EDGAR 10-K Filing

Company CIK: 1995807
Filing Year: 2025
Filename: 1995807_10-K_2025_0000950170-25-034049.json

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ITEM 1. BUSINESS
Item 1. Business
LandBridge was formed on September 27, 2023 as a Delaware limited liability company to serve as the issuer in an initial public offering of equity, which closed on July 1, 2024 (the “IPO”). LandBridge is a holding company, the sole material asset of which is membership interests in OpCo. LandBridge is also the sole managing member of OpCo. Unless otherwise indicated or the context otherwise requires, references in this Annual Report to “LandBridge”, “us,” “we,” “our” or the “Company” are to (i) OpCo and its subsidiaries before the completion of the corporate reorganization in connection with the IPO (the “Corporate Reorganization”) and (ii) LandBridge and its subsidiaries as of the completion of the Corporate Reorganization. For more information on the IPO and the Corporate Reorganization, please see “-2024 Significant Events.”
Company Overview
Land is a fundamental requirement for the development and production of energy and the construction and operation of critical infrastructure. As of December 31, 2024, we owned approximately 273,000 surface acres in and around the Delaware Basin sub-region in the prolific Permian Basin, which is the most active area for oil and natural gas exploration and development in the United States. Access to expansive surface acreage is necessary for oil and natural gas development, solar power generation, power storage, digital infrastructure and non-hazardous oilfield reclamation and solid waste facilities. Further, the significant industrial economy that exists to service and support energy and infrastructure development requires access to surface acreage to support those activities. Our strategy is to actively manage our land and resources to support and encourage energy and infrastructure development and other land uses that will generate long-term revenue and Free Cash Flow for us and returns to our shareholders. Please see “How We Evaluate Our Operations” for more information regarding Free Cash Flow.
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, 2024, handles approximately 2.0 million bpd of water associated with oil and natural gas production, with approximately 3.4 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, 2024, approximately 767,000 bpd of water handling capacity on our land, with approximately 1.7 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 partnership 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, Five Point formed Desert Environmental, which operates non-hazardous oilfield reclamation and solid waste facilities that are located on our land.
In addition to our relationships with WaterBridge and Desert Environmental, 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 Company (“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.
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 and production, 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 utilized in connection with oil and natural gas well completions, and royalties from sand extracted from our land for oil and natural gas operations. 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 4,424 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,
(in thousands)
Total revenues
$
109,954
$
72,865
Net (loss) income (1)
(41,479
)
63,172
Adjusted EBITDA (2)
97,069
62,804
Cash flows from operating activities
67,636
53,042
Capital expenditures
(985
)
(2,783
)
Free Cash Flow (2)
66,651
50,259
(1)	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 solar power generation, microgrids, power storage, cryptocurrency mining and data management, as well as other renewable energy production, among other industries and applications. For example, we recently entered into a lease development agreement with a joint venture between a third-party developer and funds affiliated with Five Point for the development of a data center and related facilities on approximately 2,000 of our surface acres in Reeves County, Texas. 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.
For the year ended December 31, 2023, we generated $52.1 million of non-oil and gas royalty revenue on our approximately 72,000 owned surface acres, or $724 in revenue per owned surface acre. As a result of our active management strategy, we have increased non-oil and gas royalty revenue on the same 72,000 owned surface acres by 41% to $73.3 million, or $1,018 in revenue per owned surface acre for the year ended December 31, 2024. The Spring 2024 Acquisitions and Recent Acquisitions contributed post-acquisition revenues of $20.6 million of non-oil and gas royalty revenue and approximately 201,000 owned surface acres. When annualized, revenue from such acquisitions is $62.7 million or $312 per acquired surface acre for the year ended December 31, 2024. Inclusive of the annualized revenue and expanded acreage as a result of the acquisitions, and the $73.3 million from existing acreage, the resulting pro forma non-oil and gas royalty revenue was $136.0 million, or $498 per owned surface acre for the year ended December 31, 2024 on our approximately 273,000 owned surface acres. We measure our revenue divided by our total acreage as a performance metric, which we refer to as “surface use economic efficiency.” We believe that our acquisitions during the year ended December 31, 2024, present an attractive opportunity to apply our active land management strategy in a similar fashion and generate attractive returns for our investors.
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.
Our Assets
We own approximately 273,000 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, 2024. 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 137,000 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, 2024. 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 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, 2024, WaterBridge and third party operators collectively operated approximately 1.0 million bpd of existing produced water handling capacity on our Stateline Position. Without giving effect to the Recent Acquisitions, we believe that the pore space underlying our Stateline Position will be able to support approximately 2.6 million bpd of additional produced water handling capacity, assuming 25,000 bpd produced water handling permits and one-mile spacing between all future produced water handling facilities.
The eastern portion of our Stateline Position includes 104,000 contiguous surface acres in Winkler and Loving Counties, Texas and Lea County, New Mexico, as of December 31, 2024. 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 56,000 fee-owned surface acres and 33,285 additional surface acres leased from the BLM and the State of New Mexico as of December 31, 2024. Our BLM and State of New Mexico acreage is leased under customary lease terms on a year-to-year basis.
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, 2024, WaterBridge and third party operators collectively operated approximately 115,000 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 1.0 million bpd of additional produced water handling capacity, assuming 25,000 bpd produced water handling permits and one-mile spacing between all future produced water handling facilities.
Our Southern Position
Our Southern Position consists of approximately 80,000 surface acres located in Reeves and Pecos Counties, Texas in the Delaware Basin as of December 31, 2024. Various producers have operations on or in the vicinity of our Southern Position, including ConocoPhillips, 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 acquired approximately 46,000 largely contiguous surface acres in the Southern Delaware Basin known as the Wolf Bone Ranch (the “Wolf Bone Acquisition”). 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 MBbls/d serviced by infrastructure owned and operated by VTX Energy, as well as assets owned and managed by WaterBridge. In connection with the Wolf Bone Acquisition, VTX Energy has agreed to a minimum revenue commitment to LandBridge of $25 million per year for the next five years.
As of December 31, 2024, WaterBridge and third party operators collectively operated approximately 400,000 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, through our subsidiary, DBR Solar LLC, we are permitting the construction and operation of a facility with 250-megawatts of solar generation capacity on our Southern Position. 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 collectively, serve as corridors for significant vehicle traffic and for pipeline and electrical infrastructure, representing additional development opportunities for this surface acreage.
Our Mineral Interests
We own 4,424 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 4.3%, as of December 31, 2024. 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 owners of working interests in oil and natural gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and natural gas production. As a mineral owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs. 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. Of our gross mineral acres, approximately 96% underlie our surface acreage. Other than our gross mineral acres, we do not own the mineral interests that underlie our surface acreage.
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
royalty per ton of sand extracted, as well as a fixed-fee per barrel of brackish water used to support sand mining operations. A large E&P company currently operates a sand mine on our land, and we have recently executed sand leases with two additional sand mine operators to develop and operate sand mines on our land.
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. While our focus is on fee-based arrangements, our revenues generated from oil and gas royalties fluctuate with market prices for oil and natural gas. For the year ended December 31, 2023, 35% of our total revenues were surface use royalties and revenues, 36% were resource sales and royalties and 29% were oil and gas royalties. As shown in the chart below, for the year ended December 31, 2024, 60% of our total revenues were surface use royalties and revenues, 26% were resources 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 Recent Acquisitions required significant capital expenditures and, as of December 31, 2024, we had $385.5 million of total debt outstanding, with working capital, defined as current
assets less current liabilities, of $38.9 million, and cash and cash equivalents of $37.0 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 Permian Resources, Devon Energy, Chevron, EOG Resources, Apache Corporation, Vital Energy, ConocoPhillips, San Mateo Midstream, Mewbourne Oil Company, and Diamondback Energy. As of December 31, 2024, WaterBridge handled approximately 2.2 million bpd of aggregate produced water and had approximately 4.2 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 24% of our revenue during the year ended December 31, 2024. These revenues consist of:
•produced water handling fees;
•skim oil royalties; and
•fees associated with rights of way for pipelines, equipment and roads and related surface use permits.
During the year ended December 31, 2024, we generated $26.1 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 revenues. 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 1,675 miles of pipeline with 3.4 million bpd of water handling capacity, as of December 31, 2024. In particular, as of December 31, 2024, WaterBridge operates an integrated water network on our land with approximately 767,000 bpd of existing water handling capacity, primarily on our Stateline Position, and has approximately 1.7 million bpd of additional permitted capacity available for future development on our land.
In addition, the Stateline AMI provides WaterBridge the certainty necessary to develop large-scale water infrastructure assets on our land, which we believe will provide 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, 2024 is shown in the graphic below.
Our Relationship with Desert Environmental
We share a financial sponsor with Desert Environmental. Desert Environmental operates two environmental remediation facilities for non-hazardous oilfield reclamation and solid waste disposal on our land. 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.
Our Relationship with Five Point
Five Point is an investment firm focused on building businesses within the environmental water management 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. As of December 31, 2024, Five Point had approximately $8 billion of assets under management. Five Point indirectly owns a majority of our common shares and owns a majority of the equity interests in WaterBridge and Desert Environmental 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, 2024:
•our five largest customers, which consisted of WaterBridge, ConocoPhillips, EOG Resources, Occidental Petroleum and PowLan comprised 65% of total revenue;
•our 10 largest customers comprised 78% of total revenue; and
•45% of total revenue was from customers with an investment grade credit rating.
During the year ended December 31, 2024, 48% of our total revenues came from three significant customers, WaterBridge, ConocoPhillips, and EOG Resources.
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, 2024, 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 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 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, 2024, 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, 2024, were generated by resource royalties and brackish water sales, with resource royalties generated during the year ended December 31, 2024, 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, 2024. 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, 2024, 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 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.
We are party to a lease development agreement with PowLan, which includes a non-refundable $8.0 million deposit paid in December 2024 for a two-year site selection and pre-development period. See “-Material Contracts and Marketing” for further information on our agreement with PowLan.
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, 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 universe 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.
•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.”
•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.”
•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.”
•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:
•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;
•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 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;
•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;
•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;
•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
•surface use agreements with Desert Reclamation LLC and Safefill Pecos, LLC, each a subsidiary of Desert Environmental, 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 oilfield reclamation and solid waste 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.
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, a sand mine, non-hazardous oilfield reclamation and solid waste facilities, a data center and a cryptocurrency facility, as of December 31, 2024. 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.
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 four full-time personnel exclusively providing field services on our surface acreage and three 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 have and expect to maintain a minimal number of employees. As of December 31, 2024, 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 our 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 relationships with WaterBridge and Desert Environmental.
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.
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:
•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 relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;
•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;
•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;
•the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
•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;
•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;
•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;
•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
•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 founded upon the pre-2015 regulations and incorporated updates based on existing Supreme Court decisions, including considerations based on regional and geographic differences. However, this rule has been subject to legal challenge and is currently enjoined in Texas. 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. In Sackett, the Supreme Court significantly narrowed the scope of waters of the United States from its earlier jurisprudence by holding that, under the CWA, the word “waters” refers only to geographical features that are described in ordinary parlance as “streams, rivers, oceans, and lakes” and adjacent wetlands that are indistinguishable from those bodies of water due to a continuous surface connection. 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, we cannot predict what actions the incoming Trump Administration may take with respect to any of these regulations and the timing with respect to the same. As a result, there is significant uncertainty with respect to wetlands regulations under the CWA at this time. To the extent, however, any rule or regulation expands the scope of the CWA’s jurisdiction, we, WaterBridge, Desert Environmental 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 and Desert Environmental, 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 have filed litigation over this 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. However, the review remains ongoing and is not expected to be complete before the EPA’s five-year cycle for NAAQS review in December 2025. Further, on October 29, 2024, the EPA entered into a consent decree with environmental litigants that requires the EPA to issue a final NAAQS for nitrogen oxides by November 10, 2028.
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.
The EPA has, in recent years, made considerable efforts to regulate GHG emissions from oil and natural gas operations, including 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”) amends the CAA to impose a fee on the emission of 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. The IRA also imposes a federal fee on the emission of GHGs through a methane emissions charge, including onshore petroleum and natural gas production. In May 2024, the EPA issued a final rule to implement the IRA’s methane fee, which starts at $900 per metric ton of waste emissions in 2024, increasing to $1,200 for 2025, and $1,500 for 2026 and beyond, and only applies to emissions that exceed the statutorily specified levels. These regulations and methane emissions charges could increase costs for our customers and, indirectly, adversely affect our results of operations, cash flows and financial position. However, we cannot predict whether, how, or when the Trump Administration might take action to revise or repeal the methane emissions charge or the finalized EPA rules related to GHG emissions. Additionally, Congress may take actions to repeal or revise the IRA, including with respect to the methane emissions charge, which timing or outcome similarly cannot be predicted.
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. The TRRC in 2014, for instance, issued a “well integrity rule” which updated the requirements for drilling, completing and cementing wells. The rule also included new testing and reporting requirements, such as the requirement to submit cementing reports after well completion or after cessation of drilling (whichever is later) and imposition of additional testing on wells less than 1,000 feet below usable groundwater. States could also elect to place certain prohibitions on hydraulic fracturing. Further, 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.
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, and the litigation remains ongoing in the U.S. District Court for the Western District of Texas. 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.”
Oil, Natural Gas and NGL Data
Proved Reserves
Evaluation of Proved Reserves. Our proved reserves estimates as of December 31, 2024 and 2023 are based on reserves reports prepared by W.D. Von Gonten & Co. (“Von Gonten”), our independent petroleum engineers. The reports of Von Gonten contain further discussion of the reserves estimates and their preparation procedures.
Von Gonten was founded in 1995 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.. Within Von Gonten, the technical persons primarily responsible for preparing the reserves estimates set forth in the reserves reports incorporated herein are William D. Von Gonten, Jr., President, and Travis C. Swanson, Petroleum Engineer. Mr. Von Gonten has served as President of Von Gonten since its founding in November 1995. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and natural gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Mr. Von Gonten graduated from Texas A&M University in 1988 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE). Mr. Swanson has been an employee of, and served as a petroleum engineer for, Von Gonten since June 2011 and has approximately 14 years of prior industry experience. Mr. Swanson graduated from Texas A&M University in 2011 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE). Both Mr. Von Gonten’s and Mr. Swanson’s responsibilities include reserves and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis.
Both Messrs. Von Gonten and Swanson meet or exceed the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Von Gonten does not have any ownership in any of our properties, and no portion of Von Gonten’s compensation is directly dependent on the quantity of reserves booked. A summary of Von Gonten’s reports with respect to our proved reserves estimates as of December 31, 2024 and 2023 are included as exhibits to this Annual Report.
Our management team works closely with Von Gonten to ensure the integrity, accuracy and timeliness of the data used to estimate our reserves. Members from our management team meet with our independent petroleum engineers periodically during the period covered by the reserves reports to discuss the assumptions and methods used in the reserves estimation process. We provide historical information to Von Gonten for our properties, such as ownership interest, oil and natural gas production and commodity prices. Our
Chief Accounting Officer oversees our reserve estimates process, and directly reports to our Chief Executive Officer who is responsible for overseeing the review of our reserve estimates.
The preparation of our reserves estimates were reviewed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserves estimations, include the following:
•review and verification of historical production data, which data is based on actual production as reported by our operators;
•review by our Chief Accounting Officer of all of our reported reserves, including the review of all significant reserves changes and all new PUD additions;
•review and verification of net revenue interests, costs inputs applicable to ownership interests and reasonableness of other cost assumptions impacting the economic life of the reserves;
•review of reserves estimates by our Chief Accounting Officer or by personnel under his direct supervision; and
•direct reporting responsibilities by our Chief Accounting Officer to our Chief Executive Officer
Estimation of Proved Reserves. In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our proved reserves as of December 31, 2024 and 2023 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserves estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for our properties, due to the abundance of analog data.
To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, decline curve analysis, geophysical interpretation, log analysis, volumetric calculations, core analysis, reservoir simulation and historical well cost and operating expense data.
Summary of Reserves. The following table presents our estimated net proved reserves as of December 31, 2024 and 2023, based on our proved reserves estimates as of such date, which have been prepared by Von Gonten, our independent petroleum engineers, in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States.
Year Ended December 31,
2024 (1)
2023 (1)
Estimated proved developed reserves:
Oil (MBbls)
Natural Gas (MMcf)
4,010
2,957
NGL (MBbls)
Total (Mboe) (2)
1,739
1,495
Estimated proved undeveloped reserves:
Oil (MBbls)
Natural Gas (MMcf)
2,000
2,278
NGL (MBbls)
Total (Mboe) (2)
1,279
1,418
Estimated proved reserves:
Oil (MBbls)
1,619
1,696
Natural Gas (MMcf)
6,010
5,235
NGL (MBbls)
Total (Mboe) (2)
3,018
2,913
(1)	Our reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The average WTI benchmark prices for both oil and NGL was $75.48 per barrel and $78.22 per barrel as of December 31, 2024 and 2023, respectively. The average Henry Hub spot price for natural gas was $2.13 per MMBtu and $2.64 per MMBtu as of December 31, 2024 and 2023, respectively. After consideration of pricing differentials such as gravity, quality, local conditions, gathering, transportation fees and distance from market, the average realized product prices over the remaining lives of the properties are $73.83 per barrel of oil, $20.38 per barrel of NGL, and $0.93 per MMBtu of natural gas as of December 31, 2024. The average realized product prices over the remaining lives of the properties were $76.40 per barrel of oil, $24.45 per barrel of NGL, and $1.67 per MMBtu of natural gas as of December 31, 2023.
(2)	We present our total reserves on an Mboe basis, calculated at the rate of one barrel of oil per six Mcf of natural gas based upon the relative energy content. This is an energy content correlation and does not reflect the price or value relationship between oil and natural gas.
Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserves estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net cash flows are based on a number of variables and assumptions, including geologic interpretation, prices and future production rates and costs, all of which may vary from actual results. Please read “Risk Factors.”
Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this Annual Report and the proved reserves reports as of December 31, 2024 and 2023, which are included as exhibits to this Annual Report.
PUDs
The following table summarizes our changes in PUDs during the years ended December 31, 2024 and 2023. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Oil
Natural Gas
NGL
Proved Undeveloped Reserves
(MBbls)
(MMcf)
(MBbls)
(Mboe)
Balance, January 1, 2023
1,154
3,151
1,889
Acquisitions of reserves
-
-
-
-
Extensions and discoveries
-
-
-
-
Divestiture of minerals in place
-
-
-
-
Revisions of previous estimates
(23
)
(82
)
(6
)
(42
)
Transfers to estimated proved developed
(244
)
(791
)
(53
)
(429
)
Balance, December 31, 2023
2,278
1,418
Acquisitions of reserves
-
-
-
-
Extensions and discoveries
-
-
-
-
Divestiture of minerals in place
-
-
-
-
Revisions of previous estimates
(5
)
(32
)
(2
)
(13
)
Transfers to estimated proved developed
(69
)
(246
)
(16
)
(126
)
Balance, December 31, 2024
2,000
1,279
Changes in our PUDs that occurred during the year ended December 31, 2023 were primarily due to:
•negative revisions of previous estimates of approximately 42 Mboe. 42 Mboe decrease was due to changes in commodity prices; and
•transfers of approximately 429 Mboe due to five gross well locations that were previously categorized as proved undeveloped but were drilled during the year resulting in the addition of proved developed reserves.
Changes in our PUDs that occurred during the year ended December 31, 2024 were primarily due to:
•negative revisions of previous estimates of approximately 13 Mboe. 13 Mboe decrease due to changes in commodity prices; and
•transfers of approximately 126 Mboe due to two gross well locations that were previously categorized as proved undeveloped but were drilled during the year resulting in the addition of proved developed reserves.
As a mineral and royalty interests owner, we do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the working interest owners. As a result, during the year ended December 31, 2024, we did not have any expenditures to convert PUDs to proved developed reserves.
We identify drilling locations based on an assessment of current geologic, engineering and land data. This includes drilling space unit formation and current well spacing information derived from state agencies and the operations of the E&P companies drilling our mineral and royalty interests. We generally do not have evidence of approval of our operators’ development plans, however we use a deterministic approach to define and allocate locations to proved reserves. In preparing our assessment, Von Gonten reviewed publicly available geological information or engineering data that it gathered and historical production data provided by operators, or otherwise publicly available information of or related to the operators of the reserves underlying our acreage, including the number of drilling rigs such operators are operating on and around our land, the drilling permits issued to such operators on or in proximity to our acreage and information disclosed by such operators regarding their drilling and development programs and their announced capital expenditure budgets and availability of liquidity. Von Gonten then compared such information against the historical drilling and development programs and trends of such operators, such as their historical conversion rates and development trends, for consistency and reasonableness relative to past practice and the then existing commodity price environment, as well as other economic conditions. In addition, our personnel confer informally from time to time with such operators to understand whether our expectations regarding their drilling and development activities are consistent with their near-term drilling schedules. Further, in providing its estimates, Von
Gonten classifies proved reserves based on locations that are economically producible from a known reservoir at existing economic and operating conditions, the consideration of economic inputs, including commodity prices, contract differentials and prevailing development and operating costs in the region as of the date of the assessment, only including reserves associated with locations that are direct offsets to productive wells or units in accordance with SEC definitions with respect to proved undeveloped locations.
