agreement) for the most recent quarter annualized, of not greater than 3.5 to 1.0.
The Credit Agreement includes fall away covenants, lower interest rates and reduced collateral requirements that OpCo may elect if OpCo is assigned an Investment Grade Rating (as defined within the Credit Agreement). OpCo was in compliance with the covenants and financial ratios under the Credit Agreement described above through the filing of this Annual Report. For further information on the Credit Agreement, refer to Note 5—Long-Term Debt under Item 8 of this Annual Report.
Senior Notes
OpCo has $3.5 billion in debt outstanding as of December 31, 2025 , consisting of senior unsecured notes with maturity dates ranging from 2027 to 2033. For further information on our Senior Unsecured Notes, refer to Note 5—Long-Term Debt under Part II, Item 8 of this Annual Report.
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Obligations and Commitments
We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, among others, in the ordinary course of business. The following table summarizes our obligations and commitments as of December 31, 2025, to make future payments under long-term contracts for the time periods specified below.
(in thousands)
Thereafter
Total
Operating leases (1)
Finance leases (2)
Purchase obligations (3)
Firm transportation (4)
Development obligation (5)
Asset retirement obligations (6)
Long term debt obligations (7)
Cash interest expense on long-term debt obligations (8)
Total
(1) Operating leases consist of our office rental agreements, drilling rig contracts and other wellhead equipment. Please refer to Note 15—Leases under Part II, Item 8 of this Annual Report for details on our operating lease commitments.
(2) Finance leases consist of our ground lease related to the office building we purchased in Midland, Texas. The lease term is ninety-nine years and as a result, the commitments above have been shown at their current present value. Please refer to Note 15—Leases under Part II, Item 8 of this Annual Report for details on our finance lease commitments.
(3) Consists of energy purchase agreements to buy a minimum amount of electricity at a fixed price or pay for underutilization as well as a take-or-pay agreement to purchase a minimum volume of frac sand at a fixed price. The obligations reported above represent our remaining minimum financial commitments pursuant to the terms of these contracts as of December 31, 2025, however actual expenditures may exceed the minimum commitments presented above. Please refer to Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report for details on these agreements.
(4) Consists of firm transportation commitment agreements that guarantee volumetric capacity on pipelines for gas transportation. Please refer to Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report for details on these agreements.
(5) Consists of obligations that are tied to our future drilling, completion and water connection activity in Reeves County, Texas that will require repayment if certain performance obligations through September 2026 are not met.
(6) Asset retirement obligations reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells and the related land restoration in accordance with applicable laws and regulations.
(7) Long-term debt consists of the principal amounts of our senior notes due as of December 31, 2025.
(8) Cash interest expense on our senior notes is estimated assuming no principal repayment until the maturity of the instruments. Cash interest expense on the Credit Agreement includes unused commitment fees and assumes no additional principal borrowings, repayments or changes to commitments under the agreement through the instrument due date.
Recently Issued Accounting Standards
Refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies , in Part II, Item 8. Financial Statements and Supplementary Data in this annual report for a discussion of recently issued accounting standards and their anticipated effect on our business.
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Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as, the disclosure of contingent assets, contingent liabilities and commitments as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, commodity prices, production performance, drilling results, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies can be found in Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Item 8 of this Annual Report.
We have outlined certain of our accounting policies below which require the application of significant judgment by our management.
Oil and Natural Gas Reserve Quantities
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil, NGL and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are used as inputs to our calculation of depletion, evaluation of proved properties for impairment, assessment of the expected realizability of our deferred income tax assets, and the standardized measure of discounted future net cash flows computations.
The process of estimating quantities of proved reserves is inherently imprecise and relies on the following: i) interpretations and judgment of available geological, geophysical, engineering and production data; ii) certain economic assumptions, some of which are mandated by the SEC, such as commodity prices; and iii) assumptions and estimates of underlying inputs such as operating expenses, capital expenditures, plug and abandonment costs and taxes. All of these assumptions may differ substantially from actual results, which could result in a significant change in our estimated quantities of proved reserves and their future net cash flows. We continually make revisions to reserve estimates throughout the year as additional information becomes available, and we make changes to depletion rates in the same reporting period that changes to reserve estimates are made.
Business Combinations
From time to time, we may complete acquisitions that are accounted for as business combinations that require us to recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, forecasted development costs, pricing and cash flows, discount rates, expectations regarding customer contracts and relationships, reserve risk adjustment factors and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition. See Note 2—Business Combinations in Item 8 of this Annual Report on Form 10-K.
Impairment of Oil and Natural Gas Properties
We assess our proved properties for impairment when events or changes in circumstances indicate that the carrying value of such proved property assets may not be recoverable. For purposes of an impairment evaluation, our proved oil and natural gas properties must be grouped at the lowest level for which independent cash flows can be identified. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to its estimated fair value. Fair value for the purpose of measuring impairment write-downs are calculated using the present value of expected future cash flows that are estimated to be generated from the asset group. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment write-down is being measured. However, such future cash flow estimates are based on numerous assumptions that can materially affect our estimates, and such assumptions are subject to change with variations in commodity prices, production performance, drilling results, operating and development costs, underlying oil and gas reserve quantities, and other internal or external factors.
Unproved properties consist of the costs we incur to acquire undeveloped leasehold acreage and unproved reserves. Unproved properties are periodically assessed for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Changes in our assessment or these factors could result in additional impairment charges of our undeveloped leases.
