NYSE: LB

The Delaware Basin is characterized by the abundant remaining oil and natural gas resources and low break-even cost of development. Activity in the Delaware Basin is dominated by large, generally publicly-listed, well-capitalized producers. Our land is located predominantly in the heart of the Delaware Basin, along and near the regulatory divide of the Texas-New Mexico state border. This area represents some of the most productive acreage in the Delaware Basin, with a high concentration of hydrocarbons and elevated levels of drilling and completion activity. We believe that our strategic location positions us to capture additional revenues from the growth in infrastructure required to facilitate the development of these resources.

We share a financial sponsor, Five Point, and our management team with WaterBridge. WaterBridge is one of the largest water midstream companies in the United States and operates a large-scale network of pipelines and other infrastructure in the Delaware Basin that, as of December 31, 2025, handles approximately 2.5 million bpd of water associated with oil and natural gas production, with approximately 4.2 million bpd of total handling capacity. These relationships provide our shared management team visibility into key areas of oil and natural gas production and long-term trends, which we leverage to encourage and support the development of critical infrastructure on our land and generate additional revenue for us. Since we acquired our initial acreage, WaterBridge has constructed or acquired, as of December 31, 2025, approximately 1.5 million bpd of water handling capacity on our land, with approximately 3.2 million bpd of permitted capacity available for future development on our land. We receive royalties for each barrel of produced water that WaterBridge handles on our land as well as surface use payments for infrastructure constructed on our land.

Five Point and our management team formed LandBridge to acquire, manage and expand a strategic land position in the heart of the Delaware Basin to support the development of WaterBridge’s large-scale produced water handling infrastructure and to actively manage our land and resources to support and encourage broader industrial and commercial development. Since our formation, our management and Five Point have successfully started and expanded businesses that generate new and growing sources of revenue for us by capturing and monetizing commercial activity both on and near our land. Examples of the benefits of these relationships include WaterBridge’s strategic relationship with Devon Energy, which supports the development of significant additional infrastructure on and around our land. We believe that WaterBridge’s future growth will continue to underpin increased revenues for us, into which we have significant visibility and that requires minimal investment by us. Additionally, WaterBridge operates non-hazardous oilfield reclamation and solid waste facilities that are located on our land.

In addition to our relationship with WaterBridge, we have actively grown third-party revenues. We utilize a collaborative commercial approach with a diversified customer base to provide availability, timing and consistent terms for our customers’ development activities on our land. As a landowner, we benefit from these activities by charging fees and royalties based on our customers’ usage of our land and resources. Furthermore, the cost of development on our land is primarily borne by our customers, allowing us to benefit from their growth on our land while deploying minimal capital of our own. In furtherance of our strategy, we and WaterBridge entered into agreements with Texas Pacific Land Corporation (“TPL”), one of the largest landowners in Texas, to provide reciprocal crossing rights and produced water royalty and revenue sharing across an area of mutual interest that provides our customers (including WaterBridge) with greater development efficiency and enables them to increase their operations on our land. Please see “Business—Our Assets—Our Stateline Position” for more information related to our agreements with TPL.

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We generate multiple revenue streams from the use of our surface acreage, the sale of resources from our land and oil and gas royalties.

•
Surface Use Royalties and Revenues: We receive fees from our customers for the use of our surface acreage for their business operations, which currently include oil and natural gas development, produced water transportation and handling, pipeline and electrical infrastructure, digital infrastructure, a commercial fuel distribution facility and other commercial and industrial activities, including non-hazardous oilfield reclamation and solid waste facilities.

•
Resource Sales and Royalties: We receive fees from the sale of resources from our land, including sales of brackish water and caliche primarily utilized in connection with oil and natural gas well development, and royalties from sand and brackish water extracted from our land primarily utilized for oil and natural gas well completions. These resources are used by our customers in their projects on and around our land and elsewhere throughout the Delaware Basin.

•
Oil and Gas Royalties: We receive a share of recurring revenues from the production of oil and natural gas on our approximate 4,400 gross mineral acres through our ownership of mineral interests, of which approximately 96% underlie our surface acreage. Other than our gross mineral acres, we do not own the mineral interests that underlie our surface acreage.

A key attribute of our business model is entering into agreements under which our customers bear substantially all of the operating and capital expenditures related to their operations on our land, with minimal capital requirements of our own for both current and future commercial opportunities, resulting in the ability to create significant Free Cash Flow. The following table summarizes our financial performance for the periods shown:

Year Ended December 31,

2025

2024

2023

(in thousands)

Total revenues

$

199,093

$

109,954

$

72,865

Net income (loss) (1)

$

72,399

$

(41,479

)

$

63,172

Adjusted EBITDA (2)

$

177,171

$

97,069

$

62,804

Cash flows from operating activities

$

126,273

$

67,636

$

53,042

Capital expenditures

$

(4,236

)

$

(985

)

$

(2,783

)

Free Cash Flow (2)

$

122,037

$

66,651

$

50,259

(1) Net income for the year ended December 31, 2025, includes non-cash share-based compensation expense of $45.3 million, of which $8.8 million is attributable to RSUs issued by the Company and $36.5 million is attributable to LBH Incentive Units. Net loss for the year ended December 31, 2024, includes non-cash share-based compensation expense of $95.3 million, of which $4.0 million is attributable to RSUs issued by the Company, $72.6 million is attributable to NDB Incentive Units and $18.7 million is attributable to LBH Incentive Units. Net income for the year ended December 31, 2023 includes non-cash share-based compensation income of $17.2 million attributable to the NDB Incentive Units. Any actual cash expense associated with the LBH Incentive Units is borne solely by LandBridge Holdings and not the Company. Distributions attributable to LBH Incentive Units are based on returns received by investors of LandBridge Holdings once certain return thresholds have been met and are neither an obligation of the Company nor taken into consideration for distributions to investors in the Company.

(2) Adjusted EBITDA and Free Cash Flow are non-GAAP financial measures. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Non-GAAP Financial Measures” for more information regarding these non-GAAP measures and reconciliations to the most comparable GAAP measures.

Active Land Management

We actively manage the commercial development of our land, seeking to maximize the long-term value of our surface acreage and our resources by identifying and developing, or supporting the development of, new uses and revenues from our land. Unlike landowners focused primarily on agricultural or livestock operations, we proactively promote our land as a location for commercial and industrial uses, and we offer our customers an efficient contracting process that provides a holistic solution to their operational needs.

We target opportunities that make the most efficient use of our surface acreage, allow the same surface acreage to be used for multiple activities and/or improve the value of the surrounding acreage. We have entered into, or are currently pursuing, primarily long-term commercial relationships with businesses focused on oil and gas development, solar power generation, microgrids, power storage, cryptocurrency mining and data management, as well as other renewable energy production, among other industries and applications. Similar to the other operations conducted on our land, we expect to enter into surface use or similar agreements with the owners of these projects from which we expect to receive surface use fees and other payments in connection with the utilization of our land, but we do not expect to own or operate such projects or expect to incur significant capital expenditures in connection therewith.

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We measure our revenue divided by our acreage as a performance metric, which we refer to as “surface use economic efficiency.” The surface use economic efficiency metric for the years ended December 31, 2025 and 2024 are shown in the following table:

Total

Weighted average acreage (2)

Surface use economic efficiency (3) (4)

Variance

acreage (1)

2025

2024

2025

2024

Percent

(in thousands)

Legacy acreage

72,000

72,000

72,000

$

1,159

$

1,018

14

%

2024 Acquisitions

203,000

203,000

101,008

$

499

$

204

145

%

2025 Acquisitions

42,000

8,479

-

$

208

$

-

- %

Total

317,000

283,479

173,008

$

658

$

543

21

%

(1)
Total acreage is rounded and reflects fee surface acres, together with leasehold acres and acreage subject to a long-term management agreement.

(2)
In the year of acquisition, weighted average surface acreage is calculated for the period of ownership during the year of acquisition to align with the revenues earned during the period of ownership in that year.

(3)
Surface use economic efficiency is calculated as “Total revenues” less “Oil and gas royalties” from our consolidated statements of operations divided by the weighed average surface acres owned during the period.

(4)
May not sum or recalculate due to rounding.

The increase in our surface use economic efficiency reflects the application of our active land management strategy, including the optimization and expansion of commercial and surface use agreements.