While many of our locations qualify as geologic PUDs, we limit our PUDs to the quantities of oil and natural gas that are reasonably certain to be recovered in the next five years. In accordance with SEC rules, our PUDs are only booked if they relate to wells that we reasonably expect, based on the above described assessment, to be scheduled to be drilled within five years after the date of booking. As of December 31, 2024 and 2023, approximately 42% and 49% of our total proved reserves were classified as PUDs, respectively.
Oil, Natural Gas and NGLs Production Prices and Costs
Production and Price History
The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:
Year Ended December 31,
2024 (1)
2023 (1)
Net royalty production volumes:
Oil (MBbls)
Natural Gas (MMcf)
NGL (MBbls)
Equivalents (MBoe)(2)
Average realized prices:
Oil ($/Bbl)
$
74.56
$
76.17
Natural gas ($/Mcf)
0.91
2.34
NGLs ($/Bbl)
20.91
19.44
Equivalents ($/Boe)(2)
$
41.33
$
49.10
Average costs ($/Boe):
Severance and ad valorem taxes
$
3.31
$
2.97
Transportation, processing and other
0.25
0.15
Net realized ($/Boe)
$
37.77
$
46.33
(1)	May not sum or recalculate due to rounding.
(2)	We present our total production on an Mboe basis, calculated at the rate of one barrel per six Mcf based upon the relative energy content. This is an energy content correlation and does not reflect the price or value relationship between oil and natural gas.
Productive Wells
Productive wells consist of producing horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. The table below sets forth our productive wells as of December 31, 2024 and 2023. All of our productive wells are gross productive horizontal wells.
Years Ended December 31,
Gross
Net
Gross
Net
Oil
1.9
1.7
Natural gas
1.5
1.5
Total
3.4
3.2
We do not own any working interests in any wells. Accordingly, we do not own any net wells as such term is defined by Item 1208(c)(2) of Regulation S-K.
Acreage
The table below sets forth historical information about our developed and undeveloped gross mineral acres and net royalty acres as of December 31, 2024 and 2023.
Years Ended December 31,
Gross Mineral Acres
Weighted Average Lease Royalty Percentage
Net Royalty
Acres
Gross Mineral Acres
Weighted Average Lease Royalty Percentage
Net Royalty
Acres
Developed
1,749
23.1
%
1,775
23.9
%
Undeveloped
2,675
24.5
%
2,405
23.9
%
Total
4,424
23.9
%
1,059
4,180
23.9
%
The table below sets forth our leased and unleased gross mineral acres as of December 31, 2024 and 2023.
Years Ended December 31,
Gross Mineral Acres
%
Gross Mineral Acres
%
Leased
3,660
82.7
%
3,520
84.2
%
Unleased
17.3
%
15.8
%
Total gross mineral acres
4,424
100.0
%
4,180
100.0
%
Drilling Results
The table below sets forth information related to wells drilled on our acreage during the years ended December 31, 2024 and 2023, gross and net wells turned to production. As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage underlying our mineral interests during the relevant periods.
Years ended December 31,
Productive Gross
Dry
-
-
Total
Productive Net
0.2
0.7
Organizational Structure; Availability of Information
LandBridge was formed on September 27, 2023 as a Delaware limited liability company. We are a holding company and our sole material 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 additional offices in Midland, Texas.
The following diagram reflects our current simplified organizational structure as of December 31, 2024.
* 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: (254) 776-3722. 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 and the New York Stock Exchange (the “NYSE”), 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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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business. The risks described below are not the only ones that we face. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations. This information should be considered carefully, together with other information in this Annual Report and other reports and materials we file with the SEC. If any of these risks were to occur, our business, financial condition, results of operations or liquidity and the trading price of our Class A shares could be materially adversely affected.
Risks Related to Our Business and Operations
Our revenues are substantially dependent on ongoing oil and natural gas exploration, development and production activity on or around our land. If E&P companies do not maintain drilling, completion and production activities on or around our land, the demand for the use of our land and resources, as well as the royalties we receive from the production of oil and natural gas and related activities on our land, could be reduced, which could have a material adverse effect on our results of operations, cash flows and financial position.
We are not an E&P company, and we have no control over the oil and natural gas development activity on or around our land. The willingness and ability of E&P companies to continue development activities on and around our land is dependent on a variety of factors that are outside of their and our control, including:
•the demand for and supply of oil and natural gas;
•the capital costs required for drilling, completion and production activities, which could be significantly more than anticipated;
•the ability to access, and cost of, capital;
•prevailing oil and natural gas prices;
•the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
•the producers’ expected return on investment in wells drilled on or around our land as compared to opportunities in other areas; and
•regulatory developments.
The SUAs we enter into and the sand, brackish water and other resources that we or our customers sell are substantially dependent on drilling, completion and production activities by E&P companies on or around our acreage. Similarly, the services WaterBridge and Desert Environmental provide from which we earn royalties and fees are substantially dependent on those same activities. If E&P companies do not maintain such activities on or around our land, their demand for the use of our land and resources and WaterBridge’s and Desert Environmental’s services will decline, negatively impacting our results of operations, cash flows and financial position.
Demand for the use of our land and resources, as well as the services provided by WaterBridge and Desert Environmental, depends substantially on capital spending by producers to construct and maintain infrastructure on and around our acreage and explore for, develop and produce oil and natural gas in the area. These expenditures are generally dependent on such producers’ overall financial position, capital allocation priorities and ability to access capital, and their views of future demand for, and prices of, oil and natural gas. 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. This, in turn, could lead to lower demand for the use of our land and resources or WaterBridge’s and Desert Environmental’s services, delays in payment of, or nonpayment of, amounts that are owed to us and cause lower rates and lower utilization of our land. In addition, we own oil and gas royalty interests that generate revenue based on oil and natural gas prices and production. As a result, a significant decrease in the price of oil and natural gas or decrease in levels of production of oil and natural gas on and around our land could adversely affect our results of operations, cash flows and financial
position. For additional information, please see “-The willingness of E&P companies to engage in drilling, completion and production activities on and around our land is substantially influenced by the market prices of oil and natural gas, which are highly volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our results of operations, cash flows and financial position.”
For the year ended December 31, 2024, we received revenue from approximately 186 customers, and our top ten customers represented 78% of our total revenues. While we expect these revenue streams to be recurring, our contracts with our significant customers, which represent a large portion of our revenues, typically do not contain minimum volume 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. Our producers make all decisions as to investments in, and production from, their wells, and our revenues are dependent upon decisions made by such producers, among other factors. For example, we cannot control whether a producer chooses to develop a property or the success of drilling and development activities, which depend on a number of factors under the control of such producer. There can be no assurance that such producers will take actions or make decisions that will be beneficial to us, which could result in adverse effects on our results of operations, cash flows and financial position.
The willingness of E&P companies to engage in drilling, completion and production activities on and around our land is substantially influenced by the market prices of oil and natural gas, which are highly volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our results of operations, cash flows and financial position.
Market prices for oil and natural gas are volatile and a decrease in prices could reduce drilling, completion and production activities by producers on or around our land, resulting in a reduction in the use of our land and resources and WaterBridge’s and Desert Environmental’s services, as well as the amount of revenues we receive from the production of oil and natural gas. The market prices for oil and natural gas are subject to U.S. and global macroeconomic and geopolitical conditions, among other things, and, historically, have been subject to significant price fluctuations and may continue to change in the future. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control and the control of producers on or around our land, such as:
•general market conditions, including macroeconomic trends, inflation, interest rates and associated policies of the Federal Reserve;
•the domestic and foreign supply of and demand for oil and natural gas;
•the price and quantity of foreign imports and U.S. exports of oil and natural gas;
•market expectations about future prices of oil and natural gas;
•oil and natural gas drilling, completion and production activities and the cost of such activities;
•political and economic conditions and events domestically and in foreign oil and natural gas producing countries, including embargoes, increased hostilities in the Middle East, and other sustained military campaigns, the Russia-Ukraine war, as well as the Israel-Hamas conflict, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;
•the ability of and actions taken by members of OPEC+ and other oil-producing nations in connection with their arrangements to maintain oil prices and production controls;
•the impact on worldwide economic activity of an epidemic, outbreak or other public health event;
•the level of consumer product demand and any efforts that may negatively impact the future production of oil and natural gas;
•weather conditions, such as winter storms, fires, earthquakes and flooding, and other natural disasters;
•the level of U.S. domestic oil and natural gas production;
•U.S. and non-U.S. governmental regulations and energy policy, including environmental initiatives and taxation;
•changes in global and domestic political and economic conditions, both generally and in the specific markets in which we operate, including the impact related to changing U.S. and foreign trade policies, such as increased trade restrictions or tariffs;
•the effects of litigation;
•physical, electronic and cybersecurity breaches;
•the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation infrastructure;
•technological advances affecting energy consumption, energy storage and energy supply;
•the price and availability of alternative fuels and any efforts to transition to a low-carbon economy; and
•the impact of energy conservation efforts.
These factors have at times resulted in, and may in the future result in, a reduction in global economic activity and volatility in the global financial markets and make it extremely difficult to predict future oil and natural gas price movements with certainty. A sustained decline in oil and natural gas prices may reduce the amount of oil and natural gas that can be produced economically by producers on or around our land, which may reduce such producers’ willingness to develop such land and use our land and resources and WaterBridge’s and Desert Environmental’s services. Producers on or around our land could also determine during periods of low oil and natural gas prices to shut-in or curtail production from wells on such land, or plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. The scale and duration of the impact of these factors cannot be predicted but could lead to an increase in our customers’ operating costs or a decrease in our or our customers’ revenues, and any substantial decline in the price of oil and natural gas or prolonged period of low oil and natural gas prices may materially and adversely affect our results of operations, cash flows and financial position.
Future land acquisitions would expose us to risks associated with acquisitions and the commercialization of additional acreage.
We may pursue opportunistic future land acquisitions that we expect to complement or expand our current land position. We may not be able to identify attractive acquisition opportunities, and even if we do so, we may not be able to complete the acquisition on commercially acceptable terms, or at all. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or at all, or successfully acquire such identified acreage.
The process of integrating acquired acreage may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to realize the anticipated benefits of our acquisitions could have a material and adverse effect on our results of operations, cash flows and financial position. The successful acquisition and integration of acreage requires an assessment of several factors, including:
•the availability of brackish water and the suitability of the land for produced water handling;
•proximity to recoverable oil and natural gas reserves and the level of drilling, completion and production operations of the target acreage;
•presence of minable sand;
•future oil and natural gas prices and their applicable differentials;
•potential environmental and other liabilities;
•any restrictive covenants or other use restrictions that would prohibit or restrict the ability to engage in certain activities on the target land; and
•regulatory, permitting and other similar matters, including condemnation proceedings.
The accuracy of these assessments is inherently uncertain. Although we will perform a review of the subject acreage that we believe to be generally consistent with industry practices, the accuracy of these assessments is inherently uncertain and may not reveal all existing or potential problems or fully assess their deficiencies and capabilities. Inspections may not always be performed on the totality of such acreage, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.
Because a significant portion of our future revenue growth is expected to be derived from WaterBridge and Desert Environmental, any development that materially and adversely affects either of their businesses, operations or financial condition could have a material adverse impact on us.
WaterBridge is, and Desert Environmental is anticipated to be, among our most significant customers and are expected to play an increasingly important role in our financial performance over the long term. Accordingly, we are indirectly subject to the business risks faced by WaterBridge and Desert Environmental. Because a significant portion of our revenues is derived from WaterBridge and Desert Environmental, any development that materially and adversely affects either of WaterBridge’s or Desert Environmental’s businesses, operations or financial condition could have a material adverse impact on us.
In addition, WaterBridge does not own all of the land on which its infrastructure is located and certain portions of such infrastructure located outside of our land are subject to leases, rights-of-way and easements with third parties. Such infrastructure is necessary to deliver produced water volumes to facilities on our land and if WaterBridge were to lose these rights or be required to relocate its infrastructure, our business could be materially and adversely affected as a result of produced water delivery interruptions. If WaterBridge is unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, it may not be able to construct and operate its assets as anticipated, or at all, which could negatively affect our results of operations, cash flows and financial position.
Our reliance on WaterBridge and its personnel to manage and operate our business exposes us to certain risks.
Pursuant to the Shared Services Agreement, WaterBridge provides general and administrative services, as well as limited operational and maintenance services to us, together with four dedicated employees providing field services and three dedicated employees providing corporate services. Our success depends on the efforts, experience, diligence, skill and network of business contacts of such personnel and the quality of services that WaterBridge offers. However, the allocation of such resources is generally within WaterBridge’s discretion. We can offer no assurance that WaterBridge will continue to provide services to us or that we will continue to have access to WaterBridge’s personnel or that the Manager will be able to recruit and retain personnel necessary to provide us with key services. If the Shared Services Agreement is terminated and no suitable replacement is found to provide management and operating services for our land, or if the Manager is unable to recruit and retain those personnel necessary to perform services under the Shared Services Agreement, we may not be able to execute our business plan, and our results of operations, cash flows and financial position may be materially and adversely affected.
We rely on a small number of key individuals, certain of whom have responsibilities with affiliated entities, whose absence or loss could adversely affect our business, and difficulty attracting and retaining experienced personnel could reduce our competitiveness and prospects for future success.
The successful operation and growth of our business depends to a large extent on a small number of individuals to whom many key responsibilities within our business have been assigned. Such individuals hold positions with our affiliates, including Five Point, WaterBridge and Desert Environmental, and dedicate a portion of their time and resources to the activities of such affiliates, and there can be no assurance as to the future allocation of time and resources between our business, on the one hand, and our affiliates in which our employees, other service providers, and management team hold an interest, on the other hand. We rely on our key personnel for their knowledge of the energy industry, relationships within the industry and experience in operating a business in the Permian Basin. The loss of the services of one or more of these key personnel, and the inability to recruit or retain additional key personnel, could have an adverse effect on our business. Further, we do not have currently a succession plan for the replacement of, and do not maintain “key-person” life insurance policies on, such key personnel.
In addition, our business and the success thereof is also dependent, in part, on our ability and the ability of the Manager to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated due to competition within the broader energy industry. Other companies may be able to offer better compensation and benefits packages to attract and retain such personnel. If we or the Manager cannot retain experienced personnel or attract additional experienced personnel, our ability to compete in our industry could be harmed, which could materially and adversely affect our results of operations, cash flows and financial position.
Our acreage is located in the Permian Basin, making us vulnerable to risks associated with geographic concentration in a single geographic area.
Our acreage is located in the Permian Basin in Texas and New Mexico making us vulnerable to risks associated with geographic concentration in that basin. In particular, we and our customers may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from oil and natural gas wells in this area, availability of equipment, facilities, personnel or services, market limitations, governmental regulation and political activities, processing or transportation
capacity constraints, natural disasters, adverse weather conditions, water shortages or other drought related conditions or interruption of the processing or transportation of oil and natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Delaware Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions.
Additionally, our brackish water sales and sand royalties may be adversely affected by risks associated with our geographic concentration, including the presence of a limited number of potential customers on or near our land, competition with adjacent landowners to provide an attractive development site for such resources, particularly if such landowners are closer to the location of oil and natural gas development activity, and legislation or regulatory initiatives limiting the utilization of brackish water and sand in the Permian Basin.
We have a limited operating history, and an investment in our Class A shares is highly speculative. Because we have a limited operating history, it may be difficult to evaluate our ability to successfully implement our business strategy.
Our predecessor for accounting purposes, OpCo, was formed in September 2021, and, accordingly, we have a limited operating history and track record. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the future value of our Class A shares and may make it difficult to assess our ability to operate profitably. Our future results will be dependent on, among other things, a number of factors and trends discussed in the “Business” section and the risks discussed elsewhere in this “Risk Factors” section, as well as our ability to execute our business model. Our business model may not be successful, and if unsuccessful, we may be unable to modify it in a timely and successful manner.
Because of our limited operating history, our business model and the attractiveness of our acreage to our customers, as well as the performance of any other future assets, are not yet proven. As a result, it may be difficult to evaluate our business and results of operations to date and to assess our future prospects.
In addition, we may encounter risks and difficulties experienced by companies whose performance is dependent upon newly acquired assets, such as failing to integrate, or realizing the expected benefits of, such assets. As a result of the foregoing, we may be less successful in achieving a consistent revenue base capable of generating cash flows from operations compared with a company that has a longer operating history. In addition, we may be less equipped to identify and address risks and hazards in the conduct of our business than those companies that have longer operating histories.
We may experience difficulty in achieving and managing future growth.
Future growth may place strains on our resources, possibly negatively affecting our results of operations, cash flows and financial position. Our ability to grow will depend on a number of factors, including:
•investment by our customers in infrastructure on or around our land;
•the amount of brackish water use and associated prices for such brackish water;
•the results of drilling operations on and in proximity to our land;
•future and existing limitations imposed by law or environmental regulations;
•oil and natural gas prices;
•our ability to develop existing and future projects, including sand mines, solar projects and data centers;
•our ability to identify and acquire additional acreage;
•our or the Manager’s ability to continue to retain and attract skilled personnel, and our ability to contract for the services of key personnel who are sufficiently dedicated to performing services with respect to our business;
•our ability to maintain or enter into new relationships with customers;
•our or our customers’ ability to obtain rights from our neighboring landowners on economic terms, or at all, to gain access to our land or transport resources, such as sand and brackish water, away from our land, to their point of end use; and
•our access to, and cost of, capital in the event we pursue future acquisitions.
We may also be unable to make attractive acquisitions, which could inhibit our ability to grow, or we could experience difficulty commercializing any acquired acreage. It may be difficult to identify attractive acquisition opportunities and, even if such opportunities are identified, our existing and/or future debt agreements contain, or may contain, limitations on our ability to enter into certain transactions, which could limit our future growth.
We may not be successful in pursuing additional commercial opportunities on our land from non-hydrocarbon based energy production and other users.
One of our strategies is to expand the use of our land by customers not engaged in hydrocarbon-based energy development. We may not be able to correctly identify such commercial opportunities or may be unsuccessful in attracting industry participants to develop projects on our land. For example, we are party to a lease development agreement pursuant to which the counterparty holds an option to develop a data center and related facilities on our land; however, we can offer no assurance that the counterparty will lease the site, nor can there be any assurance that such counterparty will be successful in its efforts to develop the data center or any power generation facilities.
The rapidly evolving and competitive nature of many of the industries we are targeting for such development makes it difficult to evaluate the future prospects of these projects. In addition, we have limited insight into emerging trends that may adversely affect the development of such projects on our land or otherwise, and the developers of these projects, if they were to materialize, would encounter the risks and difficulties frequently experienced by growing companies and project developers in rapidly changing industries, including, unpredictable and volatile revenues, increased expenses, an uncertain regulatory environment, novel litigation and corresponding outcomes and changes in business conditions. The viability of this business strategy and the resulting demand for the use of our land and its resources by such project developers will be affected by many factors outside of our control and may not be successful.
The construction by our customers of new infrastructure on our land is subject to regulatory, construction, supply chain and other risks common in the development and operation of facilities and other infrastructure.
We intend to grow our business through revenues from SUAs or other contracts pursuant to which our customers develop infrastructure on our land. These infrastructure projects involve numerous regulatory, environmental, political and legal uncertainties, including political opposition by environmental groups, local groups and other advocates. Such opposition can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our customers’ operations, intervention in regulatory or administrative proceedings related to our customers’ permitting efforts or otherwise involving their assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our customers’ assets or their business. There can be no assurance that such infrastructure will be developed at all or that our customers will complete these projects on schedule or at an economical cost, and we may not realize the anticipated benefits of such projects.
Our customers may also encounter technical difficulties during the construction of such infrastructure leading to a reduction in capacity or a shorter useful life. Moreover, our customers may undertake expansion projects to capture anticipated future growth that does not materialize or for which they are unable to acquire new customers. As a result, the new facilities and infrastructure developed by our customers on our acreage may not be able to attract enough demand to achieve their expected investment return, which could materially and adversely affect our results of operations, cash flows and financial position.
In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits our customers require to conduct their operations to be withheld, delayed or burdened by requirements that restrict our customers’ ability to profitably conduct their business. Any such event that delays or otherwise interrupts the revenues generated by our customers’ operations, or which causes them to make significant expenditures not covered by insurance, could adversely affect their payments to us in respect of use of existing infrastructure as well as future development of infrastructure on our land.
Technological advancements in connection with alternatives to hydraulic fracturing could decrease the demand for our brackish water sales and WaterBridge’s produced water transportation and handling operations on our land.
Wide-scale development of techniques to recycle produced water for use in completion activities or otherwise could adversely affect the amount of produced water transported to and handled on our land, which could materially and adversely affect our results of operations, cash flows and financial position. Some E&P companies are focusing on developing and utilizing non-water fracturing techniques, including those utilizing propane, carbon dioxide or nitrogen instead of water. If producers in the Permian Basin begin to
shift their fracturing techniques to waterless fracturing in the development of their wells, our brackish water sales could be materially and negatively impacted.
Inadequate brackish water supplies could have a material adverse effect on our revenues.
One of our significant sources of revenue is the sale of brackish water for use in oil and natural gas drilling and completion operations. Our ability to meet the existing and future demand for brackish water depends on an adequate supply of such brackish water from our acreage. Additionally, regulatory restrictions on the use of brackish water and the development of brackish water wells, lack of available water rights, drought, overuse of sources of water, protection of threatened species or habitats or other factors may limit the availability of brackish water. No assurance can be given that we will be able to produce enough brackish water to fully satisfy future customer demand.
If we are unable to produce adequate brackish water supplies, our results of operations, cash flows, and financial position may be adversely affected by, among other things, the following:
•a reduction in the amount of brackish water we sell and reduced revenues therefrom;
•an increase in operating costs; and
•an increase in capital expenditures associated with building pipelines to connect to alternative sources of brackish water supply, new wells to replace those that are no longer in service or are otherwise inadequate to meet the needs of customers, and reservoirs and other facilities to conserve or reclaim water.
We may or may not be able to recover increased operating and capital costs as a result of water shortages on a timely basis, or at all.
Our proved undeveloped reserves may not ultimately be developed or produced by the operators of our mineral and royalty interests or may take longer to develop than anticipated.
As of December 31, 2024, 1,739 Mboe of our 3,018 Mboe total estimated proved reserves, or 58%, were proved developed reserves. Our remaining total estimated proved reserves are classified as PUDs and may not be ultimately developed or produced by the operators of our mineral and royalty interests. Conversion of PUDs into producing volumes requires significant capital expenditures and successful drilling and development by such operators. The reserve data included in the reserves reports of Von Gonten, our independent petroleum engineer, assume that substantial capital expenditures by such operators are required to develop such PUDs. See “Business-Oil, Natural Gas and NGL Data-PUDs.” We cannot be certain that the estimated costs of the development of these PUDs are accurate, that our operators will develop the properties underlying our mineral and royalty interests in accordance with any publicly announced schedule or that the results of such development will be as estimated. The development of our PUDs may take longer than expected as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, lack of proximity to and shortage of capacity of transportation facilities, equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services and compliance with governmental requirements, and may require higher levels of capital expenditures from the operators than anticipated. Delays in the development of our PUDs, increases in costs to drill and develop PUDs or decreases or continued volatility in commodity prices will reduce the future net cash flows of our estimated undeveloped reserves and may result in some projects becoming uneconomic for the operators of our mineral and royalty interests.
Sand operations are subject to operating risks that are often beyond the control of the mine operator. These risks can adversely affect production levels and costs, which could adversely affect sand production from our acreage.
We do not operate the sand mines on our land, but our customers who conduct such operations are subject to risks normally encountered in the mining industry generally and the sand mining industry in particular. These risks include:
•changes in the price and availability of transportation, natural gas or electricity;
•unanticipated ground, grade or water conditions;
•unusual or unexpected geological formations or pressures;
•pit wall failures or surface rock falls;
•inclement or hazardous weather conditions;
•environmental hazards and industrial accidents;
•changes in applicable laws and regulations (or the interpretation thereof);
•inability to maintain necessary permits or mining or water rights;
•restrictions on blasting operations;
•inability to obtain necessary mining or production equipment or replacement parts;
•fires, explosions or industrial accidents or other accidents;
•technical difficulties or key equipment failures;
•labor disputes;
•late delivery of supplies; and
•facility shutdowns in response to environmental regulatory actions.
Any of these risks could result in damage to current and future mining properties or production facilities on our land, personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Any prolonged downtime or shutdowns at any of the mining properties or production facilities on our acreage could have a material adverse effect on our results of operations, cash flows and financial position.
In addition, transportation and related logistics costs are a significant component of the total delivered cost of sand for oil and natural gas operations. As a result, the cost of transporting sand to the well site is a key factor in our customers’ purchasing decisions. The development of additional in-basin sand mines that are closer to areas of drilling activity could reduce demand for sand produced from our acreage. For example, a number of companies have announced plans to develop or acquire, are currently developing or expanding, or have recently acquired or completed sand mine projects in the Delaware Basin that may be closer to ongoing development activity. Any such reduction in demand for sand from our land could materially affect our results of operations, cash flows and financial position.
Interruption of our customers’ supply chains could negatively impact our business and operations as well as reduce our revenues.
Any material interruption in our customers’ supply chains, such as a material interruption of the resources required to drill and complete oil and natural gas wells, to construct produced water pipelines on our land and otherwise construct infrastructure and extract resources from our land, such as those resulting from interruptions in service by the third-party providers or common carriers that ship goods within our customers’ distribution channels, trade restrictions, such as changing U.S. and foreign trade policies relating to increased trade restrictions or tariffs, embargoes or customs restrictions, social or labor unrest, natural disasters, epidemics or pandemics or political disputes and military conflicts that cause a material disruption in our customers’ supply chains, could have a negative impact on our business and our profitability. In the event of disruptions in our customers’ supply chains, the labor and materials they rely on in the ordinary course of business may not be available at reasonable rates or at all.
Any such supply disruption could adversely affect activity levels on or around our land or significantly delay construction and development on our land, which could materially and adversely affect our results of operations, cash flows and financial position.
Operational disruptions on or around our land from weather, natural disasters, terrorism or other similar causes could impact our results of operations, cash flows and financial position.
A natural disaster (such as an earthquake, tornado, fire or flood) or an act of terrorism could damage or destroy our customers’ infrastructure on or around our land or result in a disruption of operations on or around our land.
Additionally, our land is located in the Permian Basin, which may be adversely affected by earthquakes and adverse weather conditions. During periods of heavy rain or extreme weather conditions such as tornados or after other disruptive events such as earthquakes or wildfires, we or our customers may be unable to access our land and our customers’ infrastructure may be damaged. Such disruptions could materially and adversely affect our results of operations, cash flows and financial position.
Global incidents, such as world health events, could have a similar effect of disrupting our or our customers’ businesses to the extent they reach and impact the service areas on or around our land, the availability of supplies our customers need, the customers we or our customers serve, or the employees or other personnel who operate our or our customers’ businesses.
Any such destruction of or damage to infrastructure or interruptions of operations could materially and adversely affect our results of operations, cash flows and financial position.
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.
Our or our customers’ ability to conduct operations is subject to a variety of required permits from various governmental authorities, which may limit such operations, including those associated with oil and natural gas drilling, completion and production activities, disposal or transport of produced water and other hazardous materials or wastes or oilfield wastes, construction, stormwater, water use, air emissions, mining, and other activities that may be conducted in association with operations on our acreage. The public often has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our or our customers’ operations may not be issued, maintained, or renewed, may not be issued or renewed in a timely fashion, or may involve requirements that restrict our or our customers’ ability to economically conduct operations. Limitations on our or our customers’ ability to conduct operations due to the inability to obtain or renew necessary permits or similar approvals could materially and adversely affect our results of operations, cash flows and financial position.
The deterioration of the financial condition of our customers could adversely affect our business, and the termination of activities on or around our land by one or more significant customers could materially and adversely affect our results of operations, cash flows and financial position.
For the year ended December 31, 2024, revenues from WaterBridge, ConocoPhillips and EOG Resources each individually comprised more than 10% of our total revenues and collectively represented 48% of our total revenues. EOG Resources, WaterBridge and Occidental Petroleum each individually comprised 19%, 15% and 14% of our total accounts receivable for the year ended December 31, 2024 and collectively represented 48% of our total accounts receivable at such date. No other customer accounted for more than 10% of our total revenues or outstanding accounts receivables.
We expect to continue to depend on key customers to support our revenues for the foreseeable future, and although each of WaterBridge, ConcoPhillips and EOG Resources operates on our land under long-term contracts, each of these customers has the right to reduce or cease operations on our acreage at their sole discretion under certain circumstances, as our contracts with such customers generally do not contain minimum commitment provisions for land use or brackish water volumes to be purchased. See “Business-Customers; Material Contracts and Marketing” for further information on our agreements with our significant customers. The loss of revenue derived from any of these customers’ operations on our land could adversely affect our results of operations, cash flows and financial position. During times when the oil and natural gas markets weaken, our customers are more likely to experience financial difficulties, including generating less cash flow due to lower oil and natural gas prices and being unable to access or receive favorable terms in connection with debt or equity financing, which could result in a reduction in our customers’ activities on or around our land. 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 location of such customer’s operations and such customer’s need for the use of our land and resources. Our customers are limited to entities operating on and around our acreage in the Delaware Basin.
We cannot assure you that any of our customers will continue to do business with us. If these customers do not maintain their activities on or around our land, their demand for use of our land and resources will be reduced. The loss of revenue from key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could materially and adversely affect our results of operations, cash flows and financial position.
We may experience delays in the payment of royalties and fees and be unable to replace customers or producers that do not make required payments to us, and we may not be able to terminate our agreements with defaulting customers that declare bankruptcy.
We may experience delays in receiving royalty, fee and other payments from our customers or producers. A failure on the part of a producer to make royalty payments typically gives us the right to terminate the lease agreement, repossess the property and enforce payment obligations under the agreement. If we repossessed any of our mineral interests, we would seek a replacement producer. However, we might not be able to find a replacement producer and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, with respect to a customer or producer that is subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), our right to enforce or terminate the agreement for any defaults, including nonpayment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code,
the bankrupt customer or producer would have a substantial period of time to decide whether to ultimately reject or assume our agreement, which could prevent the execution of a new agreement or the assignment of the existing agreement to another customer or producer. In the event that the customer or producer rejected the agreement, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new agreement with a new customer or producer, the replacement customer or producer may not achieve the same levels of activity on or around our land at the same price as the customer or producer it replaced.
Additionally, we are subject to the risk of loss resulting from nonpayment or nonperformance by our customers of their respective obligations. Although we maintain policies and procedures to limit such risks, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them of their respective obligations and our inability to collect on outstanding payables or find substitute customers could have an adverse effect on our results of operations, cash flows and financial position. A decline in oil and natural gas prices could negatively impact the financial condition of our customers and sustained lower prices could impact their ability to meet their obligations to us. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could adversely affect our results of operations, cash flows and financial position.
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, cash flows and financial position.
Concerns over global economic conditions, global health threats, trade policies, increased trade restrictions and tariffs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, interest rates, the availability and cost of credit and the United States financial markets and other factors have contributed to increased economic uncertainty. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, with a general decline beginning in the second half of 2022 and a relative settling in in 2023 and 2024. In addition, the incoming presidential administration has stated an intention to impose tariffs on international goods, such as those produced in China. To the extent that any U.S. trade policy results in retaliatory tariffs against the U.S., such as the recently announced tariffs from China on U.S. natural gas and crude oil, such developments could result in inflationary pressures and have an adverse effect on our customers’ business, and reduce demand for use of our land and services, which could have a material adverse effect on our business, results of operations and financial condition. Though we incorporate inflation escalators in most of our long-term customer contracts, contractual provisions providing for inflation escalators in certain contracts are subject to caps, which may limit the amount of any single pricing increase, and may also vary as to the commencement date of such increases and the timing and calculation of the applicable adjustment. As a result, inflation may outpace the revenue adjustments provided by those provisions. Our customers may also experience supply chain constraints, due to international trade policies or otherwise, and inflationary pressure on their cost structures, which could impact the revenues we receive from them. Our customers also may face shortages of equipment, raw materials, supplies, commodities, labor and services, which may prevent them from executing their development plans on or around our land. These supply chain constraints, trade policies and inflationary pressures may continue to adversely impact our customers’ operating costs and, if they are unable to manage their supply chain, it may impact their ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could materially and adversely affect the revenues received in respect of our customers’ operations on or around our land.
In addition, hostilities related to the Russia-Ukraine war, as well as the Israel-Hamas conflict and heightened tensions in the Middle East, and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These and other factors, such as declining business and consumer confidence, may contribute to an economic slowdown and a recession. Concerns about global economic health also have a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for oil and natural gas products could diminish, which could impact operations on or around our land, affect the ability of our customers to continue operations and ultimately adversely impact our results of operations, cash flows and financial position.
We may be subject to claims for personal injury and property damage, catastrophic events, and those related to contamination resulting from our customers’ operations, which could materially and adversely affect our results of operations, cash flows and financial position.
Our customers will be subject to all of the hazards and operating risks associated with their operations, which include oil and natural gas drilling, completion and production activities, sand mining, production and distribution of brackish water, water handling, waste disposal, construction and operation of non-hazardous oilfield reclamation and solid waste facilities, power storage, microgrids,
cryptocurrency mining, fuel stations, battery and/or solar facilities, and any other operations that may occur on our acreage. These hazards may include the risk of fire, explosions, blowouts, seismic events, surface cratering, uncontrollable flows of crude oil, natural gas, NGLs and produced water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as crude oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases, release of hazardous materials into the environment, and worker health and safety issues. The occurrence of any of these events could result in substantial losses to our customers due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
In addition, litigation arising from operations on our acreage may cause us to be named as a defendant in lawsuits asserting potentially large claims, including claims for defense, indemnity, and exemplary damages. We generally seek indemnity 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, but such indemnity and insurance may not be adequate to cover our liabilities, and we are not fully protected or insured against all risks.
Subject to certain exceptions, our customers assume responsibility for, including control and removal of, all other pollution or contamination that may result from their operations on our acreage, such as Desert Environmental’s oil reclamation, solid waste and landfill operations. We may have liability in such cases if we are grossly negligent or commit willful acts, or as owners of the land under laws that impose strict, joint and several liability for pollution clean-up, such as CERCLA (as defined herein). Our customers generally agree to indemnify and defend us against claims relating to contamination resulting from their operations and related closure and remedial obligations, damage or loss of a well, reservoir, geological formation, underground strata, or water resources, or the loss of oil, natural gas, mineral, or water, but sometimes such indemnity and defense is subject to exceptions for claims for gross negligence or willful misconduct, and we may not be able to collect under these indemnities if the applicable customer is in financial distress. Our customers also generally assume responsibility for claims arising from their employees’ personal injury or death, or the damage or loss of their property, to the extent that their employees are injured or their properties are damaged by operations on our acreage, but sometimes such indemnity and defense is subject to exceptions for claims resulting from our gross negligence or willful misconduct, and we may not be able to collect under these indemnities if the applicable customer is in financial distress. However, we might not succeed in enforcing such contractual risk allocation or might incur an unforeseen liability falling outside the scope of such risk allocation.
The occurrence of any of these events could result in interruption of our customers’ operations or substantial losses to us or our customers, which could materially and adversely affect our results of operations, cash flows and financial position.
Our insurance coverage may not fully cover our losses, and we may in the future encounter increased costs related to, and lack of availability of, insurance.
While we maintain insurance coverage at levels that we believe to be reasonable and prudent, we can provide no assurance that our current levels of insurance will be sufficient to cover any losses that we have incurred or may incur in the future, whether due to deductibles, coverage challenges or other limitations. Additionally, we may not be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. Additionally, insurance will not cover many types of interruptions or events that might occur and will not cover all risks associated with our business and may not be available in certain areas in which we operate. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. The occurrence of a significant 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 materially and adversely affect our results of operations, cash flows and financial position.
Cyber incidents or attacks targeting systems and infrastructure used by the oil and natural gas industry may adversely impact our operations, and a cyber incident or systems failure could result in information theft, data corruption or operational disruption and our results of operations, cash flows or financial position may be adversely impacted.
We and our customers, and the energy industry generally, increasingly rely on uninterrupted information technology systems and digital technologies to operate our respective businesses. This reliance extends to the majority of our and our customers’ operations, from monitoring and managing critical infrastructure to processing and storing proprietary and sensitive information. Our information technology systems and networks, and those of our customers, vendors, and other business partners, are subject to damage or interruption from cyberattacks, power outages, computer and telecommunications failures, catastrophic events, such as natural disasters or acts of war or terrorism, usage errors by our employees or other personnel, and other events unforeseen or generally beyond our control. Damage or interruption to information technology systems could result in significant costs and may lead to significant liability, loss of critical data, reputational damage, and disruptions to services or operations.
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cyber incidents, including deliberate attacks, have increased in frequency globally, with energy-related assets particularly at risk. Due to the critical nature of these assets, any such attack on energy infrastructure could result in widespread service disruptions and challenges in maintaining public trust. The U.S. government has issued public warnings that specifically indicate energy assets could be targets of cybersecurity threats. Our technologies and systems, networks, and those of our customers, affiliates, vendors and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized access, release, gathering, monitoring, corruption, misuse, or destruction of proprietary, personal and other information, or other disruption of business operations. Any such event could lead to significant liability, loss of critical data, reputational damage and disruptions to our services or operations.
While we have implemented and maintain commercially reasonable security measures and safeguards, such security measures and safeguards may not be sufficient to protect against an attack. Attackers are increasingly using advances in technologies, such as artificial intelligence and encryption bypasses that may evade our efforts. Emerging artificial intelligence technologies may improve or expand the capabilities of malicious third parties in a way we cannot predict at this time, including being used to develop new hacking tools, exploit vulnerabilities, obscure malicious activities and increase the difficulty detecting threats. Moreover, some of our networks and systems are managed by third-party service providers and are not under our direct control. We regularly enter into transactions with third parties, some of whom may have less sophisticated electronic systems or networks and may be more vulnerable to cyberattacks. Our reliance on these third parties means that any vulnerability in their systems could propagate to our own systems, increasing our risk exposure despite our internal controls.
In addition, certain cyber incidents, such as surveillance, ransomware, deepfake-based social engineering attacks, and credential stuffing, may remain undetected for some period of time, and cyber incidents and attacks are continually evolving and unpredictable. As cyber incidents and attacks continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cybersecurity incidents. While we utilize various procedures and controls to reduce the risk of the occurrence of cyber incidents, there can be no assurance that our business, finances, systems and assets will not be compromised in a cyber incident. Any failure or perceived failure to detect or respond effectively to a cybersecurity incident could lead to significant liability, undermine shareholder and stakeholder trust, and negatively impact business continuity. Furthermore, we are subject to an evolving regulatory landscape, including state, federal, and international data privacy laws that require rigorous cybersecurity standards and standards relating to artificial intelligence. Compliance with various data privacy and cybersecurity regulations may impose significant costs, and any perceived or actual failure to comply could result in regulatory penalties, litigation, and reputational harm.
Reserves estimates depend on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserves estimates or underlying assumptions could materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex, as it is not possible to measure underground accumulation of oil, natural gas or NGLs in an exact way, and requires subjective interpretations of available technical data, estimates and many assumptions, including assumptions relating to economic factors, such as future oil, natural gas and NGL prices, production levels, ultimate recoveries and operating and development cost. Any significant inaccuracies in these interpretations, subjective estimates or assumptions could materially affect our estimated quantities and present value of our reserves and such data may turn out to be incorrect.
Estimates of our reserves and related valuations as of December 31, 2024 and 2023 were prepared by our independent petroleum engineers, Von Gonten. Von Gonten conducted a detailed review of all of our properties for the periods covered by its reserves reports using information provided by us and collected by it. Over time, Von Gonten may make material changes to reserves estimates taking into account the results of actual drilling, testing and production and changes in prices. In estimating our reserves, our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs. A substantial portion of our reserves estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and future royalties generated from oil and natural gas development of our oil and natural gas reserves. Numerous changes over time to the assumptions on which our reserves estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs that are ultimately recovered being different from our reserves estimates.
You should not assume that the present value of future net cash flows from proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements and the Financial Accounting Standards Board, Von Gonten bases the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted average for the first-day-of-the-month closing price for the previous calendar year, and
costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor used when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Our future results following the Recent Acquisitions and other acquisitions will suffer if we do not effectively manage our expanded operations.
Since our formation, the size of our asset base has increased significantly. Our future success will depend, in part, upon our ability to manage this expanded business, which poses substantial challenges for management, including challenges related to the management and monitoring of expanded acreage, new operations and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of the significant increase in the size of our business. There can be no assurances that we will be successful or that we will realize the expected operating efficiencies, cost savings, revenue enhancements or other benefits currently anticipated from the Recent Acquisitions.
Risks Related to Environmental and Other Regulations
Our results of operations, cash flows and financial position are subject to major trends in our industry, such as decarbonization, and may be adversely affected by future developments that are outside of our control.
The value of the revenues we receive from the use of our land and resources by our customers is substantially based on the level of oil and natural gas drilling and production activities. Our revenues may be negatively affected by changes driven by trends such as decarbonization efforts. Such changes may relate to the types or sources of energy in demand, such as a shift to renewable sources of power generation (for example, wind and solar), along with ongoing changes in regulatory, investor, customer and consumer policies and preferences. While we intend to pursue these additional opportunities, we may ultimately be unsuccessful. The evolution of global energy sources is affected by factors out of our control, such as the pace of technological developments and related cost considerations, the levels of economic growth in different markets around the world and the adoption of climate change-related policies. In addition, the possibility of taxes on carbon emissions can affect the demand for crude oil and natural gas and the operating costs for producers on or around our land.
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.