Land and Produced Water Relationship

Produced water naturally exists in underground formations and is brought to the surface during crude oil and natural gas production throughout the entire life of an oil or natural gas well. Produced water must be reliably separated and handled in order for these wells to be brought online and remain in production. The gathering, treating, handling and recycling of produced water requires both access to significant surface acreage for operations and subsurface reservoirs that are porous, uniform and stable where produced water can be injected and sequestered.

Access to significant surface acreage and subsurface reservoirs for produced water handling is of particular importance to operators in the Delaware Basin, as the Delaware Basin has experienced significant growth in oil and natural gas production activity over the last three years with a resultant increase in produced water volumes. We believe that this growth in oil and natural gas production activity will require increased produced water handling capacity, as the amount of produced water produced from wells in the Delaware Basin significantly exceeds the amount of the related oil and natural gas production.

Produced water handling facilities and their access to specific geologic zones are regulated at the state level and are required to meet guidelines imposed by the relevant state agencies. Because the Delaware Basin straddles the Texas-New Mexico state border, the planning, permitting and building of produced water infrastructure is dependent upon the laws and regulations of either Texas or New Mexico.

In contrast to New Mexico, Texas generally provides a more favorable regulatory environment for produced water permitting. The combination of favorable geological characteristics and a comparatively less restrictive regulatory environment drives increased demand for produced water handling facilities on the Texas side of the Texas-New Mexico state border. Our Stateline and Northern Positions benefit from the demand for surface acreage and pore space in Texas that is driven by the regulatory divide between Texas and New Mexico and the level of oil and gas activity in the Northern Delaware Basin. Please see “—Our Assets—Our Stateline Position” and “— Our Assets—Our Northern Position” for more information.

New Mexico also presents a more restrictive regulatory and hydrological environment for sourcing brackish water used for oil and natural gas well completion activity. As a result, much of the brackish water supplied to the oil and natural gas industry in New Mexico is sourced from Texas. Our Stateline and Northern Positions contain significant underground brackish water resources from which brackish water can be produced for sale to companies that deliver this water to E&P companies in New Mexico for use in their drilling and completion activities.

We believe that expected future growth of produced water volumes in the Delaware Basin will require incremental pore space to ensure proper handling. We also believe that our large land position strategically located at the intersection of significant producer activity and access to largely underutilized pore space offers critical capacity for produced water disposal, along with our management team’s extensive experience in the produced water industry, uniquely positions us to provide producers and produced water companies with access to our land and pore space to establish large-scale, reliable produced water handling solutions, from which we will generate multiple revenue streams, including the sale of resources from our land and produced water handling royalties.

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Our Assets

We own or manage more than 315,000 surface acres in and around the Delaware Basin in Texas and New Mexico, the most active oil and natural gas development and production region of the United States, as of December 31, 2025. Our surface acreage is located across three separate areas, which we refer to as our Stateline, Northern and Southern Positions. Our land positions are shown below.

Overview of our Land Position

Our Stateline Position

Our Stateline Position consists of approximately 169,000 surface acres located primarily in Loving, Reeves and Winkler Counties, Texas, and Lea County, New Mexico, near and along the Texas-New Mexico state border, as of December 31, 2025. Our Stateline Position comprises a significant and large land position and geological formations that are generally characterized by high permeability and porosity, that we believe will enable reliable water handling. There are substantial hydrocarbon resources under and in close proximity to our Stateline Position, which attracts high-quality, well-capitalized producers, including Devon Energy, EOG Resources, ConocoPhillips, Continental Resources, Admiral Permian and Occidental Petroleum. We believe that our geographic proximity to the operations of large, well-capitalized producers positions us to benefit from anticipated growth in oil and natural gas development on and around our land.

The western portion of our Stateline Position is semi-contiguous, or checkerboarded, with surface acreage held by TPL, one of the largest landowners in Texas. The nature of the checkerboarded acreage results in E&P companies, midstream companies, service companies and other operators in the area generally needing to access both our and TPL’s surface acreage for rights of way. In order to unlock opportunities for the checkerboarded surface acreage, we, together with WaterBridge, entered into agreements with TPL that established an approximate 64,000 acre area of mutual interest (the “Stateline AMI”) across much of the western portion of our Stateline Position and the adjacent TPL surface acreage. These agreements provide reciprocal crossing rights as well as royalty and revenue sharing across the Stateline AMI, and provides our customers, including WaterBridge, the certainty necessary to develop

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large scale infrastructure assets on and around such land. Please see “—Our Assets—Our Stateline Position” for more information related to our agreements with TPL.

As of December 31, 2025, WaterBridge and third party operators collectively operated approximately 1.9 million bpd of existing produced water handling capacity on our Stateline Position. We believe that the pore space underlying our Stateline Position will be able to support approximately 3.2 million bpd of additional produced water handling capacity, assuming approximately 27,000 bpd produced water handling permits on average and approximately one kilometer of spacing between all future produced water handling facilities.

The eastern portion of our Stateline Position includes approximately 116,000 surface acres in Winkler and Loving counties, Texas and Lea County, New Mexico, as of December 31, 2025. WaterBridge operates produced water handling infrastructure and a brackish water supply system that serves producers active on the East Stateline Ranch, including ConocoPhillips, Continental Resources, Devon Energy and Occidental Petroleum. These producers are subject to SUAs that govern commercial activities on the East Stateline Ranch. In addition, we believe that the East Stateline Ranch contains substantial sand resources, which we expect to support additional sand mine developments over time and generate surface use revenue for us in connection with the utilization of our land.

Although oil and natural gas production and related services account for a large majority of the activity in our Stateline Position, we anticipate there will be opportunities with developers seeking to build data centers, cryptocurrency mining facilities, power generation facilities, microgrids and power storage facilities and commercial fueling stations across our Stateline Position.

Our Northern Position

Our Northern Position, which includes land positions in Eddy and Lea counties, New Mexico and Andrews County, Texas, consists of approximately 61,000 fee-owned surface acres and 33,000 additional surface acres leased from the BLM and the State of New Mexico on a year-to-year basis as of December 31, 2025.

Our Northern Position supports much needed water infrastructure development to serve oil and natural gas development in the northern part of the Delaware Basin. We believe that there is a need for produced water systems serving central and northern Lea and Eddy counties to transport produced water east out of the Delaware Basin. The Speed and Lea County Ranches within our Northern Position provide critical access to pore space that we believe will be able to handle significant produced water volumes.

As of December 31, 2025, WaterBridge and third party operators collectively operated approximately 158,000 bpd of existing produced water handling capacity on our Northern Position. We believe that the pore space underlying our Northern Position will be able to support approximately 1.4 million bpd of additional produced water handling capacity, assuming approximately 32,000 bpd produced water handling permits on average and one kilometer of spacing between all future produced water handling facilities.

Our Southern Position

Our Southern Position consists of approximately 87,000 surface acres located in Reeves, Ward and Pecos counties, Texas in the Delaware Basin as of December 31, 2025. Various producers have operations on or in the vicinity of our Southern Position, including Crescent Energy, VTX Energy, APA Corporation, Permian Resources and Diamondback Energy, and we generate revenues from their use of our Southern Position acreage and its resources.

In December 2024, we closed the Wolf Bone Acquisition, pursuant to which we acquired approximately 46,000 largely contiguous surface acres in the Southern Delaware Basin known as the Wolf Bone Ranch. Located adjacent to our existing surface acreage in Reeves County, Texas, the Wolf Bone Ranch is well-positioned at a strategic intersection of oil and natural gas exploration and transportation, with access to the Waha Gas market hub. The land also supports produced water operations, with current volumes of approximately 300,000 bpd serviced by infrastructure owned and operated by VTX Energy, as well as assets owned and managed by WaterBridge.

As of December 31, 2025, WaterBridge and third party operators collectively operated approximately 783,000 bpd of existing produced water handling capacity on our Southern Position.

In addition, we continually seek to identify and pursue opportunities with a broad array of customers, including new, distinct operations on our Southern Position. For example, in September of 2025, we sold a 3,000-acre solar energy generation project in Reeves County, Texas, to a leading, publicly-traded energy infrastructure developer. In connection with the transaction, we received an up-front cash payment and the right to receive contingent future cash payments based on the achievement of certain developmental milestones. The solar project has a proposed generation capacity of 250 MW. In addition, our Southern Position is adjacent to the I-10 interstate highway corridor, the fourth longest interstate highway system in the country, as well as I-20, which, each individually and

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collectively, serve as corridors for vehicle traffic and for pipeline and electrical infrastructure, representing additional development opportunities for this surface acreage.