WaterBridge handles large volumes of produced water in connection with its customers’ drilling and production operations pursuant to permits issued by governmental authorities overseeing such produced water handling activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such produced water handling activities. For example, there exists a growing concern that the injection of produced water into certain produced water handling facilities triggers seismic activity in certain areas, including Texas, where a majority of our acreage is located. This has led to the creation of operator-led response plans in certain areas in New Mexico or Texas by the NMOCD and the TRRC, respectively, which can include the TRRC suspending or declining to issue produced water handling permits, restrictions on the amount of material that can be handled, or requiring producers to cease disposal in certain produced water handling facilities.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of produced water into produced water handling facilities, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. The U.S. Geological Survey has recently identified Texas and New Mexico as two of six states with the most significant hazards from induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that produced water handling operations have caused seismic events, caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding produced water handling permits, to assess the relationship between seismicity and the use of such produced water handling facilities. For example, the TRRC has previously published a rule governing permitting or re-permitting of produced water handling facilities that would require, among other things, the submission of information on seismic events occurring within a specified radius of the produced water handling facility location, as well as logs, geologic cross sections and structure maps relating to the water handling area in question. The TRRC has also suspended produced water handling permits and introduced injection volume curtailments within the boundaries of certain Seismic Response Areas (“SRAs”). A significant portion of our acreage
in our Northern Position within New Mexico is currently located within SRAs that limit produced water injection into deep formations, which currently only affects one produced water handling facility on our land. There can be no assurance that additional portions of our acreage will not be included in an SRA in the future. Separately, in November 2021, the NMOCD implemented protocols requiring producers to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event of a certain magnitude occurs within a specified radius of a produced water handling facility. Further, on July 11, 2024, the NMOCD announced the administrative cancellation of 75 pending permit applications for UIC Class II wells within the 10-mile County Line SRA, due to the potential for increased seismicity within the area. The adoption and implementation of any new laws or regulations that restrict our customers’ ability to handle produced water gathered from E&P companies, by limiting volumes, disposal rates, produced water handling facility locations or otherwise, or requiring our customers to shut down produced water handling facilities, could limit existing operations and future development activity in affected areas by our customers, including WaterBridge, and reduce their demand for the use of our land and resources, which could have a material adverse effect on our results of operations, cash flows and financial position.
Additionally, hydraulic fracturing related activities have been linked to subsidence and expansion. Both the injection of produced water into produced water facilities and the extraction of water, oil, natural gas, or mineral resources from the ground can result in surface subsidence and uplifts caused by changes underground (such as, but not limited to, loss of volume and pressure depletion). This has been linked to various geo-and environmental hazards, such as alteration of local ecosystems and impacts upon local communities, to include increased seismic activity and the formation of sinkholes. Any new laws or regulations that may be adopted and implemented with respect to addressing subsidence and expansion risks may lead to restrictions upon our customers’ operations, which could materially and adversely affect our results of operations, cash flows and financial position.
Our reliance on revenue generated from produced water handling activities exposes us to potential regulatory risks.
There are unique risks associated with handling produced water, and the legal requirements related to handling produced water into a non-producing geologic formation by means of produced water handling facilities are subject to change based on concerns of the public or governmental authorities. There remains substantial uncertainty regarding the handling of produced water by means of produced water handling facilities, the regulation of which could materially and adversely affect our customers in a manner that cannot be predicted. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, which could be in produced water, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning produced water handling facilities. Federal or state regulatory agencies could require the shutdown of produced water handling facilities for safety reasons or refuse to permit the restart of any facility after unplanned or planned outages. New or amended safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more capital expenditures to keep produced water infrastructure operating efficiently or in compliance with applicable laws and regulations. Such equipment is also likely to require periodic upgrading and improvement in order to maintain compliance. Although the safety record of produced water handling generally has been very good, accidents and other unforeseen problems have occurred. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a major environmental or catastrophic incident could materially and adversely affect our customers and limit their operations on our land.
The Endangered Species Act (“ESA”) and Migratory Bird Treaty Act (“MBTA”) govern our and our customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new infrastructure on our land.
The ESA and comparable state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. 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 and our customers operate, both our and our customers’ abilities to conduct or expand operations and construct facilities could be limited, or both we and our customers could be forced to incur additional material costs. Additionally, 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 designated two distinct population segments of the lesser prairie chicken under the ESA, which live in certain areas in southeastern New Mexico and western Texas; however, the U.S. Senate voted to rescind this decision, although the joint resolution was vetoed by President Biden, and the listing decision is currently subject to litigation. In May 2024, the FWS designated the dunes sagebrush lizard under the ESA, which also lives in certain areas in southeastern New Mexico and western Texas, and this listing decision is also subject to litigation. 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, which developments could have a material adverse effect on our results of operations, cash flows and financial position.
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.
Concerns over the risk of climate change have increased the focus by global, regional, national, state and local regulators on GHG emissions, including carbon dioxide emissions, and on transitioning to a lower-carbon future. A number of countries and states have adopted, or are considering the adoption of, regulatory frameworks to reduce GHG emissions. These regulatory measures may include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards, prohibitions on the sales of new automobiles with internal combustion engines, and incentives or mandates for battery-powered automobiles and/or wind, solar or other forms of alternative energy. These include laws such as the IRA, which appropriates significant federal funding for renewable energy initiatives and amends the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA, beginning in calendar year 2024 at $900 per ton of methane, increasing to $1,200 in 2025, and set at $1,500 for 2026 and each year after. However, we cannot predict whether, how, or when the incoming Trump Administration might take action to revise or repeal the methane emissions charge rule or the finalized EPA rules related to GHG emissions. Additionally, Congress may take actions to repeal or revise the IRA, including with respect to the methane emissions charge, which timing or outcome similarly cannot be predicted. Compliance with changes in laws, regulations and obligations relating to climate change could result in increased costs of compliance for our customers on or around our land or costs of consuming oil and natural gas for such products, and thereby reduce demand for the use of our land and resources, which could reduce our profitability. Changes in laws and regulations may also result in delays or increased costs associated with obtaining permits needed for oil and natural gas operations. Additionally, our customers on or around our land could incur reputational risk tied to changing customer or community perceptions of our customers or their customers’ contribution to, or detraction from, the transition to a lower-carbon economy. These changing perceptions could lower demand for oil and natural gas products, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries, and could also pressure banks and investment managers to shift investments and reduce lending.
Separately, banks and other financial institutions, including investors, may decide to adopt policies that restrict or prohibit investment in, or otherwise funding, us or our customers on or around our land based on climate change-related concerns, which could affect our and our customers on or around our land’s access to and cost of capital for potential growth projects. Additionally, insurers may decide to raise rates and/or cease insuring us or our customers on or around our land based on climate change-related concerns.
Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. For example, the SEC has adopted a new rule regarding climate change, which it has stayed pending various legal challenges, that, if ultimately made effective, implements significant disclosure obligations and would require us to update and develop our controls to accommodate these new obligations. The incoming Trump Administration, however, may seek to repeal the SEC rule though the timeline for any repeal, if at all, is subject to a number of uncertainties. While we intend to pursue opportunities related to the transition to a lower-carbon economy, there can be no assurance that our efforts will be successful. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on us or our customers’ financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and natural gas industry may affect our results of operations, cash flows and financial position.
Climate variability may cause increased volatility in weather and may impact water usage and related revenue.
The issue of climate variability is receiving increasing attention nationally and worldwide. There is consensus among climate scientists that there will be worsening of weather volatility in the future associated with climate variability. Many climate variability predictions present several potential challenges to the energy industry, including brackish water sales and water services related to oil and natural gas production, such as:
•increased frequency and duration of droughts;
•challenges associated with changes in temperature;
•potential degradation of water quality;
•decreases in available water supply and changes in water usage patterns;
•increased frequency and severity of storms and other weather events;
•increases in disruptions in service; or
•increased costs to reduce risks associated with the increasing frequency and severity of natural events, including to improve the resiliency and reliability of the infrastructure and systems necessary for customers’ water services.
Because of the uncertainty of weather volatility related to climate variability, we cannot predict its potential impact on our or our customers’ business, financial condition, results of operations, cash flows and liquidity. This, in turn, could lead to lower demand, rates and utilization for the use of our land and resources, and delays in payment of, or nonpayment of, amounts that are owed to us. Furthermore, laws and regulations have been enacted that seek to reduce or limit GHG emissions and require additional reporting and monitoring, and these regulations may become more pervasive or stringent in light of changing governmental agendas and priorities, although the exact nature and timing of these changes is uncertain. There can be no assurance that we or our customers would be able to recover any expenditures or costs associated with the impact of climate variability and related laws and regulations on a timely basis, or at all.
Increased investor attention to environmental, social, and governance (“ESG”) matters may impact our or our customers’ business.
Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. Companies that do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected. Increased attention to climate change, increasing and sometimes conflicting societal expectations on companies to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our customers’ products and services, lower demand for the use of our land and resources, reduced profits, increased governmental investigations and litigation against us.
Moreover, certain institutional investors have announced plans to transition their portfolios to net-zero GHG emissions over the next two to three decades as part of a commitment to combat climate change. This has, and will likely continue to result in some (and perhaps a growing number of) institutions removing from their portfolios the shares of companies that do not meet their minimum investment standards. Further, in some cases, banks and other capital providers are reassessing their capital allocation to our or our customers’ industries or making their participation uncertain. Any divestment or limitation of future investment in companies involved in the development, production, transportation and utilization of fossil fuels may adversely affect the price of our shares and limit our access to the debt and equity markets for capital to fund our growth.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on expectations and assumptions or hypothetical scenarios that may be incorrect or may change with the passage of time. Such expectations and assumptions or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many ESG matters. Additionally, voluntary disclosures regarding ESG matters, as well as any ESG disclosures mandated by law, could result in litigation or government investigations or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to adequately pursue or implement ESG strategies or achieve ESG goals or commitments, which are often aspirational, including any GHG reduction or neutralization goals or commitments, could result in litigation and damage our reputation, cause our investors or consumers to lose confidence in us, or otherwise negatively impact our operations. Moreover, even if we voluntarily elect to pursue climate or ESG goals, we cannot guarantee that we will be able to pursue or implement such goals because of potential costs, technical or operational obstacles, uncertainty in long-term assumptions and expectations or other market or technological developments beyond our control. Similarly, we cannot guarantee that participation in any sustainability, climate-related, or ESG certification program or framework will have the intended results on our ESG profile.
In addition, certain organizations that provide proxy advisory services to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by certain investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries, which could have a negative impact on our share price and/or our access to and costs of capital.
Furthermore, certain public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing” (i.e., misleading information or false claims overstating potential ESG benefits). For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including alleged greenwashing. Certain regulators, such as the SEC and various state agencies, as well as non-governmental
organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals, or standards were misleading, false, or otherwise deceptive. Any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. We could also face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny.
Additionally, certain employment practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies.
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.
E&P activities, sand mining, produced water handling, oilfield reclamation, solid waste facilities, landfills and other operations on our land are subject to numerous environmental, health and safety requirements. Our customers may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to their activities on our land. These laws and regulations may require our customers to obtain and maintain a variety of permits, approvals, certificates or other authorizations that govern air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting oil and natural gas or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed, and, in some instances, the issuance of orders or injunctions limiting or requiring discontinuation of certain operations, in each case, which could materially and adversely affect our customers’ operations on our land. Additionally, any failure to comply could result in negative sentiment toward our customers’ business and others in the industry.
Moreover, under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties owned by us even if a customer’s operations caused the contamination. In addition, our customers may be liable for the remediation of contamination at currently or formerly operated facilities and facilities of third parties that received waste generated by our customers’ operations, regardless of whether such contamination resulted from the conduct of others or from consequences of actions that were in compliance with all applicable environmental laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of the operations of our customers. While we seek to mitigate any potential liability we may have through indemnification, customary insurance policies and remediation activities, in each case, required under our contracts, as well as reliance on state funded programs (such as the TRRC’s Orphan Well Program) for coverage of plugging and abandonment liabilities if any of our customers declared bankruptcy or if our insurance policies did not fully cover such liabilities, we may not be fully protected. Additionally, although we generally have rights to inspect our property and the operations thereon, we may not become aware of all environmental, health and safety matters. Moreover, public interest in the protection of the environment has tended to increase over time. The trend of more expansive and stringent environmental legislation and regulations applied to extractive industries such as those our customers engage in could continue resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental actions are taken that restrict drilling or impose more stringent and costly operating, waste handling, disposal and cleanup requirements, our customers’ operations could face increased costs and potential curtailment of operations, which consequently could indirectly materially and adversely affect our business, cash flows, prospects, financial condition or results of operations.
Risks Related to Our Financial Condition
We may be unable to generate sufficient cash to service all of our indebtedness and financial commitments and any future indebtedness could adversely affect our financial condition.
As of December 31, 2024, we had $385.5 million of total debt outstanding. Our ability to make scheduled payments on, or to refinance, our indebtedness and financial commitments depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions including financial, business and other factors beyond our control, and may vary significantly from year to year. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods and we may be unable to generate sufficient cash flow to permit us to pay the principal, premium, if any, and interest on our indebtedness. Any insufficiency may impact our business.
If our cash flows and capital resources are insufficient to fund debt and other obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek to raise additional capital or refinance or restructure our indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be on unfavorable terms, including at higher interest rates, and may require us to comply with more restrictive covenants. The terms of our existing or future debt instruments may restrict us from adopting some of these alternatives. We cannot assure you that any refinancing or restructuring would be possible, that any assets, including land, could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on favorable terms, if at all. In addition, any failure to service our debt, including paying interest or principal on a timely basis, would likely result in a reduction of our credit rating, if any, which could harm our ability to incur additional indebtedness. In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt.
Our indebtedness could have important consequences for you and significant effects on our business, including:
•increasing our vulnerability to adverse changes in general economic, industry and competitive conditions and limiting our ability to address such changes;
•requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund general company and other purposes, including dividend payments;
•restricting us from exploiting business opportunities and making strategic land acquisitions;
•making it more difficult to satisfy our financial obligations, including payments on our indebtedness, and contractual and commercial commitments;
•disadvantaging us when compared to our competitors that have less debt;
•complying with covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; and
•increasing our borrowing costs or otherwise limiting our ability to borrow additional funds for the execution of our business strategy.
Finally, the agreements governing our outstanding indebtedness limit our ability to incur additional debt, but such agreements do not prohibit us from doing so. As a result, we could incur more indebtedness in the future, which would exacerbate the foregoing risks.
We are subject to interest rate risk, which may cause our debt service obligations to increase significantly. The weighted average interest rate on borrowings outstanding under our credit facility as of December 31, 2024 was 8.39% in the case of revolving credit borrowings and 8.47% in the case of term loan borrowings.
Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. The weighted average interest rate on our borrowings outstanding under our credit facility as of December 31, 2024 was 8.39% in the case of revolving credit borrowings and 8.47% in the case of term loan borrowings. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and we would be required to devote more of our cash flow to servicing our indebtedness.
In March 2022, the Federal Reserve began, and continued through 2023, to raise interest rates in an effort to curb inflation. Although the Federal Reserve made cuts to benchmark interest rates, to the extent such rates remain elevated or are increased as a result of inflationary pressures or otherwise, we may continue to experience further financing cost increases if interest rates on borrowings, credit facilities and debt offerings increase, as compared to previous levels. Changes in interest rates, either positive or negative, may also affect the yield requirements of investors who invest in our Class A shares, and the elevated interest rate environment could have an adverse impact on the price of our Class A shares, or our ability to issue equity or incur debt for acquisitions or other purposes.
Changes to applicable tax laws and regulations, exposure to additional income tax liabilities, changes in our effective tax rates or an assessment of taxes resulting from an examination of our income or other tax returns could adversely affect our results of operations, cash flows and financial position, including our ability to repay our debt.
We are subject to various complex and evolving U.S. federal, state and local taxes. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect, and may have an adverse effect on our results of operations, cash flows and financial position, including our ability to repay our debt. The passage of any tax legislation or similar changes in U.S. federal income tax laws could adversely affect our results of operations, cash flows and financial position.
Changes in our effective tax rates or tax liabilities could also adversely affect our results of operations, cash flows and financial position. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:
•changes in the valuation of our deferred tax assets and liabilities;
•expected timing and amount of the release of any tax valuation allowances;
•expansion into future activities in new jurisdictions;
•the availability of tax deductions, credits, exemptions, refunds and other benefits to reduce tax liabilities; and
•tax effects of share-based compensation.
In addition, an adverse outcome arising from an examination of our income or other tax returns could result in higher tax exposure, penalties, interest or other liabilities that could have an adverse effect on our results of operations, cash flows and financial position.
If we fail to comply with the restrictions and covenants in our credit facility or our future debt agreements, there could be an event of default under the terms of such agreements, which could result in an acceleration of payment.
A breach of compliance with any restriction or covenant in our credit facility or any of our future debt agreements could result in a default under the terms of the applicable agreement, and our ability to comply with such restrictions and covenants may be affected by events beyond our control. As a result, we cannot assure you that we will be able to comply with these restrictions and covenants. A default could result in acceleration of the indebtedness and a declaration of all amounts borrowed due and payable, which could have an adverse effect on us and negatively impact our ability to borrow. If an acceleration occurs, we may be unable to make all of the required payments and may be unable to find alternative financing. Even if alternative financing were available at that time, it may not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our credit agreement or such future agreements governing our indebtedness or obtain necessary waivers on satisfactory terms.
Our obligations under our credit facility are secured by a first priority security interest in substantially all of our assets and various guarantees.
The amounts borrowed pursuant to the terms of our credit agreement are secured by substantially all of our and our subsidiaries’ present and after-acquired assets. Additionally, our obligations under our credit facility are jointly and severally guaranteed by us and our material subsidiaries.
As a result of the above, in the event of the occurrence of a default under our credit facility, the administrative agent may enforce its security interests (for the ratable benefit of the lenders under our credit facility and the other secured parties) over our and/or our subsidiaries’ assets that secure the obligations under our credit facility, take control of our assets and business, force us to seek bankruptcy protection, or force us to curtail or abandon our current business plans. If that were to happen, you may lose all, or a part of, your investment in our Class A shares.
We do not currently have in place hedging agreements with respect to oil and natural gas production from our acreage, and we will be exposed to the impact of decreases in the price of oil and natural gas.
We do not currently have in place hedging arrangements to establish, in advance, a price for the sale of the oil and natural gas produced from our acreage. As a result, although we may realize the benefit of any short-term increase in the price of oil and natural gas, we will not be protected against decreases in the price or prolonged periods of low oil and natural prices, which, in combination with all of our acreage being located solely in the Permian Basin, could materially and adversely affect our results of operations, cash flows and financial position. Any future price hedging strategy and future hedging transactions will be determined at our discretion. If we enter into hedging arrangements in the future, it may limit our ability to realize the benefit of rising prices and may result in hedging losses.
Risks Related to Our Corporate Structure and Our Class A Shares
The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a result of the IPO, we became a public company, and, as such, we must comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the NYSE rules, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We are continuing our efforts to:
•institute a more comprehensive compliance function;
•comply with rules promulgated by the NYSE;
•prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
•accurately implement and interpret GAAP;
•institute and enforce new internal policies, such as those relating to insider trading; and
•involve and retain to a greater degree outside counsel and accountants in the above activities.
We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of internal controls over financial reporting. Although we are required to disclose changes made in our internal controls and procedures on a quarterly basis, we are not required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following this Annual Report. Additionally, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” or a “smaller reporting company” under the applicable federal securities laws. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2029, if we are no longer a “smaller reporting company.” Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements will strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
In addition, being a public company subject to these rules and regulations has increased our director and officer liability insurance expenses and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage in the future. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.
If we experience any material weaknesses in the future or otherwise fail to develop or maintain an effective system of internal controls in the future, we may not be able to accurately report our financial condition or results of operations, which may adversely affect investor confidence in us and, as a result, the value of our Class A shares.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results will be harmed. We are required, under Section 404 of the Sarbanes-Oxley Act, to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting beginning in the year following this Annual Report. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. We will take steps to improve control processes as appropriate, validate through testing that controls are functioning as documented, and implement a continuous reporting and improvement process for our internal control over financial reporting. If we identify one or more material weaknesses in our internal control over financial reporting during the evaluation and testing process, we may be unable to conclude that our internal controls are effective.
Additionally, when we cease to be an “emerging growth company” under the federal securities laws, our independent registered public accounting firm may be required to express an opinion on the effectiveness of our internal controls. If we are unable to confirm that our internal control over financial reporting is effective, or if our independent registered public accounting firm is unable to express an unqualified opinion on the effectiveness of our internal controls, we could lose investor confidence in the accuracy and completeness of our financial reports, which could cause the price of our Class A shares to decline.
Our ability to continue to pay dividends to our shareholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.
We are a holding company and will have no material assets other than our equity interest in OpCo, and we do not have any independent means of generating revenue. To the extent OpCo has available cash we intend to cause OpCo to make (i) generally pro rata distributions to all holders of OpCo Units (“OpCo Unitholders”), including us, in an amount at least sufficient to allow us to pay taxes, (ii) additional distributions in an amount generally intended to allow the OpCo Unitholders (other than us) to satisfy their respective income tax liabilities with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions), which additional distributions may be made on a pro rata basis to all OpCo Unitholders (including us) or a non-pro rata basis to OpCo Unitholders (other than us) in redemption of OpCo Units from such holders and (iii) non-pro rata distributions to us in an amount sufficient to cover our public company and other overhead expenses. In addition, as the sole managing member of OpCo, we intend to cause OpCo to make pro rata distributions to all of its unitholders, including to us, in an amount sufficient to allow us to fund dividends to our shareholders in accordance with our dividend policy, to the extent our board of directors declares such dividends. OpCo is a distinct legal entity and may be subject to legal or contractual restrictions that, under certain circumstances, may limit our ability to obtain cash from it. If OpCo is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect our results of operations, cash flows, financial position and ability to fund any dividends.
Although we intend to continue to pay dividends on our Class A shares, we are not obligated to do so. We have not adopted a formal written dividend policy nor have we adopted a dividend policy to pay a fixed amount of cash each quarter in respect of each Class A share or to pay an amount based on the achievement of, or derivable based on, any specific financial metrics such as Free Cash Flow. Dividend payments are not guaranteed and are within the absolute discretion of our board of directors. Our board of directors will take into account general economic and business conditions, our financial condition and results of operations, our cash flows from operations and current and anticipated cash needs, our capital requirements, legal, tax, regulatory and contractual restrictions, and implications of such other factors as our board of directors may deem relevant in determining whether, and in what amounts, to pay such dividends. In addition, our debt agreements may limit the amount of distributions that OpCo’s subsidiaries can make to OpCo and OpCo can make to us and the purposes for which distributions could be made. Any return on investment in our Class A shares may be solely dependent upon the appreciation of the price of our Class A shares on the open market, which may not continue to occur. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Debt Instruments” for further discussion of our debt agreements. Accordingly, we may not be able to pay dividends even if our board of directors would otherwise deem it appropriate. Please see “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities-Dividends” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
LandBridge Holdings has the ability to direct the voting of a majority of our common shares and control certain decisions with respect to our management and business, including certain consent rights and the right to designate more than a majority of the members of our board of directors as long as it and its affiliates beneficially own at least 40% of our outstanding common shares, as well as lesser director designation rights as long as it and its affiliates beneficially own less than 40% but at least 10% of our outstanding common shares. LandBridge Holdings’ interests may conflict with those of our other shareholders.
As of December 31, 2024, LandBridge Holdings owned an aggregate of 53,227,852 Class B shares representing approximately 70% of our voting power. LandBridge Holdings’ beneficial ownership of greater than 50% of our common shares means LandBridge Holdings is able to control matters requiring shareholder approval, including the election of directors, changes to our organizational documents, approval of acquisition offers and other significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A shares will be able to affect the way we are managed or the direction of our business. The interests of LandBridge Holdings with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.
Furthermore, in connection with the consummation of the IPO, we entered into a shareholder’s agreement, dated July 1, 2024 (the “Shareholder’s Agreement”), with LandBridge Holdings, providing that for so long as LandBridge Holdings and certain affiliates beneficially own at least 40% of our outstanding common shares, LandBridge Holdings shall be entitled to designate a number of directors equal to a majority of the board of directors, plus one director; and for so long as LandBridge Holdings and such affiliates beneficially own at least 30%, 20% and 10% of our outstanding common shares, LandBridge Holdings shall be entitled to designate at least three directors, two directors and one director, respectively. So long as LandBridge Holdings is entitled to designate one or more directors and notifies the board of directors of its desire to remove, with or without cause, any director previously designated by it to the board of directors, we are required to take all necessary action to cause such removal. So long as LandBridge Holdings has the right to designate at least one director to our board of directors, it will also have the right to appoint a number of board observers, who will be entitled to attend all meetings of the board of directors in a non-voting, observer capacity, equal to the number of directors LandBridge Holdings is entitled to appoint.
In addition, under our First Amended and Restated Limited Liability Company Agreement (the “Operating Agreement”), for so long as LandBridge Holdings and certain affiliates beneficially own at least 40% of our outstanding common shares, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, the following direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of LandBridge Holdings:
•increasing or decreasing the size of our board of directors, committees of our board of directors or boards and committees of our subsidiaries;
•terminating our chief executive officer or removing the Chairman of our board of directors and/or hiring or appointing either of their successors;
•agreeing to or entering into any transaction that would result in a change of control of the Company or enter into definitive agreements with respect to a change of control transaction;
•incurring debt for borrowed money (or liens securing such debt) in an amount that would result in outstanding debt that exceeds our Adjusted EBITDA for the four quarter period immediately prior to the proposed date of the incurrence of such debt by 4.00 to 1.00;
•authorizing, creating (by way of reclassification, merger, consolidation or otherwise) or issuing any equity securities of any kind (other than pursuant to any equity compensation plan approved by our board of directors or a committee of our board of directors or intra-company issuances among the Company and our subsidiaries);
•making any voluntary election to liquidate or dissolve or commence bankruptcy or insolvency proceedings or the adoption of a plan with respect to any of the foregoing or any determination not to oppose such an action or proceeding commenced by a third party; and
•selling, transferring or disposing of assets outside the ordinary course of business in a transaction or series of transactions with a fair market value in excess of 2% of our Consolidated Net Tangible Assets (as defined in the Operating Agreement) determined as of the end of the most recently completed fiscal quarter or year, as applicable, immediately prior to the proposed date of the consummation of such transaction or such series of transactions.
Additionally, for so long as LandBridge Holdings and certain affiliates beneficially own at least 10% of our outstanding common shares, we and our subsidiaries may not, without the approval of LandBridge Holdings, make any amendment, modification or waiver of our Operating Agreement or any other of our governing documents that materially and adversely affects LandBridge Holdings.
The existence of LandBridge Holdings as a significant shareholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in the best interests of our company. Moreover, LandBridge Holdings’ concentration of share ownership may adversely affect the trading price of our Class A shares to the extent investors perceive a disadvantage in owning shares of a company with a significant shareholder.
In addition, LandBridge Holdings may have different tax positions from us that could influence its decisions regarding whether and when to support the disposition of assets and the incurrence or refinancing of new or existing indebtedness. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration LandBridge Holdings’ tax or other considerations, which may differ from the considerations of our other shareholders.
LandBridge Holdings, Five Point and WaterBridge, as well as their affiliates, are not limited in their ability to compete with us, and may benefit from opportunities that might otherwise be available to us.
Our Operating Agreement provides that our officers and directors and their respective affiliates and LandBridge Holdings, Five Point and WaterBridge, as well as their officers, directors and affiliates (each an “Unrestricted Party”), are not restricted from owning assets or prohibited from engaging in other businesses or activities, including those that might be in direct competition with us, and that we renounce any interest or expectancy in any business opportunity that may from time to time be presented to them that would otherwise be subject to a corporate opportunity or other analogous doctrine under Delaware General Corporation Law (the “DGCL”). In addition, the Unrestricted Parties may compete with us for investment opportunities and may own an interest in entities that compete with us. In particular, our Operating Agreement, subject to the limitations of applicable law, provides, among other things, that (i) the Unrestricted Parties may conduct business that competes with us and may make investments in any kind of property in which we may make investments, and (ii) if any of the Unrestricted Parties acquire knowledge of a potential business opportunity, transaction or other matter, they have no duty, to the fullest extent permitted by law, to communicate such offer to us, our shareholders or our affiliates.
We may refer any conflicts of interest or potential conflicts of interest involving any of the Unrestricted Parties to a conflicts committee, which must consist entirely of independent directors, for resolution. Additionally, our board of directors adopted a written related party transactions policy relating to the approval of related party transactions, pursuant to which any such transactions, including transactions with the Unrestricted Parties, will be reviewed and approved or ratified by our Audit Committee or such conflicts committee or pursuant to the procedures outlined in such policy.
LandBridge Holdings may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. Furthermore, LandBridge Holdings, Five Point and WaterBridge, are not required to utilize facilities located on our land in connection with any business opportunities, whether currently existing or arising in the future, and may pursue development opportunities with competing landowners, or pursue an alternative land position without informing us of such opportunity or offering such opportunity to us. This renouncing of our interest and expectancy in any business opportunity may create actual and potential conflicts of interest between us and LandBridge Holdings, Five Point and WaterBridge, and result in less than favorable treatment of us and our shareholders if attractive business opportunities are pursued by LandBridge Holdings, Five Point and WaterBridge, for its own benefit rather than for ours.
Certain of our directors and officers may have significant duties with, and spend significant time serving, other entities, including entities that may compete with us in seeking acquisitions and business opportunities, and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors and officers, who are responsible for managing our business may hold positions of responsibility with other entities, including those that are in the energy industry. The existing and potential positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us and may also otherwise require attention and time that could otherwise be devoted to our business. These directors and officers may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, such directors and officers may present potential business opportunities to other entities prior
to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and, as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our or your best interests.
A significant reduction by LandBridge Holdings of its ownership interests in us could adversely affect us.
We believe that LandBridge Holdings’ ownership interest in us provides it with an economic incentive to assist us to be successful. LandBridge Holdings is not subject to any obligation to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If LandBridge Holdings sells all or a substantial portion of its ownership interests in us, it may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our results of operations, cash flows and financial position.
The U.S. federal income tax treatment of dividends on our Class A shares to a holder will depend upon our tax attributes and the holder’s tax basis in our common shares, which are not necessarily predictable and can change over time, and could cause taxable gain or loss on the sale of our Class A shares to be more or less than expected.
Amounts we distribute to our shareholders with respect to our Class A shares, which we refer to as “dividends,” will constitute “dividends” for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent such distribution amounts exceed our current and accumulated earnings and profits, such distributed amount will be treated as a non-taxable return of capital to the extent of a holder’s tax basis in our Class A shares and thereafter as capital gain from the sale or exchange of such shares.
If a holder sells its Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A shares. To the extent that the amount of our dividends is treated as a non-taxable return of capital as described above, such dividends will reduce a holder’s tax basis in the Class A shares. Consequently, such excess dividends will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares or subsequent dividends with respect to such shares. Additionally, with regard to U.S. corporate holders of our Class A shares, to the extent that a dividend on our Class A shares exceeds both our current and accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the corporate dividends-received deduction (to the extent it would otherwise be applicable to such holder) with respect to the gain resulting from such excess dividend.
Prospective investors in our Class A shares are encouraged to consult their tax advisors regarding the tax consequences of receiving dividends on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.
The Internal Revenue Service (“IRS”) Forms 1099-DIV that our shareholders receive from their brokers may over-report dividend income with respect to our Class A shares for U.S. federal income tax purposes, and failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a shareholder’s U.S. federal income tax return. For non-U.S. holders of our Class A shares, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a shareholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.
Dividends we pay with respect to our Class A shares will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Dividends we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a shareholder’s tax basis in their Class A shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our dividends that is a “dividend” for U.S. federal income tax purposes.
For a U.S. holder of our Class A shares, the IRS Forms 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a shareholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify our shareholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our shareholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a shareholder’s tax return.
For a non-U.S. holder of our Class A shares, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate unless an applicable income tax treaty provides for a lower rate or the dividends are effectively connected with conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our dividends that is a “dividend” for U.S. federal income tax purposes, or a shareholder’s broker or withholding agent chooses to withhold taxes from dividends in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a
shareholder’s broker or other withholding agent may overwithhold taxes from dividends paid. In such a case, a shareholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
For as long as we are an emerging growth company and/or a smaller reporting company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We currently are taking advantage of the exemptions described above. We have also elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(2) of the JOBS Act. This election allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result, our financial statements may not be comparable to companies that comply with public company effective dates, and our shareholders and potential investors may have difficulty in analyzing our operating results if comparing us to such companies. We will remain an emerging growth company until the last day of the fiscal year following the fifth anniversary of the IPO, or such earlier time that we have more than $1,235.0 billion of revenues in a fiscal year, have more than $700.0 million in market value of our Class A shares held by non-affiliates (and have been a public company for at least 12 months), or issue more than $1.0 billion of non-convertible debt over a three-year period.
Additionally, we qualify as a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K under the Securities Act. Smaller reporting companies may take advantage of certain reduced disclosure obligations, including, among other things, providing only two years of audited financial statements in their periodic reports. We will remain a smaller reporting company until the last day of the fiscal year in which: (i) the market value of our common shares held by non-affiliates equals or exceeds $250 million as of the end of that fiscal year’s second fiscal quarter; or (ii) our annual revenues equal or exceed $100 million during such completed fiscal year and the market value of our common shares held by non-affiliates equals or exceeds $700 million as of the end of that fiscal year’s second fiscal quarter. To the extent we take advantage of such reduced disclosure obligations, it may also make comparison of our financial statements with other public companies difficult or impossible.
To the extent that we rely on any of the exemptions available to emerging growth companies and/or smaller reporting companies, you will receive less information about our financial position, executive compensation and internal control over financial reporting than issuers that are not emerging growth companies or smaller reporting companies. Additionally, we intend to take advantage of the extended transition periods for the adoption of new or revised financial accounting standards under the JOBS Act until we are no longer an emerging growth company. Our election to use the transition periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the extended transition periods permitted under the JOBS Act and who will comply with new or revised financial accounting standards.
If some investors find our Class A shares to be less attractive as a result, there may be a less active trading market for our Class A shares and our Class A share price may be more volatile.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A shares or if our operating results do not meet their expectations, our share price could decline.
The trading market for our Class A shares is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our share price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrades our Class A shares or if our operating results do not meet their expectations, our Class A share price could decline.
The market price of our Class A shares could be adversely affected by sales of substantial amounts of our Class A shares in the public or private markets or the perception in the public markets that these sales may occur, including sales by LandBridge Holdings after the exercise of the Redemption Right.
As of December 31, 2024, we had 23,255,419 Class A shares and 53,227,852 Class B shares outstanding. Future sales by LandBridge Holdings after the exercise of the Redemption Right (as described in the OpCo LLC Agreement) or sales by other large holders of our Class A shares in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our Class A shares or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to LandBridge Holdings and certain other shareholders. In January 2024, we registered the resale of 59,058,271 Class A shares (including Class A shares to be issued upon redemption of a corresponding number of Class B shares) by certain selling shareholders, including LandBridge Holdings, pursuant to certain registration rights agreements. Furthermore, we filed a registration statement with the SEC on Form S-8 providing for the registration of 3,960,000 Class A shares issued or reserved for issuance under the LandBridge Company LLC Long Term Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144 under the Securities Act, shares registered under the registration statement on Form S-8 have been made available for resale immediately in the public market without restriction. Alternatively, we may be required to undertake a future public or private offering of Class A shares and use the net proceeds from such offering to purchase an equal number of OpCo Units, with the cancellation of a corresponding number of Class B shares, from LandBridge Holdings.
In December 2024, we closed the December Private Placement, pursuant to which certain persons reasonably believed to be accredited investors or qualified institutional buyers purchased an aggregate 5,830,419 Class A shares from us at a price per share of $60.03.
We may sell additional Class A shares in future offerings. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.
LandBridge Holdings holds a majority of the voting power of our common shares. As a result, we are a controlled company within the meaning of the NYSE rules. Under the NYSE rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:
•a majority of the board of directors consists of independent directors as defined under the rules of the NYSE;
•the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
•the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
These requirements will not apply to us as long as we remain a controlled company. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation and nominating and governance committees. We currently utilize all of these exemptions. Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of the rules of the NYSE.
Our Operating Agreement, as well as Delaware law, contains provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A shares and deprive our investors of the opportunity to receive a premium for their shares.
Our Operating Agreement authorizes our board of directors to issue preferred shares without shareholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof,
including dividend rights, voting rights, rights and terms of redemption, redemption prices and liquidation preferences of such series. If our board of directors elects to issue preferred shares, it could be more difficult for a third party to acquire us.
In addition, certain provisions of our Operating Agreement could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders. Among other things, such provisions of our Operating Agreement include:
•providing that after LandBridge Holdings and certain of its affiliates no longer beneficially own or control the voting of more than 40% of our outstanding common shares (the “Trigger Event”), our board of directors will be divided into three classes that are as nearly equal in number as is reasonably possible and each director will be assigned to one of three classes, with each class of directors elected for a three-year term to succeed the directors of the same class whose terms are then expiring; provided that LandBridge Holdings shall have the right to designate the initial class assigned to each director immediately following the occurrence of the Trigger Event;
•prohibiting cumulative voting in the election of directors;
•providing that after the Trigger Event, the affirmative vote of the holders of not less than 66 2/3% in voting power of all then-outstanding common shares entitled to vote generally in the election of our board of directors, voting together as a single class, will be required to remove any director from office, and such removal may only be for “cause”;
•providing that after the Trigger Event, all vacancies, including newly created directorships, may, except as otherwise required by the terms of the Shareholder’s Agreement, law or, if applicable, the rights of holders of a series of preferred shares, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum, or by a sole remaining director;
•providing that after the Trigger Event, shareholders will not be permitted to call special meetings of shareholders;
•providing that after the Trigger Event, our shareholders may not act by written consent and may only act at a duly called annual or special meeting;
•establish advance notice procedures with respect to shareholder proposals and nominations of persons for election to our board of directors, other than nominations made by or at the direction of our board of directors or any committee thereof; and
•providing that a majority of our board of directors is expressly authorized to adopt, or to alter or repeal our Operating Agreement.
Pursuant to our Operating Agreement, for so long as LandBridge Holdings beneficially owns at least 40% of our outstanding common shares, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, certain direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of LandBridge Holdings.
Our Operating Agreement designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, other personnel or agents.
Our Operating Agreement provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery of the State of Delaware does not have jurisdiction, the Superior Court of the State of Delaware, or, if the Superior Court of the State of Delaware does not have jurisdiction, the United States District Court for the District of Delaware, in each case, subject to that court having personal jurisdiction over the indispensable parties named defendants therein) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees, other personnel, or agents to us or our shareholders, (iii) any action asserting a claim against us or any director or officer or employee or other personnel of ours arising pursuant to any provision of the Delaware Limited Liability Company Act (the “Delaware LLC Act”) or our Operating Agreement or (iv) any action asserting a claim against us or any director, officer, employee or other personnel of ours that is governed by the internal affairs doctrine. Our Operating Agreement also provides that, to the fullest extent permitted by applicable law, the United States District Court for the District of Delaware will be the sole and exclusive forum for resolving any complaint asserting a cause of action under the Securities Act. This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. Any person or entity purchasing or otherwise acquiring any interest in our common shares will be deemed to have notice of, and consented to, the provisions of our Operating Agreement described in the preceding sentence. This choice of
forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees, other personnel or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Operating Agreement inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our results of operations, cash flows and financial position.
There are certain provisions in our Operating Agreement regarding fiduciary duties of our directors, exculpation and indemnification of our officers and directors and the approval of conflicted transactions that differ from the DGCL in a manner that may be less protective of the interests of our public shareholders and restricts the remedies available to shareholders for actions taken by our officers and directors that might otherwise constitute breaches of fiduciary duties if we were subject to the DGCL.
Our Operating Agreement contains certain provisions regarding exculpation and indemnification of our officers and directors and the approval of conflicted transactions that differ from the DGCL in a manner that may be less protective of the interests of our public shareholders. For example, our Operating Agreement provides that to the fullest extent permitted by applicable law our directors or officers will not be liable to us. In contrast, under the DGCL, a director or officer would be liable to us for (i) breach of duty of loyalty to us or our shareholders, (ii) intentional misconduct or knowing violations of the law that are not done in good faith, (iii) improper redemption of shares or declaration of dividends or (iv) a transaction from which the director derived an improper personal benefit.
Pursuant to our Operating Agreement and indemnification agreements, we must indemnify our directors and officers for acts or omissions to the fullest extent permitted by law. In contrast, under the DGCL, a corporation can only indemnify directors and officers for acts and omissions if the director or officer acted in good faith, in a manner he or she reasonably believed to be in or not opposed to the best interest of the corporation, and, in a criminal action, if the officer or director had no reasonable cause to believe his or her conduct was unlawful.
Additionally, our Operating Agreement provides that in the event a potential conflict of interest exists or arises between any of our directors, officers, equity owners or their respective affiliates, including LandBridge Holdings, on the one hand, and us, any of our subsidiaries or any of our public shareholders, on the other hand, a resolution or course of action by our board of directors shall be deemed approved by all of our shareholders, and shall not constitute a breach of the fiduciary duties of members of our board of directors to us or our shareholders, if such resolution or course of action (i) is approved by a conflicts committee, which is composed entirely of independent directors, (ii) is approved by shareholders holding a majority of our common shares that are disinterested parties, (iii) is determined by our board of directors to be on terms that, when taken together in their entirety, are no less favorable than those generally provided to or available from unrelated third parties or (iv) is determined by our board of directors to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). In contrast, under the DGCL, a corporation is not permitted to exempt board members from claims of breach of fiduciary duty under such circumstances.
Accordingly, our Operating Agreement may be less protective of the interests of our public shareholders, when compared to the DGCL, insofar as it relates to the exculpation and indemnification of our officers and directors.