Our Mineral Interests

We own approximately 4,400 gross mineral acres in the Delaware Basin with a weighted average lease royalty percentage based on acreage of 23.9% and an average proved developed producing net revenue interest per well of 4.2%, as of December 31, 2025. Our mineral interests are leased to some of the top operators in the Delaware Basin, including APA Corporation, Chevron, ConocoPhillips and Occidental Petroleum. Our leases with these and other E&P companies permit the lessee to explore for and produce oil, natural gas and NGLs from our land and entitle us to receive an upfront cash payment, or lease bonus, and a percentage of the proceeds from the sales of these commodities in the form of an oil and gas royalty interest.

Unlike businesses that focus on buying oil and gas royalty interests, which are more directly exposed to commodity prices, our focus is on surface acreage ownership and the associated fee-based revenue. As a result, we expect to acquire additional mineral interests only incidentally in connection with property acquired primarily for other purposes and, consequently, oil and natural gas is expected to become a smaller percentage of our total revenues over time.

Our Business Model

We are focused on actively growing revenue from the use of our surface acreage and the sale of resources from our land, while continuing to maximize value from our current mineral interests. We believe that our largely fee-based contracts, as well as our strong base of revenues from our customers’ oil and natural gas production, help mitigate our direct exposure to commodity price fluctuations and promote cash flow stability through commodity price cycles.

Sources of Revenue

Our sources of revenue currently include:

Surface Use Royalties and Revenues

•
Surface Use Royalties: Under our SURAs, including produced water handling facility leases and certain surface use agreements that contain water handling royalties, which typically provide for five- to 10-year initial terms, we receive a royalty based on a percentage of gross revenues derived from the use of our land and/or volumetric use of infrastructure installed on our land in exchange for rights of use of our land. Royalties we receive from operations under our SURAs include produced water transportation and handling operations, skim oil recovery and produced water throughput and waste reclamation, all of which are required for oil and natural gas production throughout the lifecycle of a well.

•
Easements and Surface-Related Revenues: Under our SUAs, including easements and rights-of-way, which typically provide for five- to 10-year initial terms, we typically receive a fee when the contract is executed, fixed monthly or annual payments, and often additional fees at the beginning of each renewal period. Such agreements typically include pre-defined terms for fees that we will receive for our customers’ development and use of drilling sites, new and existing roads, pipeline easements and electric transmission easements. Our SUAs generally require our customers to use the resources from our land, such as brackish water and sand, for their operations on our land, for which we receive our customary fees.

Resource Sales and Royalties

•
Resource Sales: Under our water supply agreements, we sell brackish water to be used primarily in well completions in exchange for a per barrel fee. These fees are negotiated and vary depending on the destination of the brackish water, with brackish water sold for use outside the Stateline AMI typically at wholesale prices, and brackish water sold for use in the Stateline AMI sold directly to producers at retail prices. Revenue from brackish water sold for use in the Stateline AMI is shared with TPL (please see “—Our Assets—Our Stateline Position” for more information related to our agreements with TPL). We and TPL have strong relationships with, and contractual commitments from, many of the E&P companies in the Stateline AMI. Additionally, the immediate proximity of our Stateline Position to the Texas-New Mexico state border provides us the ability to deliver brackish water volumes into the otherwise constrained market in New Mexico. Through our relationships, as well as the strategic location of our brackish water resources, we believe that we will benefit from strong demand going forward in both Texas and New Mexico. Similarly, our customers buy caliche from us for the construction of access roads and well pads for which we receive a fixed-fee per cubic yard of caliche extracted from our surface acreage. Businesses operating on our land are generally required to buy all caliche they use on our land from us.

•
Resource Royalties: Under our sand lease agreements, we lease our surface acreage to customers to construct and operate at their expense sand mines to provide in-basin sand for use in oil and natural gas completion operations. We receive a fixed

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royalty per ton of sand extracted, as well as a fixed-fee per barrel of brackish water used to support sand mining operations. Additionally, under certain access agreements and fee arrangements, we lease our surface acreage to customers to construct and operate (at their expense) brackish water wells to extract brackish water for use in oil and natural gas operations. We receive a fixed royalty per barrel of brackish water extracted.

Oil and Gas Royalties

•
Under our oil and natural gas mineral leases, we receive a lease bonus at inception and in connection with any extensions and oil and gas royalties on a per unit produced basis at a market rate, less production taxes and, in some instances, gathering, processing and transportation costs. Our leases, which typically extend for a one- to three-year primary term, permit the lessee to explore for and produce oil, natural gas and NGLs from our land and entitle us to receive a percentage of the proceeds from the sales of these commodities in the form of a royalty. If the lessee does not meet certain requirements, such as drilling and completing wells within the leased mineral acreage by a specified date, the lessee must pay to extend the lease, or the lease will terminate. If terminated, we would seek to re-lease our mineral interests to another E&P company.

We expect our fee-based revenues to grow over time relative to our revenues generated from oil and gas royalties. As shown in the chart below, for the year ended December 31, 2025, 68% of our total revenues were surface use royalties and revenues, 24% were resources sales and royalties, 6% were oil and gas royalties and 2% were considered other. For the year ended December 31, 2024, 60% of our total revenues were surface use royalties and revenues, 26% were resource sales and royalties and 14% were oil and gas royalties.

We seek to include inflation escalators in our SURAs and SUAs, which, when combined with our relatively low operating and capital expenditures, may assist in mitigating our exposure to rising costs. Given the expected long-term nature of production in the Delaware Basin, we expect these contracts to be renewed over an extended period of time. While we expect these revenue streams to be recurring over the long-term, our contracts with our significant customers, which represent a large portion of our revenues, generally do not contain minimum commitment provisions for land use or brackish water volumes to be purchased. As a result, our revenues are dependent on ongoing demand from these customers, which may decrease due to factors beyond our control despite our current expectations regarding long-term activity by our customers on our land. Among other risks to which we are exposed, we are subject to the risk of geographic concentration in the Permian Basin where we compete with other landowners to provide an attractive development site for the limited number of potential customers that seek to develop and/or construct infrastructure or procure resources necessary for their projects and operations.

Financial Performance

Key to our business model is entering into agreements under which our customers bear substantially all of the operating and capital expenditures related to their operations, while requiring only modest capital investment by us. As a result, we are able to grow our revenues, net income and Adjusted EBITDA while maintaining relatively high Free Cash Flow.

Our success in signing new commercial agreements through the active management of our land combined with the strength of our existing contracts and our proactive land acquisition strategy has resulted in significant growth in our business.

Although we believe that we have been successful in growing our business, the 1918 Ranch Acquisition required significant capital expenditure and, as of December 31, 2025, we had $570.7 million of total debt outstanding, with working capital, defined as current

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assets less current liabilities, of $47.5 million, and cash and cash equivalents of $30.7 million. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our Relationship with WaterBridge

We share a management team and financial sponsor with WaterBridge. WaterBridge owns and operates one of the largest integrated water midstream systems in the United States, providing water sourcing and produced water handling in key oil and natural gas producing basins in Texas, New Mexico and Oklahoma. WaterBridge’s key customers include Devon Energy, Permian Resources, BPX Energy, Chevron, EOG Resources, APA Corporation, Vital Energy, ConocoPhillips, San Mateo Midstream and Mewbourne Oil Company. As of December 31, 2025, WaterBridge handled approximately 2.5 million bpd of aggregate produced water and had approximately 4.8 million bpd of aggregate handling capacity, in each case across its aggregate areas of operation. WaterBridge has the right to construct produced water infrastructure on our Stateline and Northern Positions and is one of our largest customers, representing 25% of our revenue during the year ended December 31, 2025. These revenues consist of produced water handling fees, skim oil royalties, solid waste disposal and reclamation facility royalties and fees associated with rights of way for pipelines, equipment and roads and related surface use permits.

During the year ended December 31, 2025, we generated $50.5 million of revenues from WaterBridge. For every 100,000 bpd of incremental produced water that WaterBridge brings onto our surface, we expect to generate royalty fees of $4.0 million to $6.0 million per year, including skim oil royalties. The shared management team between LandBridge and WaterBridge facilitates our common goal of capitalizing on energy production in the Permian Basin through a mutually beneficial relationship. Additionally, our shared management team’s visibility into oil and natural gas production and long-term trends in the Permian Basin as a result of WaterBridge’s platform allows us to facilitate development of infrastructure in certain premier locations, thus capturing additional revenue streams.