We are a holding company. Our sole material asset is our equity interest in OpCo, and accordingly, we will be dependent upon distributions from OpCo to pay taxes and cover our corporate and other overhead expenses.
We are a holding company and have no material assets other than our equity interest in OpCo. We have no independent means of generating revenue. To the extent OpCo has available cash and subject to the terms of any debt instruments or other applicable agreements, we intend to cause OpCo to make (i) generally pro rata distributions to OpCo Unitholders, including us, in an amount at least sufficient to allow us to pay our taxes, (ii) at the election of certain holders of OpCo Units, additional distributions in an amount generally intended to allow such OpCo Unitholders to satisfy their respective income tax liabilities with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions), which additional distributions may be made on a pro rata basis to all OpCo Unitholders (including us) or a non-pro rata basis to OpCo Unitholders (other than us) in redemption of OpCo Units from such holders and (iii) non pro rata distributions to us in an amount at least sufficient to reimburse us for our corporate and other overhead expenses. In addition, as the sole managing member of OpCo, we intend to cause OpCo to make pro rata distributions to all of its unitholders, including us, in an amount sufficient to allow us to fund dividends to our shareholders in accordance with our dividend policy, to the extent our board of directors declares such dividends. Therefore, although we expect to pay dividends on our Class A shares in amounts determined by our board of directors, from time to time, our ability to do so may be limited to the extent OpCo and its subsidiaries are limited in their ability to make these and other distributions to us. To the extent that we need funds and OpCo or its subsidiaries are restricted from making distributions under applicable law or under the terms of any current or future financing or other arrangements or are otherwise unable to provide such funds, our results of operations, cash flows and financial position could be materially and adversely affected.
In certain circumstances, OpCo will be required to make tax distributions to OpCo Unitholders, and such tax distribution may be substantial. To the extent we receive tax distributions in excess of our actual tax liabilities and retain such excess cash, the OpCo Unitholders would benefit from such accumulated cash balances if they exercise their Redemption Right.
Pursuant to the OpCo LLC Agreement, OpCo will make generally pro rata distributions to the OpCo Unitholders, including us, in an amount sufficient to allow us to satisfy our actual tax liabilities. In addition, to the extent OpCo has available cash, OpCo will be required to make additional pro rata tax distributions to all OpCo Unitholders in an amount generally intended to allow the OpCo Unitholders (other than us) to satisfy their assumed tax liabilities with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions and as determined by OpCo). For this purpose, the determination of available cash will take into account, among other factors, (i) the existing indebtedness and other obligations of OpCo and its subsidiaries and their anticipated borrowing needs, (ii) the ability of OpCo and its subsidiaries to take on additional indebtedness on commercially reasonable terms and (iii) any necessary or appropriate reserves.
The amount of such additional tax distributions will be determined based on certain assumptions, including assumed income tax rates, and will be calculated after taking into account other distributions (including other tax distributions) made by OpCo. Additional tax distributions may significantly exceed the actual tax liability for many of the OpCo Unitholders, including us. If we retain the excess cash we receive from such distributions, the OpCo Unitholders would benefit from any value attributable to such accumulated cash balances as a result of their exercise of the Redemption Right. However, we intend to take steps to eliminate any material excess cash balances, which could include, but are not necessarily limited to, a distribution of the excess cash to holders of our Class A shares or the reinvestment of such cash in OpCo for additional OpCo Units.
In addition, the tax distributions that OpCo may be required to make may be substantial, and the amount of any additional tax distributions OpCo is required to make likely will exceed the tax liabilities that would be owed by a corporate taxpayer similarly situated to OpCo. Funds used by OpCo to satisfy its obligation to make tax distributions will not be available for reinvestment in our business, except to the extent we or certain other OpCo Unitholders use any excess cash received to reinvest in OpCo for additional OpCo Units. In addition, because cash available for additional tax distributions will be determined taking into account the ability of OpCo and its subsidiaries to take on additional borrowing, OpCo may be required to increase its indebtedness in order to fund additional tax distributions. Such additional borrowing may adversely affect our results of operations, cash flows and financial position by, without limitation, limiting our ability to borrow in the future for other purposes, such as capital expenditures, and increasing our interest expense and leverage ratios.
If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result.
We intend to operate such that OpCo does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of OpCo Units pursuant to the Redemption Right (or our Call Right (as described in the OpCo LLC Agreement)) or other transfers of OpCo Units could cause OpCo to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of OpCo Units qualify for one or more such safe harbors. For example, we intend to limit the number of OpCo Unitholders, and the OpCo LLC Agreement provides for limitations on the ability of OpCo Unitholders to transfer their OpCo Units and provides us, as managing member of OpCo, with the right to impose restrictions (in addition to those already in place) on the ability of OpCo Unitholders to redeem their OpCo Units pursuant to the Redemption Right to the extent we believe that it is necessary to ensure that OpCo will continue to be treated as a partnership for U.S. federal income tax purposes.
If OpCo were to become a publicly traded partnership, significant tax inefficiencies might result for us and for OpCo, including as a result of our inability to file a consolidated U.S. federal income tax return with OpCo.
Because we have elected to take advantage of the extended transition period pursuant to Section 107 of the JOBS Act, our financial statements may not be comparable to those of other public companies.
Section 107 of the JOBS Act provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. Accordingly, our financial statements may not be comparable to companies that comply with public company effective dates, and our shareholders and potential investors may have difficulty in analyzing our operating results by comparing us to such companies.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B.	Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2.	Properties
As of December 31, 2024, we owned approximately 273,000 surface acres in and around the Delaware Basin sub-region of the Permian Basin in Texas and New Mexico. Substantially all of our land is encumbered by mortgages that secure our credit facility. In addition, pursuant to our SURAs and SUAs, we grant our customers rights to use our land in return for pre-determined fees and royalties. Other than such mortgages and our SURAs and SUA easements, there are no material liens or encumbrances on our title to our surface estate as of December 31, 2024.
As of December 31, 2024, we also owned 4,424 gross mineral acres in Texas with a weighted average lease royalty percentage of 23.9% and net revenue interest per well of 4.3%. Of our gross mineral acres, approximately 96% underlie our surface acreage. Other than our gross mineral acres, we do not own the mineral interests that underlie our surface acreage.
The following table shows by county our surface ownership and royalty ownership as of December 31, 2024:
Number of Acres
Location (by county and position)
Surface
Gross Mineral Acres
Northern Position
Andrews County (TX)
20,479
-
Lea County (NM)
35,041
-
Eddy County (NM)
-
Total
56,285
-
Stateline Position
Loving County (TX)
82,981
Winkler County (TX)
34,480
Lea County (NM)
15,669
-
Reeves County (TX)
3,663
Total
136,793
1,566
Southern Position
Reeves County (TX)
71,572
2,858
Pecos County (TX)
9,074
-
Total
80,646
2,858
Total Acres
273,724
4,424

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ITEM 3. LEGAL PROCEEDINGS
Item 3.	Legal Proceedings
Due to the nature of our business, we may become, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, there are no pending litigation, disputes or claims against us
which, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part II, Item 8. Financial Statements and Supplementary Data - Note 13. Commitments and Contingencies.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. 	Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Class A shares are listed on the NYSE under the symbol “LB.” As of March 5, 2025, 23,255,419 Class A shares were outstanding, with 13 holders of record. This number does not include shareholders whose shares are held in trust by other entities and the actual number of our shareholders is greater than the number of holders of record. As of March 5, 2025, 53,193,178 Class B shares were outstanding, with one holder of record. Our Class B shares are not listed on any exchange, and there is no established public trading market for such Class B shares.
Dividends
On November 5, 2024, our board of directors declared a dividend on our Class A shares of $0.10 per share, which was paid on December 19, 2024, to shareholders of record as of December 5, 2024.
On February 21, 2025, our board of directors declared a dividend on our Class A shares of $0.10 per share, payable on March 20, 2025 to shareholders of record as of March 6, 2025.
While we intend to pay dividends on our Class A shares in amounts and at times determined from time to time by our board of directors, we have not adopted a formal written dividend policy to pay any particular amount of dividends based on the achievement of, or derivable from, any specific financial metrics. Furthermore, we are not contractually obligated to pay any dividends and do not have any required minimum dividend amount, and our credit facility limits our ability to pay dividends. If our board of directors determines to pay dividends in the future, the amount of such dividends may vary from quarter to quarter and may be significantly reduced or eliminated entirely. Our future dividends depend on our cash flow needs, which may be impacted by the availability of financing alternatives, the need to service any future indebtedness or other liquidity needs, potential acquisition opportunities and general industry and business conditions, including the level of use of our land and its resources, among other things, and will be subject to approval by our board of directors, applicable law and the terms of our existing debt instruments, including our revolving credit facility.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes repurchases of our Class A shares occurring in the fourth quarter of 2024.
Period
Total Number of Shares Purchased
Average Price Paid Per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
10/1/2024 - 10/31/2024
-
$
-
-
$
-
11/1/2024 - 11/30/2024
-
-
-
12/1/2024 - 12/31/2024
-
-
-
Total
-
$
-
-
$
-
Securities Authorized for Issuance under Equity Compensation Plans
See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding securities authorized for issuance under equity compensation plans.
Recent Sales of Unregistered Equity Securities
IPO Concurrent Private Placement
On June 27, 2024, we entered into a Common Share Purchase Agreement with an accredited investor (the “Accredited Investor”), pursuant to which the Accredited Investor purchased 750,000 Class A shares from us at $17.00 per share in a private placement that closed concurrently with the IPO (the “IPO Concurrent Private Placement”), resulting in net proceeds of approximately $12.5 million
after deducting fees to the placement agent and other expenses payable by the Company in connection with the IPO Concurrent Private Placement. We contributed the net proceeds from the IPO Concurrent Private Placement to OpCo in exchange for additional OpCo Units and OpCo used such net proceeds, together with net proceeds from the IPO and the exercise of the underwriters’ over-allotment option, to repay outstanding indebtedness and make a distribution to existing unitholders. The IPO Concurrent Private Placement closed concurrently with the IPO on July 1, 2024. Goldman Sachs & Co. LLC, acted as the placement agent for the IPO Concurrent Private Placement. The securities issued in connection with the IPO Concurrent Private Placement were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act. The Accredited Investor is an accredited investor for purposes of Rule 501 of Regulation D.
December Private Placement
In December 2024, we closed the private placement pursuant to which certain persons reasonably believed to be accredited investors or qualified institutional buyers purchased an aggregate 5,830,419 Class A shares from us at $60.03 per share (the “December Private Placement”). We used approximately $200.0 million of the proceeds from the December Private Placement, net of placement fees, to partially fund the Wolf Bone Acquisition, and approximately $150.0 million of such proceeds, net of placement fees, to purchase 2,498,751 OpCo Units (along with the cancellation of a corresponding number of Class B shares) from LandBridge Holdings.
Other than as previously reported on our Current Reports on Form 8-K, filed with the SEC on July 3, 2024, and November 22, 2024, we had no sales of unregistered securities during the year ended December 31, 2024.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6.	Reserved.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our Financial Statements and notes thereto in Part 8, “Financial Statements and Supplementary Data” of this Annual Report. The following discussion contains “forward-looking statements” reflecting our current expectations, future plans, estimates, beliefs and assumptions concerning events and financial trends that may affect our future results of operations, cash flows and financial position. Our actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including certain factors outside our control. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in the sections titled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” and in the prospectus under the heading “Risk Factors,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We assume no obligation to publicly update any of these forward-looking statements except as otherwise required by applicable law.
Unless otherwise indicated or required by the context, references to “LandBridge,” the “Company,” “we,” “us,” “our” and like terms refer (i) prior to the consummation of the Corporate Reorganization and the IPO, to OpCo and its subsidiaries, our predecessor for financial reporting purposes, and (ii) subsequent to the consummation of the Corporate Reorganization and the IPO, to LandBridge and its subsidiaries, including OpCo and its subsidiaries. Our financial statements have been prepared in accordance with GAAP. The consolidated financial statements as of and for the year ended December 31, 2024 included herein, reflect all adjustments which, in the opinion of management, are necessary for a fair presentation of financial position, results of operations and cash flows for the period. All such adjustments are of a normal recurring nature.
The historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of us or our predecessor, OpCo, as applicable, and does not give pro forma effect to the East Stateline Acquisition, the Credit Agreement Amendment, the Corporate Reorganization or the IPO.
Overview
Land is a fundamental requirement for the development and production of energy and the construction and operation of critical infrastructure. As of December 31, 2024, we owned approximately 273,000 surface acres in and around the Delaware Basin sub-region in the prolific Permian Basin, which is the most active area for oil and gas exploration and development in the United States. Access to expansive surface acreage is necessary for oil and natural gas development, solar power generation, power storage, digital infrastructure and non-hazardous oilfield reclamation and solid waste facilities. Further, the significant industrial economy that exists to service and support energy and infrastructure development requires access to surface acreage to support those activities. Our strategy is to actively manage our land and resources to support and encourage energy and infrastructure development and other land uses that will generate long-term revenue and Free Cash Flow for us and returns to our shareholders.
We take an active approach to the commercial development of our land, seeking to maximize the long-term value of our surface acreage and our resources by identifying and seeking commercial partners looking to invest in developing and operating long-term assets within and beyond the oil and gas value chain on our land. For the year ended December 31, 2023 , we generated $52.1 million of non-oil and gas royalty revenue on our approximately 72,000 owned surface acres, or $724 per owned surface acre. For the year ended December 31, 2024 we increased non-oil and gas royalty revenue on the same 72,000 owned surface acres to $73.3 million or $1,018 per owned surface acre. The Spring 2024 Acquisitions and Recent Acquisitions contributed post-acquisition revenues of $20.6 million of non-oil and gas royalty revenue and approximately 201,000 owned surface acres. When annualized, revenue from such acquisitions is $62.7 million or $312 per acquired surface acre for the year ended December 31, 2024. Inclusive of the annualized revenue and expanded acreage as a result of the acquisitions, and the $73.3 million from existing acreage, the resulting pro forma non-oil and gas royalty revenue was $136.0 million, or $498 per owned surface acre for the year ended December 31, 2024 on our approximately 273,000 owned surface acres. We measure our revenue divided by our total acreage as a performance metric, which we refer to as “surface use economic efficiency.” Further, we are actively pursuing additional revenue streams beyond the hydrocarbon value chain to maximize utilization of our land and resources. We have entered into, or are currently pursuing, primarily long-term commercial relationships with businesses focused on solar power generation, power storage, power generation/microgrids, 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.
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, 2024, handles approximately 2.0 million bpd of water associated with oil and natural gas production, with approximately 3.4 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. As of December 31, 2024, WaterBridge operates approximately 767,000 bpd of water handling capacity on our land, with approximately 1.7 million bpd of additional 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.
2024 Significant Events
Initial Public Offering
On July 1, 2024, LandBridge closed its initial public offering of 14,500,000 Class A shares at a price to the public of $17.00 per Class A share. In addition, LandBridge granted the underwriters a 30-day option to purchase up to an additional 2,175,000 Class A shares at the public offering price, less underwriting discounts and commissions, which the underwriters exercised in full on July 1, 2024. The Class A shares began trading on the New York Stock Exchange under the ticker symbol “LB” on June 28, 2024, and the IPO, including the underwriters’ option, closed on July 1, 2024. In addition to the Class A shares sold in the IPO, LandBridge sold 750,000 Class A shares at a price of $17.00 per Class A share in a concurrent private placement to an accredited investor (the “concurrent private placement”). See “Part II - Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - IPO Concurrent Private Placement” for additional information on the concurrent private placement.
LandBridge received net proceeds from the IPO, including the exercise of the underwriters’ option and the concurrent private placement of approximately $270.9 million, after deducting underwriting discounts and commissions, placement agent fees, and $7.5 million of offering expenses payable by LandBridge (with any additional offering expenses to be paid by LandBridge out of cash on balance sheet). The Company contributed the net proceeds from the IPO to OpCo in exchange for newly issued OpCo Units at a per-unit price equal to the per share price paid by the underwriters for our Class A shares in the IPO. OpCo used the net proceeds from the IPO to repay approximately $100.0 million of the outstanding borrowings under the Credit Facilities and to make a distribution to LandBridge Holdings of approximately $170.9 million.
Corporate Reorganization
Pursuant to a Master Reorganization Agreement, dated July 1, 2024 (the “Master Reorganization Agreement”), by and among LandBridge, LandBridge Holdings, OpCo, and DBR Land LLC, a Delaware limited liability company, LandBridge and OpCo completed the Corporate Reorganization. As part of the Corporate Reorganization, among other things:
•LandBridge Holdings was formed and acquired NDB LLC’s interests in OpCo and LandBridge;
•LandBridge Holdings caused LandBridge to amend and restate its operating agreement;
•LandBridge Holdings caused OpCo to amend and restate its operating agreement;
•LandBridge issued 14,500,000 Class A shares pursuant to the IPO;
•LandBridge contributed all of the net proceeds from the IPO to OpCo in exchange for a number of OpCo Units equal to the number of Class A shares issued in the IPO; and
•LandBridge Holdings received the cash distribution from OpCo described above and a number of Class B shares equal to the number of OpCo Units held by it immediately following the IPO.
Second Credit Agreement Amendment
On November 4, 2024, we entered into a second credit agreement amendment (the “Second Credit Agreement Amendment”), which amended the credit agreement governing our Credit Facilities, by and among DBR Land LLC, certain of our subsidiaries, as guarantors, Texas Capital Bank, as administrative agent and letter of credit issuer, and the other lenders party thereto from time to time. Among other things, the Second Credit Agreement Amendment (i) increased the maximum available amount under our Revolving Credit Facility to $100.0 million, (ii) increased the principal amount of the Term Loan to $300.0 million, (iii) provided for a $75.0 million uncommitted delayed draw term loan (the “Uncommitted DDTL”), and (iv) eliminated our obligation to make Term Loan amortization payments and permits us to make restricted payments as long as our leverage ratio is less than 3.50 to 1.00 for the most recently ended four-fiscal quarter period, subject to certain conditions and exceptions. On December 19, 2024, the Company borrowed $55.0 million under the Uncommitted DDTL to fund a portion of the purchase price of the Wolf Bone Acquisition, thereby increasing the aggregate outstanding amount of the Term Loan to $355.0 million. The Uncommitted DDTL terminated following such borrowing, and the Company is not permitted to borrow any additional amounts under the Uncommitted DDTL.
Commercial Developments
On November 6, 2024, we entered into 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. The counterparty to the agreement is a joint venture between a third-party developer and funds affiliated with our financial sponsor, Five Point Energy LLC. The lease development agreement includes, among other things, a non-refundable $8.0 million deposit due in December 2024 for a two-year site selection and pre-development period. The counterparty is obligated to meet certain timing milestones to maintain its lease, to include the commencement of site development within a two-year period and construction of the data center within a subsequent four-year period. Upon initiation of construction of a data center, the counterparty will make escalating annual lease payments along with additional payments based on net revenue received with respect to the power generation facilities to be located on the leased property. Approval of the lease development agreement and related transactions were referred to an independent Conflicts Committee of our board of directors for approval.
Recent Acquisitions
On November 1, 2024, we acquired approximately 1,280 surface acres in Winkler County, Texas, from a private, third-party seller (the “Winkler County Acquisition”) for total purchase consideration of $20.5 million inclusive of transaction costs. The Winkler County Acquisition includes a long-term water supply contract with an active sand mine underpinned by a minimum volume commitment through October 2031. We expect this minimum volume commitment to provide approximately $2.2 million in annual revenue through 2031.
On November 22, 2024, we acquired approximately 5,820 surface acres in Lea County, New Mexico, from a third party seller (the “Brininstool Acquisition”), for total purchase consideration of $26.8 million inclusive of transaction costs.
On December 19, 2024, we acquired approximately 46,000 surface acres in Reeves and Pecos Counties, Texas, from a subsidiary of VTX Energy (the “Wolf Bone Acquisition”), for total purchase consideration of $246.8 million, inclusive of transaction costs. Pursuant to the Wolf Bone Acquisition, we received a five-year, $25.0 million per year minimum revenue commitment from VTX Energy. The purchase price for the Wolf Bone Acquisition was funded with a portion of the net proceeds from the December Private Placement described below and borrowings under our credit facility. See “Debt Instruments - Credit Facility” for additional information
We believe that the Recent Acquisitions increase the exposure of our land position to the operations of large, well-capitalized producers and position us to benefit from anticipated growth in oil and natural gas, as well as other development on and around our land, among other benefits.
December Private Placement
On December 19, 2024, we closed the private placement pursuant to which certain persons reasonably believed to be accredited investors or qualified institutional buyers purchased an aggregate 5,830,419 Class A shares from us at $60.03 per share (the “December Private Placement”). We used approximately $200.0 million of the proceeds from the December Private Placement, net of placement fees, to partially fund the Wolf Bone Acquisition, and approximately $150.0 million of such proceeds, net of placement fees, to purchase 2,498,751 OpCo Units (along with the cancellation of a corresponding number of Class B shares) from LandBridge Holdings.
Recent Developments
On February 25, 2025, the Company acquired approximately 3,000 surface acres in Lea County, New Mexico, from a private third-party seller for total consideration of $16.7 million.