In the Permian Basin, WaterBridge is primarily focused on building and operating integrated water networks to provide operational continuity for its upstream customers. WaterBridge’s integrated systems provide continuous handling capacity for water produced in connection with production operations. WaterBridge’s network provides operational redundancy, customer flow assurance and recycling and redelivery across its entire Permian Basin footprint. Within the Delaware Basin, WaterBridge has approximately 2,500 miles of pipeline with 4.2 million bpd of water handling capacity, as of December 31, 2025. In particular, as of December 31, 2025, WaterBridge operates an integrated water network on our land with approximately 1.5 million bpd of existing water handling capacity, primarily on our Stateline Position, and has approximately 3.2 million bpd of additional permitted capacity available for future development on our land. Additionally, WaterBridge operates two waste management facilities on our land for the reclamation and disposal of non-hazardous oilfield waste. We receive a percentage of gross revenue from solid waste disposal and reclamation operations, as well as revenue from providing brackish water for landfill operations.

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In addition, the Stateline AMI provides WaterBridge the certainty necessary to develop large-scale water infrastructure assets on our land, which we believe provides WaterBridge with greater water sourcing and handling opportunities and will generate additional royalty revenue for us. A map of WaterBridge’s assets in the Delaware Basin, as of December 31, 2025 is shown in the graphic below.

Our Relationship with Five Point

Five Point is a private equity and infrastructure investor focused on investments within the North American water management, surface management, powered land and sustainable infrastructure sectors. Five Point acquires and develops in-basin assets, provides growth capital and builds industry-leading companies with experienced management teams and large E&P partners. Five Point indirectly owns a majority of our common shares, a majority of WaterBridge’s common shares and 50% of Powered Land Partners, LLC (“PowLan”), a joint venture between a third-party developer and funds affiliated with Five Point for the development of a data center on our land. Please see “—Material Contracts and Marketing” below for more information on our relationship with PowLan.

Customers; Material Contracts and Marketing

Customers

We have a diverse customer base consisting primarily of businesses that develop and produce oil and natural gas or provide services in support of oil and natural gas production. Our customers are generally large, well-capitalized businesses that have strong credit ratings. For the year ended December 31, 2025:

•
our five largest customers, which consisted of WaterBridge, VTX Energy, ConocoPhillips, EOG Resources and Occidental Petroleum comprised 59% of total revenue; and

•
36% of total revenue was from customers with an investment grade credit rating.

Our revenue-generating agreements with WaterBridge include water facilities agreements and related SUAs, including easements and rights-of-way, pursuant to which WaterBridge has constructed and operates produced water handling facilities and fresh water facilities on our land. See “—Material Contracts and Marketing” for further information on our agreements with WaterBridge. The majority of our revenues from WaterBridge during the year ended December 31, 2025, were generated by produced water handling royalties, brackish water sales and surface use payments for infrastructure constructed on our lands, with less significant revenues generated by its other land uses. Our agreements with WaterBridge do not contain minimum volume commitments, and our revenues

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from WaterBridge can fluctuate based on the nature, timing and scope of WaterBridge’s activities on our land. Pricing for our agreements with WaterBridge is consistent with the pricing described under “Management’s Discussion and Analysis of Financial Condition and Results of Operation — How we Generate Revenue.”

Our revenue-generating agreements with VTX Energy include SUAs with VTX Energy and its water midstream affiliate, Supply Water Systems LLC (“SWS”), each with an initial term of 10 years and a perpetual term thereafter, so long as such applicable party conducts operations on Wolf Bone Ranch without cessation of use for a period of twelve consecutive months or more. Pursuant to such SUAs, VTX Energy conducts oil and natural gas development and production activities on Wolf Bone Ranch and SWS conducts produced water handling, recycling and treatment activities on Wolf Bone Ranch, as applicable, from which we receive customary royalties and fees. We also entered into a letter agreement pursuant to which VTX Energy provided a minimum annual revenue commitment of $25.0 million for each of five years beginning December 19, 2024, inclusive of revenues under the VTX Energy and SWS SUAs. The terms and conditions of, and pricing for, our agreements with VTX Energy and its affiliates are consistent with descriptions of such agreements set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue.” The majority of our revenues from VTX Energy during the year ended December 31, 2025, were generated by surface use royalties, brackish water sales and the minimum annual revenue payment under the letter agreement. Our agreements with VTX Energy can fluctuate based on the nature, timing and scope of VTX Energy’s activities on our land.

Our revenue-generating agreements with ConocoPhillips include (i) a water purchase and access agreement with an initial term of 10 years and a perpetual term thereafter, subject to termination for non-use for more than six months, pursuant to which ConocoPhillips operates brackish water wells on our lands and we receive customary royalties for each barrel of brackish water produced from such wells, (ii) brackish water supply agreements, typically on a short-term basis, pursuant to which we sell brackish water to ConocoPhillips to be used primarily in well completions, (iii) SUAs with perpetual terms so long as ConocoPhillips conducts operations thereunder, subject to termination for non-use for more than six months, pursuant to which ConocoPhillips operates produced water recycling and treatment facilities on our land and from which we receive customary royalties and fees, (iv) customary term easements, typically for five- to 10-year terms, subject to early termination for non-use over a specified period of time and (v) customary oil and natural gas mineral leases with perpetual terms so long as ConocoPhillips conducts operations thereunder. The terms and conditions of, and pricing for, our agreements with ConocoPhillips are consistent with the descriptions of such agreements set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue.” The majority of our revenues from ConocoPhillips during the year ended December 31, 2025, were generated by brackish water sales, produced water handling royalties and oil and gas royalties, with less significant revenues generated by its other land uses. Our agreements with ConocoPhillips do not contain minimum volume commitments, and our revenues from ConocoPhillips can fluctuate based on the nature, timing and scope of ConocoPhillips’ activities on our land.

Our revenue-generating agreements with EOG Resources include (i) a sand mine lease with an initial term of three years and a perpetual term thereafter so long as EOG Resources conducts operations thereunder, subject to early termination rights for non-use over six months, pursuant to which EOG Resources constructed and operates a sand mine on our land and from which we receive a per ton royalty for sand extracted and fees for water used in its mining operations, and (ii) an SUA with an initial term of 10 years and an option for EOG Resources to extend for two additional 10-year terms, pursuant to which we receive customary fees for EOG Resources’ development and use of drilling sites, new and existing roads, pipeline easements and surface and subsurface easements. The terms and conditions of, and pricing for, our agreements with EOG Resources are consistent with the descriptions of such agreements set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue.” The majority of our revenues from EOG Resources during the year ended December 31, 2025, were generated by resource royalties and brackish water sales, with resource royalties generated during the year ended December 31, 2025, reflecting EOG Resources’ sand mining operation on our surface acreage. We generated less significant revenues from EOG Resources’ other land uses during the year ended December 31, 2025. Our agreements with EOG Resources do not contain minimum volume commitments, although our sand mine lease with EOG Resources contains a nominal minimum yearly royalty payment. Our revenues from EOG Resources can fluctuate based on the nature, timing and scope of EOG Resources’ activities on our land.

Our revenue-generating agreements with Occidental Petroleum include (i) brackish water supply agreements, typically on a short-term basis, pursuant to which we sell brackish water to Occidental Petroleum to be used primarily in well completions, (ii) SUAs with perpetual terms so long as Occidental Petroleum conducts operations thereunder, subject to termination for non-use for more than six months, pursuant to which Occidental Petroleum conducts oil and natural gas exploration, development and production activities, including produced water recycling and treatment, on our land and from which we receive customary royalties and fees, (iii) customary term easements, typically for five- to 10-year terms, subject to early termination for non-use over a specified period of time and (iv) customary oil and natural gas mineral leases with perpetual terms so long as Occidental Petroleum conducts operations thereunder. The terms and conditions of, and pricing for, our agreements with Occidental Petroleum are consistent with the descriptions of such agreements set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue.” The majority of our revenues from Occidental Petroleum during the year ended December 31, 2025, were generated by damage payments under SUAs and easements, brackish water sales, produced water handling royalties and oil and gas royalties, with less significant revenues generated by its other land uses. Our agreements with Occidental

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Petroleum do not contain minimum volume commitments, and our revenues from Occidental Petroleum can fluctuate based on the nature, timing and scope of Occidental Petroleum’s activities on our land.

Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue” for further information regarding the ranges of our customary royalties and fees, inclusive of our royalties and fees with WaterBridge, VTX Energy, ConocoPhillips, EOG Resources and Occidental Petroleum.

While we would expect to be able to replace these customers, it is possible that the loss of any one of these customers could adversely affect our total revenues and have a material adverse effect on our results of operations, cash flows and financial position, whether in the short or long term. Furthermore, the determination by a customer to initiate or maintain activities on or around our land largely depends on the location of our surface acreage relative to the nature and locations of such customer’s operations and such customer’s need for the use of our land and resources. Our customers generally consist of a limited number of entities operating on and around our acreage in the Delaware Basin.

Material Contracts and Marketing

We enter into various agreements with our customers in the ordinary course relating to the use of our land and resources and the fees, royalty rates, payment structure and other related terms in our contracts are negotiated on a case-by-case basis, taking into account the surface use of our land, the type of resources extracted, and the amount of use expected to be made of our land and the amount of resources to be produced and/or extracted, among other things. For a discussion regarding general market rates for similar uses of land and resources in our industry and geographic area, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue.”

Although our agreements generally do not contain minimum commitment provisions for activities on or around our land, such as brackish water volumes to be purchased, we may include such provisions on an individual basis based on a potential customer’s proposed use of our land and resources. Under our contracts, our customers generally bear liability for environmental, health and safety risks, through indemnification of the Company, mandated insurance coverage and covenants and representations regarding environmental, health and safety compliance for all such risks, in each case, related to their operations on our land. Further, our contracts include inspection rights such that we may enter and oversee certain activities on our properties to monitor our customers’ compliance with environmental, health and safety requirements, and, following completion of the term of our agreements, our customers typically must remediate our land as close as is reasonably practicable to its state prior to such customers’ activities on the land.

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For a description of our SURAs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources of Revenue—Surface Use Royalties and Revenues—Surface Use Royalties.”

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For a description of our SUAs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources of Revenue—Surface Use Royalties and Revenues—Easements and Surface-Related Revenues.”

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For a description of our water supply agreements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources of Revenue—Surface Use Royalties and Revenues—Resource Sales.”

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For a description of our sand lease agreements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources of Revenue—Surface Use Royalties and Revenues—Resource Sales.”

In addition, we are a party to various agreements with affiliates relating to the use of our land and its resources, including:

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a produced water facilities agreement granting WaterBridge the exclusive right to construct, own and operate new produced water handling infrastructure on the western portion of our Stateline Position, with an initial term of approximately five years and automatic one-year renewals unless terminated by a party prior to renewal. We are paid a royalty for each barrel of produced water transported across our lands subject to the agreement, surface use payments in respect of its infrastructure constructed and operated on our surface acreage subject to the agreement and a percentage of the net proceeds received by WaterBridge for the sale of skim oil recovered on our land subject to the agreement. Surface use payments are based on market rates and subject to annual redetermination by us in our reasonable discretion, taking into account market rates for similar payments in the immediate vicinity of our land. The agreement provides for automatic annual increases in royalties after a specified period of time that are tied to the lesser of the CPI and a fixed percentage, and mutual termination rights in the event of a counterparty default and contains standard confidentiality, indemnification, insurance and change of control provisions;

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a produced water facilities agreement granting WaterBridge the right to construct, own and operate produced water handling infrastructure on the East Stateline Ranch, the Lea County Ranches, the Speed Ranch and all future land acquired by us in our

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Stateline and Northern Positions, with (i) a perpetual term on the East Stateline Ranch for so long as WaterBridge conducts operations thereon and (ii) an initial term of approximately ten years and automatic one-year renewals unless terminated by a party prior to renewal for all other lands. Under the agreement, WaterBridge has the exclusive right to construct and operate up to 30 produced water handling facilities at specified locations. WaterBridge also has the exclusive right to handle produced water volumes generated from oil and gas development and production on the East Stateline Ranch, subject to customary exclusions and pre-existing third-party rights. WaterBridge has the non-exclusive right to operate produced water infrastructure on all other lands subject to the agreement. We are paid a royalty for each barrel of produced water transported by WaterBridge across our land subject to the agreement, a royalty for each barrel of produced water treated and sold by WaterBridge from a recycling facility on our land subject to the agreement, surface use payments in respect of WaterBridge’s infrastructure constructed and operated on our surface acreage subject to the agreement and a percentage of the net proceeds received by WaterBridge for the sale of skim oil recovered on our land subject to the agreement. Surface use payments are based on market rates and subject to annual redetermination by us in our reasonable discretion, taking into account market rates for similar payments in the immediate vicinity of our land. The agreement provides for automatic annual increases in royalties after a specified period of time that are tied to the lesser of CPI and a fixed percentage, and mutual termination rights in the event of a counterparty default and contains standard confidentiality, indemnification, insurance and change of control provisions;

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a fresh water facilities agreement granting WaterBridge the right to construct, own and operate brackish water infrastructure on the East Stateline Ranch, the Lea County Ranches, the Speed Ranch and all future land acquired by us in our Stateline and Northern Positions, with (i) a perpetual term on the East Stateline Ranch for so long as WaterBridge conducts operations thereon and (ii) an initial term of approximately ten years and automatic one-year renewals unless terminated by a party prior to renewal for all other lands. WaterBridge has the exclusive right to market and sell brackish water produced from the East Stateline Ranch to third parties for use in oil and natural gas operations, subject to customary exclusions and pre-existing third-party rights. WaterBridge has the non-exclusive right to operate brackish water infrastructure on all other lands subject to the agreement for use in oil and natural gas operations. We may grant third parties the right to transport brackish water across the lands subject to the agreement, including the East Stateline Ranch. We are paid a royalty for each barrel of brackish water produced by WaterBridge from, or transported by WaterBridge across, our land subject to the agreement, a percentage of the net proceeds for each barrel of brackish water produced by WaterBridge from our land subject to the agreement and sold for use off of our land and surface use payments in respect of WaterBridge’s infrastructure constructed and operated on our land subject to the agreement. Surface use payments are based on market rates and subject to annual redetermination by us in our reasonable discretion, taking into account market rates for similar payments in the immediate vicinity of our land. The agreement provides for automatic annual increases in royalties after a specified period of time that are tied to the lesser of CPI and a fixed percentage, and mutual termination rights in the event of a counterparty default and contains standard confidentiality, indemnification, insurance and change of control provisions;

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a surface lease and use agreement granting WaterBridge the non-exclusive right to construct, own and operate produced water handling infrastructure on the Wolf Bone Ranch, with an initial term of 10 years and the option for WaterBridge to renew for additional 10-year terms in return for one-time renewal payments. We are paid a royalty for each barrel of produced water handled on our lands subject to the agreement and surface use payments in respect of produced water handling infrastructure constructed and operated on our surface acreage subject to the agreement. Surface use payments are based on market rates and subject to redetermination by us from time-to-time in our commercially reasonable discretion, taking into account market rates for similar payments in the immediate vicinity of our land. The agreement provides for mutual termination rights in the event of a counterparty default and contains standard confidentiality, indemnification, insurance and change of control provisions;

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a lease development agreement for the development of a data center and related facilities on approximately 2,000 acres of our land in Reeves County, Texas with PowLan. PowLan is obligated to meet certain timing milestones to maintain its lease, including the commencement of site development within a two-year period and the construction of the data center within a subsequent four-year period. To the extent PowLan does not commence site development within two years of entry into the lease development agreement or commence construction of the data center within a subsequent four-year period, the agreement will automatically terminate. The lease development agreement includes, among other things, a non-refundable deposit and a two-year site selection and pre-development period; and

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surface use agreements with WaterBridge, each with an initial term of 10 years and automatic one-year renewals unless terminated by either party prior to renewal, pursuant to which we have granted certain exclusive rights to construct, operate and maintain non-hazardous waste management facilities on our land and we receive a percentage of gross revenue from solid waste disposal and reclamation, as well as additional revenue from providing water for landfill operations and fees for surface damages, which surface damage payments are based on market rates and subject to annual redetermination by us in our reasonable discretion, taking into account market rates for similar payments in the immediate vicinity of our land. Each party is required to purchase all dirt, gravel and similar materials utilized in connection with such facilities on our land, as well as for all brackish water, from us. These agreements contain standard confidentiality, indemnification, insurance and change of control provisions.

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We are also party to lease arrangements with respect to a portion of our oil and natural gas mineral interests. See “—Our Assets—Mineral Interests” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Gas Royalties.”