Market Condition and Outlook
Over the last several years, the global economy, and more specifically the oil and natural gas industry, has experienced significant volatility, impacted by the COVID-19 pandemic and recovery, the Russia-Ukraine war and the related sanctions imposed on Russia, as well as the Israel-Hamas conflict and heightened tensions in the Middle East, domestic political uncertainty, the activities of OPEC, a potential economic recession and elevated inflation, interest rates and costs of capital and industry consolidation. More recently, high levels of activity in the Delaware Basin have resulted in industry consolidation and labor and supply chain challenges, which has impacted drilling, completion and production activity. This volatility has driven material swings in WTI pricing, which has subsequently impacted development and production decisions of E&P companies.
In addition, global macroeconomic developments, such as the development or change in international trade policies, including the imposition of tariffs, may adversely affect our customers' ability to source raw materials and, as a result, demand on our land. As a result, any trading disruption (such as tariffs, product restrictions, etc.) in the trading relationships between the U.S. and other nations may adversely impact our business. For example, on February 1, 2025, the White House issued three executive orders directing the U.S. to impose an increase of the duty on imports from Canada and Mexico and China, with certain retaliatory tariffs being imposed as a result.
Despite these challenges, we believe the outlook for energy and infrastructure development, particularly within the Permian Basin, remains positive, which will require significant build out of supporting infrastructure in the region and access to surface acreage to support such operations. Any transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, like clean energy technologies, often require access to material surface acreage and supporting infrastructure, which we are also well positioned to facilitate. Please see the “Business” of this Annual Report for more information.
Year-end Results
Significant financial and operating highlights for the year ended December 31, 2024 include:
•Revenues of $110.0 million, an increase of $37.1 million as compared to the prior year;
•Net loss of $41.5 million as compared to net income of $63.2 million in 2023;
•Net loss margin of 38% as compared to net income margin of 87% in 2023;
•Adjusted EBITDA(1) of $97.1 million, an increase of 55% as compared to the prior year;
•Adjusted EBITDA Margin(1) of 88%, an increase of 2% as compared to the prior year;
•Cash flow from operating activities of $67.6 million, an increase of 28% as compared to the prior year;
•Free Cash Flow(1) of $66.7 million, an increase of 33% as compared to the prior year;
•Operating cash flow margin of 62%, a decrease of 11% as compared to the prior year; and
•Free Cash Flow Margin(1) of 61%, a decrease of 8% as compared to the prior year;
(1) Adjusted EBITDA, Adjusted EBITDA Margin, Free Cash Flow and Free Cash Flow Margin are non-GAAP financial measures. See “Non-GAAP Financial Measures” for more information regarding these non-GAAP measures and reconciliations to the most comparable GAAP measures. See also “How We Evaluate Our Operations” for more information regarding Adjusted EBITDA, Adjusted EBITDA Margin, Free Cash Flow and Free Cash Flow Margin.
Net loss and net loss margin for the year ended December 31, 2024 include 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 issued prior to the IPO and $18.7 million is attributable to LBH Incentive Units. Net income and net income margin for the year ended December 31, 2023 include non-cash share-based compensation income of $17.2 million attributable to the NDB Incentive Units. Any actual cash expense associated with such 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 threshold have been met and are neither an obligation of the Company nor taken into consideration for distributions to investors in the Company. See Note 2 - Summary of Significant Accounting Policies and Note 10 - Share-Based Compensation to our consolidated financial statements for additional information regarding LBH Incentive Units.
How We Generate Revenue
We generate revenue from multiple sources, including the use of our surface acreage, the sale of resources from our land and oil and gas and mineral royalties. 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, the amount of use expected to be made of our land, and the amount of resources to be produced and/or extracted. In any given period, the amount and sources of revenues we receive from any particular customer can fluctuate based on the nature, timing and scope of such customer’s activities on our land. For example, during the initial phase of a customer’s activities on our land, we would generally expect to receive usage-based fees and revenues under our SURAs and SUAs related to installation of infrastructure necessary to support long-term operations. Over time, these revenues would generally be expected to migrate to royalty revenue and resource sales based on such customer’s use of our land and resources. Our revenue consists of the principal components discussed below.
Surface Use Royalties and Revenues
Surface Use Royalties. We enter into SURAs and certain overarching SUAs with operators that require royalty payments to us based on a percentage of the customer’s gross revenues derived from use of our land and/or volumetric use of infrastructure installed on our land in exchange for rights of use of our land. Our SURAs typically obligate the operator to meter its volumetric utilization of infrastructure installed on our land and to include a report of such utilization for our review along with its periodic payment. 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. Our SURAs generally have terms ranging from a minimum of five years to 10 years, with the exception of brackish water sales agreements, which generally have a term of less than 12 months, and impose only nominal obligations on us. As of December 31, 2024: (i) produced water royalties under our SURAs ranged from $0.10 per barrel to $0.25 per barrel; and (ii) skim oil royalties under our SURAs ranged from 15% to 50% of net proceeds. However, the terms of our SURAs are negotiated on a customer-by-customer basis. Our SURAs typically do not include minimum purchase or use commitments by our customers but do generally provide for automatic renewal-based increases in royalties that are tied to the CPI or are negotiated on a case-by-case basis, depending on a number of factors, such as general economic conditions, the surface use of our land, competitor pricing and/or customer specific considerations. Our contractual provisions providing for inflation escalators are generally based on CPI or a specified fixed percentage, which may limit the amount of any single pricing increase. Such provisions may also vary as to the commencement date of such increases and the timing and calculation of the applicable adjustment based on the term of the agreement or particular use of our land. Our SURAs generally include standard provisions relating to maintenance by our customers of insurance of specified types and amounts, environmental, health and safety covenants and indemnification of us for the unauthorized use of hazardous material or environmental claims.
Easements and other surface-related income. SUAs permit operators to install drilling sites, pipelines, roadways, electric lines and other facilities and equipment on land owned by us. We typically receive a per-rod or per-acre fee when the contract is executed, based on the aggregate amount of our land that is utilized under such SUA, and we often receive additional fees at the beginning of each renewal period or on a monthly or annual basis. 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. Our SUAs generally have terms ranging from a minimum of five years to 10 years, with early termination rights for non-use over a pre-determined period of time, typically 12 to 18 months. Beyond making our land available in accordance with our SUAs, our SUAs impose only nominal obligations on us. As of December 31, 2024: (i) standard pipeline easements ranged from $20 per rod to $450 per rod based, in part, on the diameter of the pipeline and the easement term; (ii) road easements for new roads ranged from $75 per rod to $150 per rod based, in part, on the easement term; (iii) utility line easements ranged from $20 per rod to $150 per rod based, in part, on capacity and width of the utility line and the easement term; and (iv) well pads ranged from $7,000 per acre to $12,000 per acre. However, the terms of our SUAs are negotiated on a customer-by-customer basis. Our SUAs typically do not include minimum commitments with respect to the type and amount of infrastructure to be installed on our property or the amount of revenue to be received by us, but do generally provide for automatic renewal-based increases in royalties that are tied to the CPI or negotiated on a case-by-case basis, depending on a number of factors, such as general economic conditions, the surface use of our land, competitor pricing and/or customer specific considerations. Our contractual provisions providing for inflation escalators are generally based on CPI or a specified fixed percentage, which may limit the amount of any single pricing increase. Such provisions may also vary as to the commencement date of such increases and the timing and calculation of the applicable adjustment based on the term of the agreement or particular use of our land. Our SUAs generally include standard provisions relating to maintenance by our customers of insurance of specified types and amounts, environmental, health and safety covenants and indemnification of us for environmental claims.
Resource Sales and Royalties
Resource Sales. Resource sales generally include brackish water to be used primarily in well completions in exchange for a per barrel fee, which is negotiated and varies depending on the destination of the brackish water. We have strong relationships with, and contractual commitments from, many of the E&P companies in the Stateline Position. 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. Similarly, our customers buy other surface composite materials from us for the construction of access roads and well pads for which we receive a fixed-fee per cubic yard extracted from our surface acreage. Our agreements related to the sale of resources generally have terms ranging from a minimum of five years to 10 years, with early termination rights for non-use over a pre-determined period of time, typically 12 to 18 months. As of December 31, 2024: (i) per barrel prices for brackish water sold to third parties on a spot basis ranged from $0.50 to $1.10; (ii) per barrel prices for brackish water sold to oil and gas producers ranged from $0.35 to $0.95; (iii) per barrel prices for brackish water sold to resellers for delivery into New Mexico ranged from $0.15 to $0.35; and (iv) prices for caliche ranged from $5 per cubic yard to $10 per cubic yard. Such agreements may include certain exclusivity rights, such as the exclusive right to require the purchase of the subject resource for any operations on our land, and may include minimum commitments that are negotiated on a case-by-case basis, taking into account the amount of activity on our land, the specific use of our land and any resultant production thereon, among other things. These agreements typically provide rights to monitor activities on our land and contain standard provisions relating to confidentiality, indemnification of us for environmental claims and maintenance of insurance of specified types and amounts.
Resource Royalties. We lease our surface acreage to customers to construct and operate at their expense brackish water wells and sand mines to provide in-basin water and sand for use in oil and natural gas completion operations. Such customers hold the exclusive right to the water and sand they extract from the leased surface acreage and may be required to make minimum royalty payments as a result.
The agreements pursuant to which we receive resource royalties have varying primary terms of at least one year, and contain rights for renewal so long as the customer continues to operate on our land. We typically receive a fee when the contract is executed and a fixed royalty per barrel of water or ton of sand extracted. In situations where our customers do not operate brackish water wells on our surface but require the use of water for their operations, they generally must acquire such water from us for our customary fee. Such fees are negotiated on a case-by-case basis, depending on a number of factors, such as general economic conditions, the type of resources extracted, the amount of use expected to be made of our land or the amount of resources to be produced and/or extracted, competitor pricing and/or customer specific considerations. As of December 31, 2024, resource royalties received per ton of sand extracted ranged from $2.00 to $3.00, subject to certain minimum payment obligations, and resource royalties received per barrel of brackish water extracted ranged from $0.15 to $0.40. These leases generally do not impose minimum production requirements on our customers. These lease agreements contain standard provisions relating to confidentiality, indemnification of us for the unauthorized use of hazardous material or environmental claims and maintenance of insurance of specified types and amounts.
Oil and Gas Royalties
Oil and Gas Royalties. Oil and gas royalties are received in connection with oil and natural gas mineral interests owned by us. Oil and gas royalties are recognized as revenue as oil and gas are produced or severed from the mineral lease. The oil and gas royalties we receive are dependent upon market prices for oil and natural gas, and producer specific location and contractual price differences. Oil and gas royalties also include mineral lease bonus revenues. We receive lease bonus revenue by leasing our mineral interests to E&P companies. When we execute a mineral lease contract, the lease generally transfers the rights to any oil or natural gas discovered to the E&P company and grants us the right to a specified royalty interest payable on future production. Mineral lease bonuses are nonrefundable. Royalties from oil and natural gas production are generally negotiated on a case-by-case basis, depending on the particular mineral interests and holder of such mineral interests.
We expect our fee-based revenues to grow over time relative to our oil and gas royalties. While our focus is on fee-based arrangements, our oil and gas royalties fluctuate with market prices for oil and natural gas.
The following table presents the amount and relative percentage of each component of our revenues for the following periods:
Year Ended December 31,
Amount ($)
%
Amount ($)
%
Surface use royalties and revenues
Surface use royalties
$
31,620
28.8
%
$
13,216
18.1
%
Easements and other surface-related revenues
34,115
31.0
%
12,644
17.4
%
Resource sales and royalties
Resource sales
15,351
14.0
%
19,830
27.2
%
Resource royalties
12,841
11.7
%
6,432
8.8
%
Oil and gas royalties
16,027
14.5
%
20,743
28.5
%
Total revenue
$
109,954
100.0
%
$
72,865
100.0
%
Our revenues may vary significantly from period to period as a result of the activity level of producers on and around our land, the development of new revenue streams, commodity prices, changes in volumes produced on our land and our acquisition strategy, among other things, and are significantly dependent on our customers’ activities on and around our land. For example, oil and natural gas prices have historically been volatile. Lower commodity prices may decrease our revenues as customers on and around our land decrease their activity levels in response to low commodity prices. Although we intend to pursue additional opportunities to increase our revenue streams and introduce additional revenue components, including through solar power generation, power storage and battery projects, water treatment and desalination facilities, fueling stations, microgrids, cryptocurrency mining, data centers, telecommunication towers and equipment and other opportunities, there can be no assurance that such revenue streams will materially diversify our revenue streams.
Costs of Conducting our Business
Our costs consist primarily of resource sales-related expenses, other operating and maintenance expenses to maintain our surface acreage and general administrative expenses. Our principal costs are as follows:
Resource Sales-Related Expenses. Resource sales-related expenses are costs incurred for utilization and maintenance of our assets and facilities in the extraction or production of resources available on our land that are sold by us. These costs generally include utilities to operate our facilities and assets and repairs and maintenance expenses related to those assets.
Other Operating and Maintenance Expenses. Operating and maintenance expenses are costs incurred for maintaining our surface acreage and other assets, including field operating overhead and supervision, production taxes, insurance costs, ad valorem and property taxes, and repairs and maintenance expense.
General and Administrative Expenses. General and administrative expenses include a corporate shared services allocation from WaterBridge, directly incurred corporate costs and share-based compensation expense. Corporate shared services generally include the cost of shared management and administrative services. The corporate shared service allocation is based on an approximation of time spent on activities supporting us as well as by underlying business activities. The shared service allocation expense is reimbursed to WaterBridge through the Shared Services Agreement. Direct corporate costs are incurred for direct corporate employees, including payroll, benefits and other employee-related expenses of our direct corporate staff, professional services that generally consist of audit, tax, legal and valuation services and expenses for corporate insurance policies.
Prior to the IPO, share-based compensation expense only included expense allocated to us for NDB LLC’s Incentive Unit plan. The NDB Incentive Unit awards were classified as liability awards by NDB LLC and required periodic remeasurement. On July 1, 2024, in accordance with the Division, the holders of the NDB Incentive Units were issued an identical number of LBH Incentive Units. As of the date of the Division, the LBH Incentive Units are the only incentive units attributable and allocated to the Company. The LBH Incentive Units are accounted for as a modification and have been transitioned to equity award accounting and, as such, do not require periodic remeasurements. The share-based compensation for the LBH Incentive Units is fully allocated to the noncontrolling interest as the contractual obligation to satisfy the LBH Incentive Units exists at LandBridge Holdings. Any actual cash expense associated with such LBH Incentive Units is borne solely by LandBridge Holdings and not the Company.
In connection with the IPO, our board of directors adopted the LandBridge Company LLC Long Term Incentive Plan (the “LTIP”). The LTIP allows for the grant of options, share appreciation rights (“SARs”), RSUs, share awards, dividend equivalents, other share-based awards, cash awards, substitute awards or any combination thereof. Under the LTIP, participants have been granted RSUs. Share-based compensation associated with RSUs is allocated between the Company and the noncontrolling interest based on relative ownership. Substantially all share-based compensation is included in general and administrative expense (income) with an immaterial amount included in other operating and maintenance expense on the statements of operations prior to allocation to the noncontrolling interest. See Note 10 - Share-Based Compensation to our consolidated financial statements for additional information regarding share-based compensation.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our business.
Revenue
Revenue is a key performance metric of our company. We analyze realized monthly, quarterly and annual revenues and compare the results against our internal projections and budgets. Results are used to validate, or when applicable update, existing assumptions on macroeconomic drivers of our business, contractual mix driving average unit-level revenues and E&P customer development activity and commodity pricing, absent the impact of our operating costs.
Surface Use Economic Efficiency
We calculate surface use economic efficiency as (i) total revenues less oil and gas royalty revenues divided by (ii) owned surface acreage or in periods in which we acquire or dispose of acreage, the weighted average surface acreage owned during the period. This metric provides valuable insight into the effectiveness of our active land management strategy by examining our ability to generate value on our owned surface and track trends of our results over time, while inherently adjusting for any surface acreage acquisitions or divestitures that may occur. Further, we believe this metric serves as a worthwhile benchmark of our team’s management and growth strategy, as well as the relative value of our surface acreage, compared to our peers.
Adjusted EBITDA and Adjusted EBITDA Margin
Adjusted EBITDA and Adjusted EBITDA Margin are used by our management and by external users of our financial statements, such as investors, research analysts and others, to assess the financial performance of our assets over the long term to generate sufficient cash to return capital to equity holders or service indebtedness. We define Adjusted EBITDA as net income (loss) before interest; taxes; depreciation, amortization, depletion and accretion; share-based compensation; non-recurring transaction-related expenses and other non-cash or non-recurring expenses. We define Adjusted EBITDA Margin as Adjusted EBITDA divided by total revenues.
Management believes Adjusted EBITDA and Adjusted EBITDA Margin are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period, and against our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA and Adjusted EBITDA Margin because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Please read “-Non-GAAP Financial Measures” for reconciliations and additional information regarding these non-GAAP financial measures.
Free Cash Flow and Free Cash Flow Margin
Free Cash Flow and Free Cash Flow Margin are used by our management and by external users of our financial statements, such as investors, research analysts and others, to assess our ability to repay our indebtedness, return capital to our shareholders and fund potential acquisitions without access to external sources of financing for such purposes. We define Free Cash Flow as cash flow from operating activities less investment in capital expenditures. We define Free Cash Flow Margin as Free Cash Flow divided by total revenues.
Management believes Free Cash Flow and Free Cash Flow Margin are useful because they allow for an effective evaluation of both our operating and financial performance, as well as the capital intensity of our business, and subsequently the ability of our operations to generate cash flow that is available to distribute to our shareholders, reduce leverage or support acquisition activities. Please read “-Non-GAAP Financial Measures” for reconciliations and additional information regarding these non-GAAP financial measures.
Factors Affecting the Comparability of Our Results of Operations
In this Annual Report, we present our historical results of operations for the years ended December 31, 2024 and December 31, 2023. Our future results of operations will not be directly comparable to the historical results of operations of our predecessor for the periods presented as a result of the significant growth of our business and new contracting activity completed during each year of our operation, which are not reflected in our operating results until such contracting activity has been completed. We have also experienced additional significant growth in our business following the completion of the Spring 2024 Acquisitions and the Recent Acquisitions, resulting in our future results of operations for periods following the consummation of such acquisitions to not be directly comparable with our historical results.
Public Company Costs
As a result of the IPO, we incurred incremental, non-recurring costs related to our transition to a publicly traded and taxable entity, including the costs of the IPO and the costs associated with the initial implementation of our Sarbanes-Oxley Act internal controls and testing. We have incurred and expect to continue to incur additional significant and recurring expenses as a publicly traded company, including costs associated with SEC reporting and compliance requirements, consisting of the preparation and filing of annual and quarterly reports, registrar and transfer agent fees, national stock exchange fees, audit fees, legal fees, investor relations expenses, incremental director and officer liability insurance costs and director and officer compensation expenses. These expenses are not included in our results of operations prior to the IPO. Additionally, we have retained additional employees and consultants, including accounting and legal personnel, in order to comply with the requirements of being a publicly traded company.
Corporate Reorganization
We were formed to serve as the issuer in the IPO and had no operations, assets or liabilities prior to the consummation of the IPO. Certain of the historical consolidated financial statements included in this Annual Report are based on the financial statements of our accounting predecessor, OpCo, prior to the Corporate Reorganization in connection with the IPO. As a result, the historical consolidated financial data may not give you an accurate indication of what our actual results would have been if the Corporate Reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.
Long-Term Incentive Plan
In order to incentivize individuals providing services to us or our affiliates, our Board adopted a long-term incentive plan (“LTIP”) for employees and directors. Any individual who is our officer or employee or an officer or employee of any of our affiliates, and any other person who provides services to us or our affiliates, including our directors, may be eligible to receive awards under the LTIP at the discretion of our Board or a committee thereof, as applicable. The LTIP provides for the grant, from time to time, at the discretion of our Board, or a committee thereof, of options, share appreciation rights, restricted shares, restricted share units, share awards, dividend equivalents, other share-based awards, cash awards, substitute awards and performance awards intended to align the interests of employees, directors and service providers with those of our shareholders. As such, our historical financial data may not present an accurate indication of what our actual results would have been if we had implemented the LTIP program prior to the periods presented within.
Acquisitions
During 2024, we acquired approximately 200,000 surface acres through the consummation of the Spring 2024 Acquisitions and the Recent Acquisitions, which will impact the comparability of our results of operations. See Note 4 - Asset Acquisitions within the notes to our consolidated financial statements for further information with respect to such acquisitions. We expect to pursue opportunistic future land acquisitions that compliment or expand our current land position, which may impact the comparability of our results.
Credit Facility
On July 3, 2023, we entered into our credit facility which initially provided for (i) a four-year $100.0 million term loan facility (“Term Loan”) and (ii) a four-year $50.0 million revolving credit facility (“Revolving Credit Facility”), each of which matures on July 3, 2027. In connection with the closing of the credit facility, the prior credit agreement (the “Ag Loan”) was terminated and borrowings under the Ag Loan were repaid in full with proceeds from the new credit facility. See “-Liquidity and Capital Resources-Debt Instruments-Credit Facility” for more information.