In addition to continuing to capitalize on existing agreements and relationships, we intend to pursue and acquire new commercial arrangements in an effort to develop and diversify our revenue streams. As such, we are currently pursuing arrangements, or have agreed to certain arrangements, relating to solar power generation, power storage, microgrids, cryptocurrency mining and data centers, non-hazardous oilfield reclamation and solid waste facilities and commercial fueling stations, among other revenue streams. Similar to the other operations conducted on our land, we expect to enter into surface use or similar agreements with the owners of these projects from which we expect to receive surface use fees and other payments in connection with the utilization of our land, but we would not own or operate such projects or expect to incur significant capital expenditures in connection therewith.

Infrastructure

In order to use our surface acreage to, among other things, support all stages of energy development and production to supply growing global demand, we have entered into various SUAs through which our customers have built and own or are developing infrastructure on our land, including oil, natural gas and produced water gathering pipelines, recycled water pipelines, produced water handling facilities, water recycling ponds, sand mines, non-hazardous oilfield reclamation and solid waste facilities, a data center and a cryptocurrency facility, as of December 31, 2025. We also own brackish water wells and ponds on our land.

In addition to the above infrastructure, improvements with respect to permanent electrical infrastructure, including telecommunication lines, drilling pad sites, roads and landfills, among other things, have been made on our land that improve reliability and lower operating costs for our customers. Although infrastructure with the ability to increase revenue-generating activities is already present on our surface acreage, we believe that our land presents a multitude of additional opportunities for further commercialization and optimization, including coordinating with potential customers to construct infrastructure relating to power storage, water treatment facilities, hydrogen production and carbon capture and sequestration.

Cyclical Nature of Oil and Natural Gas Industry

The oil and natural gas industry is a highly cyclical industry. Demand for the use of our land and its resources depends substantially on activity levels by producers on and around our land. Prevailing commodity prices and future demand for, and price of, oil and natural gas and volatility in oil or natural gas prices (or the perception that oil or natural gas prices will decrease) affects such producers’ capital expenditures and willingness to pursue development activities. As such, the willingness of our producers to engage in drilling activities on and around our land is substantially influenced by the market prices of oil and natural gas. Producers tend to increase capital expenditures in response to increases in oil and natural gas prices, which would generally be expected to result in greater revenues for us. Increased capital expenditures can also lead to greater production, which historically has resulted in increased supplies of oil and natural gas that can, in turn, reduce prices thereby leading to a reduction in activity levels. For these reasons, the results of our operations may be cyclical and may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods.

Seasonality

While our business is not necessarily seasonal in nature, revenue from the use of our land and its resources may fluctuate over certain reporting periods due to fluctuations in the prices of oil and natural gas. Generally, but not always, the demand for natural gas, as well as associated production, decreases during the summer months and increases during the winter months, thereby affecting the amount we receive in association with natural gas production and related activities on our land.

Seasonal anomalies, such as mild winters or hotter than normal summers, may lessen this fluctuation. Demand for oil has generally not been seasonal. Our other revenue streams, including sales of brackish water, payments from SUAs and other surface related revenue and sales of resources, may also vary from period to period due to seasonal changes in supply and demand, and a variety of additional seasonal factors that are beyond our control and the control of producers on or around our land.

Our results and business are significantly dependent on our customers and their activities on our land, which are beyond our control. Weather conditions in the Permian Basin generally result in higher drilling activity in the spring, summer and fall months, although summer and fall drilling activity can be restricted due to severe weather conditions. In the fourth quarter, due to inclement weather and the exhaustion of annual drilling and completion capital expenditure budgets, drilling activity typically declines in the Permian Basin. As a result, our results of operations, cash flows and financial position may vary year over year, with particular periods of results not necessarily indicative of our future results.

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Human Capital Resources

We manage our operations through a shared services agreement (the “Shared Services Agreement”) with certain affiliates of WaterBridge (the “Manager”). Pursuant to the Shared Services Agreement, the Manager provides us with the services of our senior executive management team and certain management services, as well as general, administrative, overhead and operating services to support our business and development activities, including by making available five full-time personnel exclusively providing field services on our surface acreage and five full-time corporate services personnel exclusively providing corporate services to us.

Pursuant to the Shared Services Agreement, the Manager also provides operational and maintenance services, such as project and construction management, and provides operating materials and equipment. Because our customers construct and operate almost all of the infrastructure installed on our acreage, we expect to maintain a minimal number of dedicated personnel. As of December 31, 2025, we did not directly employ any employees.

Due to our Shared Services Agreement, our business and the success thereof is dependent, in part, on the Manager’s ability to attract and retain qualified personnel. As part of the Manager’s efforts to hire and retain highly qualified employees, the Manager has structured competitive compensation and benefits programs that reward outstanding performance. In addition to the incentive programs in place for our named executive officers, the Manager has structured an incentive bonus program for employees that is dependent on an employee’s individual performance.

Certain employees of the Manager who make material contributions to our success may also receive restricted share units and/or other equity-based incentive awards to encourage retention and align compensation with our performance. The Manager provides a comprehensive benefits package, including 401(k) contributions, medical insurance options and programs to encourage and support employee development. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. In general, we believe that our personnel relations are positive.

Personnel Health and Safety

Safety is important to us and begins with the protection and safety of the personnel who provide services with respect to our business and the communities in which we operate. We value people above all else and remain committed to making safety and health a top priority. We strive to comply with all applicable health and safety laws and regulations and continually seek to maintain and deepen our safety culture by providing a safe working environment that encourages active personnel engagement, including implementing safety programs and continuing education policies to achieve improvements in our safety culture. We intend to continue to develop and administer policies to promote our organizational goals and improve and maintain the safety of our workspace.

Competition

The market in which we operate is competitive due to the location of our land in the Permian Basin in Texas and New Mexico and to the services in which we offer our customers. Given our geographic concentration in the Permian Basin, we compete with existing landowners in the area to provide an attractive development site for the limited number of potential customers that seek to develop and/or construct infrastructure in Texas and New Mexico to support their various business activities. We also compete with such landowners over the limited supply of, and demand for, resources, including brackish water, in the area. Furthermore, to the extent any new property owner purchases land located in areas comparable to our surface acreage, such property owner could be a potential competitor. As we continue to grow our business and enter into new business lines, including with respect to renewable energy, non-hazardous oilfield reclamation and solid waste facilities and other revenue streams, we will experience increasing levels of competition. Competition in our current market is based primarily on the geographic location of land, business reputation, pricing arrangements for the use of the land and its resources and legal and regulatory restrictions, among other factors. Although some of our competitors may have a broader geographic scope, longer operating history and greater financial and other resources than we have, we believe that we are competitively well-positioned due to the premier location of our land, which also provides a multitude of resources and uses, the reliability of our assets and our customer relationships, such as our symbiotic relationship with WaterBridge.

Insurance

We maintain insurance coverage at levels that we believe are reasonable and prudent; however, as is customary in our industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. We may not be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable and our actual coverage may not insure against many types of interruptions or events that might occur. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if a loss event were to occur. The occurrence of such an event, the consequences of which are either not covered by insurance or not fully insured, or a significant delay in, or denial of, the payment of a major insurance claim, could have a materially and adverse effect on our results of operations, cash flows and financial position. Our arrangements with our customers operating on our land require the maintenance of certain levels of insurance and such customers’ indemnification of us to protect for such events occurring with respect to their operations.

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Regulation of Environmental and Occupational Safety and Health Matters

Our customers’ business operations are subject to numerous environmental and occupational health and safety laws and regulations that may be imposed at the federal, regional, state and local levels. The activities that our customers conduct in the course of oil and natural gas exploration and production, produced water handling, sand mining, and other activities are subject to or may become subject to stringent environmental regulation. Our customers are responsible for compliance with various environmental laws and regulations in the course of their operations. Although we generally have the right to inspect our properties and the activities thereon, we typically do not have any control with respect to such activities. For properties in which we hold mineral or royalty interests, we generally are not subject to direct environmental liability because we do not own, operate, or otherwise have control over any of the equipment, facilities, or operations occurring on such properties. However, with respect to land owned by us and leased to a customer, we may be subject to strict, joint and several liability for any spills or contamination on those properties, even though we generally have no control over operations on properties. For further information, see “Risk Factors—Risks Related to Environmental and Other Regulations—Our customers” operations on our land may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements, and we may be subject to strict, as well as joint and several liability, for contamination resulting from such operations pursuant to such requirements, even if we do not have control over such operations. The occurrence of any such delays, costs and liabilities may materially and adversely affect our customers’ business, operations or financial condition, which could reduce the demand for the use of our land and its resources, as well as the royalties and other payments we receive therefrom, and thereby materially affect our results of operations, cash flows and financial position. To mitigate the risk of potential environmental liabilities that may arise in the course of operations on our properties that we do not control, we generally seek to partner with reputable customers and seek indemnification from our customers for liabilities arising from their operations on our land, and we maintain what we believe is customary and reasonable insurance to protect our business against these potential losses. We also typically include covenants relating to compliance with environmental, health and safety regulations and remediation provisions in our contracts. Additionally, we may be able to rely on state funded programs (such as the Texas Railroad Commission’s (“TRRC”) Orphan Well Program) for coverage of certain plugging and abandonment liabilities upon declaration of bankruptcy by any of our customers. However, such actions may not be adequate to cover our liabilities, and we are not fully protected or insured against all risks. We do not expect environmental compliance costs to have a material adverse effect on our results of operations, cash flows and financial position; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our results of operations, cash flows and financial position, or on those of our customers.

The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. legal standards, as amended from time to time:

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the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring and reporting requirements, and which the U.S. Environmental Protection Agency (“EPA”) has historically relied upon as authority for adopting climate change regulatory initiatives relating to GHG emissions;

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the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants into state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

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the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

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the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

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the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities, pipelines and other facilities, as well as lessees or permittees of areas in which offshore facilities are located, that are the site of an oil spill in waters of the United States, to liability for removal costs and damages;

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the Safe Drinking Water Act (the “SDWA”), which ensures the quality of the United States’ public drinking water through the adoption of drinking water standards and control of the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;

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the Endangered Species Act (the “ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

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the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and

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the Occupational Safety and Health Act (“OSHA”), which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

Texas and New Mexico have similar laws and regulations in many respects. These environmental and occupational health and safety laws and regulations generally restrict the level of substances generated as a result of operations that may be emitted to ambient air, discharged to surface water, and disposed or released to surface and below-ground soils and ground water. Additionally, there exist state and local jurisdictions in the United States where we operate that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. Any failure by us, or our customers, to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal fines or penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all activities in a particular area. Certain environmental laws also provide for citizen suits, which allow environmental organizations to act in place of the government and sue those subject to the laws, in many cases, our customers, for alleged violations of environmental law. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.

Some of our land has been or is now operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons is not under our control. Under environmental laws such as CERCLA and RCRA, we could incur strict, joint and several liability for remediating hydrocarbons, hazardous substances or wastes disposed of or released by us or prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.

Waste Disposal. RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and nonhazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as nonhazardous could be classified as hazardous wastes in the future. Any loss of the RCRA exclusion for drilling fluids, produced water and related wastes could result in an increase in our and our oil and natural gas producing operators’ costs to manage and dispose of generated wastes, which could have a material adverse effect on our and our customers’ results of operations, cash flows and financial position. Texas and New Mexico have received authority from the EPA to administer the RCRA program in their respective jurisdictions, in addition to their own state regulations.

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with our customers’ operations. Certain processes used to produce oil and natural gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is subject primarily to individual state radiation control regulations. For example, the TRRC and New Mexico Oil Conservation Division (“NMOCD”) generally regulate the management and disposal of NORM from oil and natural gas operations in their own respective jurisdictions. In addition, NORM handling and management activities are governed by regulations promulgated by OSHA. These state and OSHA regulations impose certain requirements concerning worker protection, the treatment, storage and disposal of NORM waste and the management of waste piles, containers and tanks containing NORM, as well as restrictions on the uses of land with NORM contamination.

The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the U.S. 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. The CWA and analogous state laws also require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities.

Water Regulation. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. There continues to be uncertainty regarding the federal government’s applicable jurisdictional reach under the CWA over waters of the U.S., including wetlands, as the EPA and the U.S. Army Corps of Engineers (“Corps”) have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. In January 2023, the EPA and the Corps issued a final rule

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founded upon the pre-2015 regulations and incorporated updates based on existing Supreme Court decisions, including considerations based on regional and geographic differences. Additionally, in May 2023, the Supreme Court decided Sackett v. EPA, a case relating to the legal tests used to determine whether wetlands should be considered waters of the United States. A revised waters of the United States rule was issued in September 2023, to amend the January 2023 rule based on the Sackett decision, but it is currently being challenged in multiple courts. Due to the rule’s injunction in certain states, the implementation of the September 2023 final rule varies by state and the operative definition is different in the two states in which we currently operate. However, in November 2025, the EPA and the Corps proposed a rule to further update and narrow the September 2023 definition. To the extent any judicial ruling or administrative rulemaking or other action changes the scope of the CWA’s jurisdiction, we, WaterBridge and our producers and other customers could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of crude oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. To the extent that any new final rule or rules issued by the EPA and Corps expands the scope of the CWA’s jurisdiction in areas where we or our customers conduct operations, such developments could increase compliance expenditures or mitigation costs, contribute to delays, restrictions, or cessation of the development of projects, and also reduce the rate of production of oil and natural gas from producers with whom we have a business relationship and, in turn, have a material adverse effect on our results of operations, cash flows and financial position. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions. The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions standards, construction and operating permit programs and the imposition of other compliance standards. These laws and regulations may require us, or our customers, to obtain preapproval 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 our projects as well as our customers’ development of various types of projects. Over the next several years, our customers may incur certain capital expenditures for air pollution control equipment or other air emissions related issues, which could lead to an increase in our customers’ operating costs or a decrease in our or our customers’ revenues and limit future development activity by our customers, including WaterBridge, thereby reducing their demand for the use of our land and resources. For example, in 2015, the EPA issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground level ozone more stringent. In December 2020, the EPA under the Trump Administration published a final action that elected to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups filed litigation over the December 2020 decision, and the Biden Administration subsequently announced plans to reconsider the December 2020 final action in favor of a more stringent ground-level ozone NAAQS. On August 21, 2023, the EPA announced a new review of the ozone NAAQS to reflect updated ozone science in combination with the reconsideration of the December 2020 decision. In June 2025, the EPA announced its plans to reconsider its finalized revisions to the regulatory deadlines for submitting state implementation plan (SIP) revisions and implementation requirements for nonattainment areas under the 2015 ozone NAAQS.

State implementation of the revised NAAQS could also result in the imposition of more stringent requirements through permits issued by the New Mexico Environmental Department or the Texas Commission on Environmental Quality if projects on our land have air emissions above certain thresholds set under applicable laws and regulations. Compliance with the NAAQS requirements or other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas and other projects and increase our or our customers’ costs of development and production, which costs could reduce demand for our services and have a material adverse impact on our results of operations, cash flows and financial position.

Notwithstanding the EPA’s recent proposal to revoke the “endangerment finding,” which supports the majority of the EPA’s GHG-related regulations, in recent years, the agency has made considerable efforts to regulate GHG emissions from oil and natural gas operations. These include regulations that establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector. In addition, the Inflation Reduction Act of 2022 (the “IRA”) amended the CAA to impose a fee on the emission of excess methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. In May 2024, the EPA issued a final rule to implement the IRA’s methane fee, although in February 2025, Congress repealed the rule under the Congressional Review Act. Additionally, in the One Big Beautiful Bill Act (“OBBBA”), Congress delayed the implementation of the methane emission fee until 2034. We cannot predict if the Trump Administration and / or Congress may take further actions with respect to the IRA or the methane emissions fee. However, compliance with this and other air pollution control and permitting requirements has the potential to increase costs for our customers and, indirectly, adversely affect our results of operations, cash flows and financial position.

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Produced Water Handling Facilities. Water handling via underground injection is regulated pursuant to the Underground Injection Control (“UIC”) program established under the SDWA and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring, recordkeeping and reporting of produced water handling activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate produced water handling facilities. Authority over underground injection and disposal wells has been delegated by the EPA to the TRRC and the NMOCD, respectively. Although our customers monitor the injection process of their facilities, any leakage from the subsurface portions of the produced water handling facilities could cause degradation of groundwater resources, potentially resulting in suspension of our customers UIC permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties claiming damages for alternative water supplies, property and personal injuries. A change in water handling regulations or the inability to obtain permits for new produced water handling permits in the future may affect our customers’ ability to handle produced water and other substances on our land, which could adversely affect our business, results of operations, cash flows and financial position.

Furthermore, in response to seismic events in the past several years near produced water handling facilities used for disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such facilities have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such produced water handling facilities in certain areas prone to increased seismic activity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region and that only a very small fraction of the tens of thousands of produced water handling facilities have been suspected to be, or have been, the likely cause of induced seismicity. In 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. As a result of these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water handling facilities or otherwise to assess any relationship between seismicity and the use of such wells. For example, the TRRC has issued rules for water handling facilities that imposed certain permitting and operating restrictions and reporting requirements on produced water handling facilities in proximity to faults. New Mexico has, in some parts of the state, issued monitoring and reporting guidelines with respect to seismic activity and requires significant spacing between produced water handling facilities.

States also may issue orders to temporarily shut down or to curtail the injection depth of existing facilities in the vicinity of seismic events. In Texas, the TRRC has pursued several regulatory initiatives since the latter half of 2021 as a result of recent seismic activity in an area of the Midland Basin including: (i) directing operators to pursue voluntary reductions in produced water handling from scores of produced water handling facilities in response to earthquakes; (ii) suspending certain deep produced water handling permits within seismic response areas: and (iii) suspending all produced water handling permits to inject oil and natural gas waste into deep strata within the boundaries of seismic response areas. In November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. Further, on July 11, 2024, New Mexico announced the administrative cancellation of 75 pending permit applications for UIC Class II wells within the 10-mile County Line Seismic Response Area, due to the potential for increased seismicity within the area. An additional consequence of this seismic activity is lawsuits alleging that produced water handling operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. The adoption and implementation of any new laws, regulations or directives that restrict our customers’, including WaterBridge’s, ability to dispose of wastewater on our land by limiting volumes, disposal rates, produced water handling facility locations or otherwise, or requiring our customers to shut down produced water handling facilities, could reduce the demand for use of our land and resources and limit the fees and royalties we receive from the transportation and the handling of produced water on our land, which would have a material adverse effect on our results of operations, cash flows and financial position.

Hydraulic Fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is an important and common practice that is typically regulated by state oil and natural gas commissions or similar agencies. However, the practice continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal agencies that have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process.

Moreover, some state and local governments, including states where our customers operate, have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including bans on hydraulic fracturing. For example, Texas, New Mexico and other states have adopted regulations that impose stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations, such as the TRRC’s 2014 “well integrity rule.” States could also elect to place certain prohibitions on hydraulic fracturing. For example, in multiple annual New Mexico legislative sessions, there have been continued efforts to pause hydraulic fracturing and cease state issuance of permits for a four year time period, although none of the bills introduced on this topic have yet passed the New Mexico Legislature.

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In the event that new federal, state or local restrictions or bans on the hydraulic fracturing process are adopted in areas where our land is located, our customers may incur additional costs or permitting requirements to comply with such requirements that may be significant in nature and our customers could experience added restrictions, delays or cancellations in their exploration, development, or production activities, which would in turn reduce the demand for use of our land and resources and have a material adverse effect on our results of operations, cash flows and financial position.

Climate Change. The threat of climate change continues to attract considerable attention from the public and policymakers in the U.S. and around the world. As a result, numerous proposals have been made, and more are likely forthcoming at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our customers are subject to a series of regulatory, political, litigation, and financial risks associated with our and their operations, including those related to the production and processing of fossil fuels and emission of GHGs.

Endangered Species. The ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are afforded under the Migratory Bird Treaty Act (the “MBTA”), which prohibits the taking of protected migratory bird species without prior authorization by the U.S. Fish and Wildlife Service (“FWS”). To the degree that species listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our customers operate, our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or we and our customers could be forced to incur material additional costs. Moreover, our customers’ drilling activities may be delayed, restricted, or cancelled in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our land and the operations of our customers are located in areas that are designated as habitats for protected species. In addition, the FWS may make determinations on the listing of unlisted species as endangered or threatened under the ESA For example, in November 2022, the FWS listed the northern district population segment of the lesser prairie chicken (encompassing southwest Colorado, south central to western Kansas western Oklahoma and the northeast Texas Panhandle) as threatened under the ESA, and the southern district population segment (covering eastern New Mexico and the southwest Texas panhandle) as endangered. The listing decision for the lesser prairie chicken was challenged by the states of Texas, Kansas, and Oklahoma, and various industry groups, with the U.S. District Court for the Western District of Texas vacating the rule for the northern district population segment in March 2025. Further, the FWS listed the dunes sagebrush lizard as an endangered species under the ESA in a final rule that became effective in June 2024. In September 2024, however, that listing decision was also challenged by the state of Texas in the U.S. District Court for the Western District of Texas. The results of that challenge remain uncertain. Critical habitat for the species has not yet been designated but is expected to occur after a separate rulemaking in the future. The designation of previously unidentified endangered or threatened species could indirectly cause us or our customers to incur additional costs, cause our or our customers’ operations to become subject to operating restrictions or bans and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of, or access to, federal, state, and private lands, including our land.

Over time, the trend in environmental and occupational health and safety regulation is to typically place more restrictions and limitations on activities that may adversely affect the environment or expose workers to injury and thus, any changes in environmental or occupational health and safety laws and regulations or reinterpretation of enforcement policies that may arise in the future and result in more stringent or costly waste management or disposal, pollution control, remediation or occupational health and safety-related requirements could have a material adverse effect on our business, results of operations, cash flows and financial position. We may not have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, and we may be unable to pass on increased compliance costs arising out of such risks to our customers. We review regulatory and environmental issues as they pertain to us and we consider regulatory and environmental issues as part of our general risk management approach. For more information on environmental and occupational health and safety matters, see “Risk Factors—Risks Related to Environmental and Other Regulations—Legislation or regulatory initiatives intended to address seismic activity, over-pressurization or subsidence could restrict drilling, completion and production activities, as well as WaterBridge’s ability to handle produced water gathered from its customers, which could have a material adverse effect on our results of operations, cash flows and financial position,” “Risk Factors—Risks Related to Environmental and Other Regulations—The results of operations of our customers, as well as producers on or around our land, may be materially impacted by efforts to transition to a lower-carbon economy,” “Risk Factors—Risks Related to Our Business and Operations—We may be subject to claims for personal injury and property damage, or for catastrophic events, which could materially and adversely affect our results of operations, cash flows and financial position,” “Risk Factors—Risks Related to Our Business and Operations—We or our customers may be unable to obtain and renew permits necessary for operations, which could materially and adversely affect our results of operations, cash flows, and financial position” and “Risks Related to Our Business and Operations.”

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Organizational Structure; Availability of Information

LandBridge was formed on September 27, 2023 as a Delaware limited liability company. We are a holding company whose principal asset is membership interests in OpCo. We are also the sole managing member of OpCo. Our principal executive office is located at 5555 San Felipe Street, Suite 1200, Houston, Texas 77056, and we have an additional office in Midland, Texas.

The following diagram reflects our current simplified organizational structure as of December 31, 2025.

1 In connection with the 1918 Ranch Acquisition, we issued 657,411 OpCo Units and a corresponding number of Class B shares to sellers. For more information, see “—Recent Developments—1918 Ranch Acquisition.”

* This diagram is provided for illustrative purposes only and has been simplified by not depicting each individual operating subsidiary.

Our website is located at www.landbridgeco.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and filings and amendments thereto filed or furnished with the SEC are available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are filed with or furnished to the SEC. Information contained on our website is not incorporated into this Annual Report or on our other filings with the SEC. Our filings are available in hard copy, free of charge, by contacting us at 5555 San Felipe Street, Suite 1200, Houston, Texas 77056, Attention: Investor Relations, telephone: (432) 445-3929. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Also posted on our website under “Investor Relations—Governance—Governance Documents,” and available in print upon request made by any shareholder to the Investor Relations Department, are our Code of Business Conduct and Ethics and Whistleblower Policy and Corporate Governance Guidelines, as well as our charter for our Audit Committee. Within the time period required by the SEC, the New York Stock Exchange (the “NYSE”) and NYSE Texas, Inc. (“NYSE Texas”), as applicable, we will post on our website any modifications to the foregoing governance documents and any waivers applicable to senior officers as defined in the applicable governance document, as required by the Sarbanes-Oxley Act.

We webcast our earnings calls and certain events we participate in or host with members of the investment community on our investor relations website. Additionally, we provide notifications of news or announcements regarding our financial performance, including SEC filings, investor events and presentations and press and earnings releases, as part of our investor relations website. We intend for our website to be a forum of public dissemination for purposes of Regulation FD.

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