Income Taxes
Prior to the IPO, OpCo and its subsidiaries were primarily entities that were treated as partnerships or disregarded entities for federal income tax purposes but were subject to certain minimal Texas franchise taxes. One of our subsidiaries is a qualified REIT for federal income tax purposes. There is no tax imposed on a REIT as long as the REIT complies with the applicable tax rules and avails itself of the opportunity to reduce its taxable income through distributions. A REIT must comply with a number of organizational and operational requirements, including a requirement that it must pay at least 90% of its taxable income to shareholders.
As a result of our predominately non-taxable structure historically, income taxes on taxable income or losses realized by our predecessor, OpCo, were generally the obligation of the individual members or partners. Accordingly, the financial data attributable to our predecessor, OpCo, contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than margin tax in the State of Texas). Following consummation of the IPO, although we are a limited liability company, we have elected to be taxed as a corporation and are subject to U.S. federal, state and local income taxes on our allocable share of the income and loss of OpCo.
Results of Operations
Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
Year Ended December 31,
(In thousands)
Revenues:
Surface use royalties
$
31,620
$
13,216
Easements and other surface-related revenues
34,115
12,644
Resource sales
15,351
19,830
Oil and gas royalties
16,027
20,743
Resource royalties
12,841
6,432
Total revenues
109,954
72,865
Resource sales-related expense
2,113
3,445
Other operating and maintenance expense
3,174
2,740
General and administrative expense (income)
112,302
(12,091
)
Depreciation, depletion, amortization and accretion
8,875
8,762
Operating (loss) income
(16,510
)
70,009
Interest expense, net
23,335
7,016
Other income
(241
)
(549
)
(Loss) income from operations before taxes
(39,604
)
63,542
Income tax expense
1,875
Net (loss) income
$
(41,479
)
$
63,172
Total revenues. Total revenues increased by $37.1 million, or 51%, to $110.0 million for the year ended December 31, 2024, as compared to $72.9 million for the year ended December 31, 2023. The increase was comprised of an increase in surface use royalties of $18.4 million, easements and other surface-related revenues of $21.5 million and resource royalties of $6.4 million, partially offset by decreased oil and gas royalties of $4.7 million and resource sales of $4.4 million. Please see our discussion below regarding comparative period variances in revenue sources.
Surface use royalties. Surface use royalties increased by $18.4 million, or 139%, to $31.6 million for the year ended December 31, 2024, as compared to $13.2 million for the year ended December 31, 2023. The increase was primarily attributable to increased produced water handling and associated skim oil royalties of $17.3 million and industrial waste handling royalties of $1.1 million on our surface for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Easements and other surface-related revenues. Easements and other surface-related revenues increased by $21.5 million, or 171%, to $34.1 million for the year ended December 31, 2024, as compared to $12.6 million for the year ended December 31, 2023. The increase was primarily attributable to oil and natural gas gathering and transportation pipelines and produced water handling infrastructure of $8.1 million, $8.0 million related to the non-refundable option fee associated with the data center lease development agreement and $5.3 million in other surface and subsurface easements for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Resource sales. Resource sales decreased by $4.4 million, or 22%, to $15.4 million for the year ended December 31, 2024, as compared to $19.8 million for the year ended December 31, 2023. Brackish water sales volume decreased by 4.9 million barrels, or 12%, to 34.2 million barrels for the year ended December 31, 2024, as compared to 39.1 million barrels for the year ended December 31, 2023. Additionally, the per unit sales price decreased by approximately 17%. The brackish water sales volume decrease is primarily due to the timing of customer demand in the areas surrounding our surface acreage, primarily upstream drilling and completion operations. Lower unit sales rates are driven by the customer contract mix for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Oil and gas royalties. Oil and gas royalties decreased by $4.7 million, or 23%, to $16.0 million for the year ended December 31, 2024, as compared to $20.7 million for the year ended December 31, 2023, which consists of decreased royalty income of $4.4 million and lower mineral lease income of $0.3 million. Mineral lease income decreased $0.3 million due to fewer net mineral acres leased during the year ended December 31, 2024, as compared to the year ended December 31, 2023. The table below provides operational and financial data by oil and gas royalty stream for the periods indicated.
Year Ended December 31,
Net royalty volumes:
Oil (MBbls)
Natural Gas (MMcf)
NGL (MBbls)
Equivalents (MBoe)
Equivalents (MBoe/d)
1.0
1.1
Oil and gas royalties (in thousands):
Oil royalties
$
13,346
$
17,138
Natural gas royalties
1,623
NGL royalties
1,610
1,322
Oil and gas royalties
15,621
20,083
Mineral lease income
Total oil and gas royalties
$
16,027
$
20,743
Realized prices
Oil ($/Bbl)
$
74.56
$
76.17
Natural gas ($/Mcf)
$
0.91
$
2.34
NGL ($/Bbl)
$
20.91
$
19.44
Equivalents ($/Boe)
$
41.33
$
49.10
Resource royalties. Resource royalties increased by $6.4 million, or 100%, to $12.8 million for the year ended December 31, 2024, as compared to $6.4 million for the year ended December 31, 2023. The increase was primarily attributable to brackish water royalties in connection with the East Stateline Ranch acquisition of $5.0 million and an increase attributable to sand mine royalty rates of $0.4 million and sand mine volumes of $1.0 million.
Resource sales-related expense. Resource sales-related expense decreased by $1.3 million, or 38%, to $2.1 million for the year ended December 31, 2024, as compared to $3.4 million for the year ended December 31, 2023. The decrease was primarily attributable to lower utility expenses due to the installation of permanent electricity infrastructure and purchase of third-party water and transfer costs associated with sales of brackish water driven by the lower volumes sold during the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Other operating and maintenance expense. Other operating and maintenance expense increased by $0.5 million, or 19%, to $3.2 million for the year ended December 31, 2024, as compared to $2.7 million for the year ended December 31, 2023. The increase was primarily attributable to higher direct and shared service labor costs in connection with the acquisitions for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
General and administrative expense (income). General and administrative expense (income), excluding share-based compensation expense, increased by $12.0 million, or 235%, to $17.1 million for year ended December 31, 2024, as compared to $5.1 million for the year ended December 31, 2023. The increase was primarily attributable to IPO-related employee bonuses of $5.0 million, a contract termination payment of $2.6 million, higher professional services fees and other non-capitalizable expenses associated with transitioning to a publicly traded company of $2.4 million, professional services fees primarily associated with amending the Company’s Credit Facilities in conjunction with acquisition-related activities of $0.7 million, $0.6 million in increased corporate shared services allocation from WaterBridge and $0.5 million in increased insurance costs.
General and administrative expense (income), inclusive of share-based compensation, increased by $124.4 million, or 1028%, to expense of $112.3 million for the year ended December 31, 2024, as compared to income of $12.1 million for the year ended December 31, 2023. The increase was attributable to the change in share-based compensation expense of $112.4 million and increased cash expenses noted above. The share-based compensation consists of an increase related to the incentive units of $108.4 million and $4.0 million related to the issuance of RSUs. The incentive units expense increase is primarily due to the periodic remeasurements of NDB Incentive Units prior to the Division of $72.6 million when the awards were accounted for as liability awards at NDB LLC and new issuances and post-modification equity award accounting amortization of $18.6 million for the year ended December 31, 2024, as compared to income of $17.2 million due to remeasurement of the NDB Incentive Units for the year ended December 31, 2023. See Note 10 - Share-Based Compensation within the notes to our condensed consolidated financial statements included elsewhere in this Annual Report.
Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion increased by $0.1 million, or 1%, to $8.9 million for the year ended December 31, 2024, as compared to $8.8 million for the year ended December 31, 2023.
Interest expense, net. Interest expense, net, increased by $16.3 million, or 233%, to $23.3 million for the year ended December 31, 2024, as compared to $7.0 million for the year ended December 31, 2023. The increase was primarily attributable to additional principal borrowings under our credit facility during the year ended December 31, 2024, as compared to borrowings under our then-existing debt instruments for the year ended December 31, 2023. See “- Liquidity and Capital Resources” for additional information regarding the Company’s debt instruments and interest expense.
Non-GAAP Financial Measures
Adjusted EBITDA, Adjusted EBITDA Margin, Free Cash Flow and Free Cash Flow Margin are supplemental non-GAAP measures that we use to evaluate current, past and expected future performance. Although these non-GAAP financial measures are important factors in assessing our operating results and cash flows, they should not be considered in isolation or as a substitute for net income or gross margin or any other measures presented under GAAP.
Management believes Adjusted EBITDA and Adjusted EBITDA Margin are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period, and against our peers, without regard to our financing methods or capital structure. We exclude the items listed below from net income (loss) in arriving at Adjusted EBITDA and Adjusted EBITDA Margin because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired.
Management believes Free Cash Flow and Free Cash Flow Margin are useful because they allow for an effective evaluation of both our operating and financial performance, as well as the capital intensity of our business, and subsequently the ability of our operations to generate cash flow that is available to distribute to our shareholders, reduce leverage or support acquisition activities.
Adjusted EBITDA and Adjusted EBITDA Margin
The following table sets forth a reconciliation of net income as determined in accordance with GAAP to Adjusted EBITDA and Adjusted EBITDA Margin for the periods indicated.
Year Ended December 31,
Net (loss) income
$
(41,479
)
$
63,172
Adjustments:
Depreciation, depletion, amortization and accretion
8,875
8,762
Interest expense, net
23,335
7,016
Income tax expense
1,875
EBITDA
(7,394
)
79,320
Adjustments:
Share-based compensation - Incentive Units (1)
91,307
(17,230
)
Share-based compensation - RSUs
4,028
-
Transaction-related expenses (2)
1,266
Non-recurring expenses (3)
7,825
-
Other
Adjusted EBITDA
$
97,069
$
62,804
Net (loss) income margin
(38
%)
%
Adjusted EBITDA Margin
%
%
(1)Share-based compensation - Incentive Units for the year ended December 31, 2024, consists of $18.7 million related to the LBH Incentive Units, and $72.6 million related to the NDB Incentive Units. Share-based compensation - Incentive Units for the year ended December 31, 2023, consists only of the NDB Incentive Units. NDB Incentive Units were liability awards resulting in periodic fair value remeasurement prior to the Division. Subsequent to the IPO, 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)Transaction-related expenses consist of non-capitalizable transaction costs associated with both completed or attempted acquisitions, debt amendments, entity structuring and non-capitalizable IPO-related charges.
(3)Non-recurring expenses consist primarily of $5.0 million in IPO-related employee bonuses and $2.6 million related to a contract termination payment.
Free Cash Flow and Free Cash Flow Margin
The following table sets forth a reconciliation of cash flows from operating activities determined in accordance with GAAP to Free Cash Flow and Free Cash Flow Margin, respectively, for the periods indicated.
Year Ended December 31,
Net cash provided by operating activities
$
67,636
$
53,042
Net cash used in investing activities
(724,352
)
(2,772
)
Cash (used in) provided by operating and investing activities
(656,716
)
50,270
Adjustments:
Acquisitions
723,367
-
Proceeds from disposal of assets
-
(11
)
Free Cash Flow
$
66,651
$
50,259
Operating cash flow margin (1)
%
%
Free Cash Flow Margin
%
%
(1)Operating cash flow margin is calculated by dividing net cash provided by operating activities by total revenue.
Liquidity and Capital Resources
Overview
Historically, our primary sources of liquidity have been capital contributions from our financial sponsor, cash flows from operating activities and borrowings under our debt instruments. Following the completion of the IPO, our primary sources of liquidity are cash flows from operating activities and, if required, proceeds from borrowings under our credit facility. Our primary liquidity and capital requirements will be for our operating expenses, servicing of our debt, the payment of dividends to our shareholders, general company needs and investing in our business, including the potential acquisition of additional surface acreage, such as the Recent Acquisitions. Although we believe that we will be able to partially or fully fund our short-term and long-term capital expenditures, working capital requirements and other capital needs with cash on hand and cash flows from operating activities, we may elect to use borrowings under our credit facility to finance our operating and investing activities. See “- Debt Instruments - Credit Facility.”
We strive to maintain financial flexibility and proactively monitor potential capital sources, including equity and debt financing, to meet our target liquidity and capital requirements. If market conditions were to change and our revenues were to decline significantly or operating costs were to increase, our cash flows and liquidity could be reduced and we could be required to seek alternative financing sources. As of December 31, 2024, we had working capital, defined as current assets less current liabilities, of $38.9 million and we had cash and cash equivalents of $37.0 million. As of December 31, 2023, we had working capital of $25.2 million and cash and cash equivalents of $37.8 million.
Cash Flow
The following tables summarizes our cash flow for the periods indicated:
Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
Year Ended
December 31,
Consolidated Statement of Cash Flow Data:
Net cash provided by operating activities
$
67,636
$
53,042
Net cash used in investing activities
(724,352
)
(2,772
)
Net cash provided by (used in) financing activities
655,925
(37,798
)
Net (decrease) increase in cash and cash equivalents
$
(791
)
$
12,472
Net Cash Provided by Operating Activities. Net cash provided by operating activities increased $14.6 million or 28% to $67.6 million for the year ended December 31, 2024, as compared to $53.0 million for the year ended December 31, 2023. The increase was attributable to higher net income, net of non-cash items, of $9.2 million, and cash flow related to working capital accounts, primarily
accounts receivable and taxes payable, of $5.4 million. Please see “-Results of Operations” for more information regarding analysis of our consolidated statements of operations.
Net Cash Used in Investing Activities. Net cash used in investing activities increased $721.6 million or 25,771% to $724.4 million for the year ended December 31, 2024, as compared to $2.8 million for the year ended December 31, 2023. The increase was attributable to acquisition-related expenditures of $723.4 million for the Spring 2024 Acquisitions and Recent Acquisitions, partially offset by lower capital expenditures, primarily supporting brackish water supply sales, of $1.7 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Net Cash Provided by (Used In) Financing Activities. Net cash provided by financing activities increased $693.7 million or 1835% to $655.9 million of cash provided by financing activities for the year ended December 31, 2024, as compared to cash used of $37.8 million for the year ended December 31, 2023. For the year ended December 31, 2024, cash provided by financing activities consisted of $609.4 million of net proceeds from the IPO and December Private Placement and $250.7 million of debt borrowings, net of repayments and debt issuance costs, primarily used to fund the acquisitions during the year, partially offset by the purchase of OpCo Units from LandBridge Holdings of $145.4 million, dividends and distributions paid, net of contributions, of $58.2 million. For the year ended December 31, 2023, cash used in financing activities was primarily attributable to $105.2 million in member distributions and $1.7 million in deferred offering costs, partially offset by debt proceeds, net of repayments and issuance costs, of $69.5 million.
Capital Requirements
We focus our business model on entering into agreements under which our customers bear substantially all of the operating and capital expenditures related to their operations on our land, while minimizing our capital requirements for both current and future commercial opportunities, resulting in the ability to create significant free cash flows. Our contracts generally include inflation escalators, which, when combined with our relatively low operating and capital expenditures, may assist in mitigating our exposure to broader inflationary pressures. As a landowner, we incur the initial cost to acquire our acreage, but thereafter we incur modest development capital expenditures and operating expenses as it relates to operations on our land or our mineral and royalty interests, as such expenses are borne primarily by our customers. As a result, we expect that additional significant capital expenditures would be related to our acquisition of additional surface acreage, such as the Recent Acquisitions, should we elect to do so.
The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the size of the acquisition opportunity, our cash flows from operating activities and our investing and financing activities. For the year ended December 31, 2024, we incurred $723.4 million in acquisition-related capital expenditures, inclusive of $3.1 million of transaction-related expenses, in connection with the consummation of the Spring 2024 Acquisitions and the Recent Acquisitions.
We periodically assess changes in current and projected cash flows, acquisition and divestiture activities and other factors to determine the effects on our liquidity. We believe that our cash on hand and cash flow from operating activities will provide us with sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of factors that may directly or indirectly affect us, many of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through traditional borrowings under our debt instruments, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us.
As our board of directors declares cash dividends to our Class A shareholders, we expect the dividend to be paid from Free Cash Flow. We do not currently expect to borrow funds or to adjust planned capital expenditures to finance dividends on our Class A shares. The timing, amount and financing of dividends, if any, will be subject to the discretion of our board of directors from time to time. See “Dividend Policy.”
Debt Instruments
Ag Loan
On October 14, 2021, our subsidiary, Delaware Basin Ranches, Inc., entered into a $65.0 million credit agreement (the “Ag Loan”) that was scheduled to mature on October 1, 2028. Borrowings under the Ag Loan were repaid in full with borrowings under our new credit facility in July 2023.
Credit Facility
On July 3, 2023, we entered into our credit facility which initially provided for (i) a four-year $100.0 million Term Loan and (ii) a $50.0 million Revolving Credit Facility, each of which matures on July 3, 2027. In connection with entering into our credit facility, we borrowed $100.0 million under the Term Loan and $25.0 million under the Revolving Credit Facility. Net proceeds from these borrowings were used to repay the $49.4 million outstanding under our prior credit facility and to make a distribution of $72.9 million to NDB LLC. On May 10, 2024, in order to fund a portion of the purchase price for the Spring 2024 Acquisitions, we entered into a credit facility amendment (the “First Credit Agreement Amendment”), which, among other things, increased the principal amount of the Term Loan to $350.0 million and the maximum available under the Revolving Credit Facility to $75.0 million. Following our entry into the First Credit Agreement Amendment, we borrowed $265.0 million under our credit facility to fund a portion of the purchase price of the Spring 2024 Acquisitions. On November 4, 2024, we further amended the credit facility (the “Second Credit Agreement Amendment”), to (i) increase the maximum available amount under our Revolving Credit Facility to $100.0 million, (ii) increase the principal amount of the Term Loan to $300.0 million, (iii) provide for an additional $75.0 million uncommitted delayed draw term loan (“the Uncommitted DDTL”), and (iv) eliminate the Company’s obligation to make Term Loan amortization payments. Following our entry into the Second Credit Agreement Amendment, we borrowed $55.0 million to fund a portion of the purchase price of the Wolf Bone Acquisition, thereby increasing the aggregate outstanding amount of the Term Loan to $355.0 million. The Uncommitted DDTL terminated following such borrowing, and the Company is not permitted to borrow any additional amounts under the Uncommitted DDTL. Our credit facility is secured by a first-priority lien on substantially all of our assets and guaranteed by us and our subsidiaries (other than certain immaterial subsidiaries).
Our credit facility includes certain affirmative and restrictive covenants common in such agreements that apply to DBR Land LLC and its subsidiaries. See Note 8 - Debt within the notes to our condensed consolidated financial statements and included elsewhere in this Annual Report for further information with respect to such affirmative and restrictive covenants.
The estimated fair value of our credit facility approximates the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
We may elect for outstanding borrowings under our credit facility to accrue interest at a rate based on either (i) a forward-looking term rate based on the secured overnight financing rate (“Term SOFR”) plus 0.10%, or (ii) the base rate, in each case plus an applicable margin. Borrowings under our credit facility accrue interest based on a five-tiered pricing grid tied to our current leverage ratio. The applicable margin ranges from (i) prior to the consummation of the IPO, 3.00% to 4.00% in the case of Term SOFR loans and letter of credit fees, and 2.00% to 3.00% in the case of base rate loans, and commitments fees of 0.50%, and (ii) following consummation of the IPO, 2.75% to 3.75% in the case of Term SOFR loans and letter of credit fees, and 1.75% to 2.75% in the case of base rate loans, and commitment fees range from 0.375% to 0.50%. Our credit facility is secured by a first priority security interest in substantially all of our assets and the assets of our restricted subsidiaries, which are party to our credit facility as guarantors, and all outstanding equity interests issued by DBR Land, which are held by OpCo.
As of December 31, 2024, we had $385.0 million of outstanding borrowings consisting of $30.0 million of revolving credit borrowings and $355.0 million of term loan borrowings. The weighted average interest rate on the total amount of borrowings outstanding under new credit facility for the twelve months ended December 31, 2024 was 8.39% in the case of revolving credit borrowings and 8.47% in the case of term loan borrowings. We are currently in compliance with all affirmative and negative covenants under our new credit facility.
Critical Accounting Estimates
The preparation of our Consolidated Financial Statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements. We consider our critical accounting estimates those that require subjectivity and that could inherently influence our financial result based on changes in those estimates. Our significant accounting policies are discussed in Note 2 - Summary of Significant Accounting Policies - Basis of Presentation and Consolidation of our Notes to the Consolidated Financial Statements.
Share-Based Compensation
Incentive Units
The Company accounts for share-based compensation expense for incentive units granted in exchange for employee services. Incentive units are subject to time-based vesting, and vest to the participant over the course of the vesting period which is generally three years. Forfeitures are accounted for upon occurrence.
Prior to the Division, our management and employees participated in an equity-based incentive unit plan, managed by NDB LLC, the
direct parent of the Company (the “NDB Incentive Units”). The incentive units consisted of time-based awards of profits interests in NDB LLC(the “NDB Incentive Units”).
The NDB Incentive Units represented a substantive class of equity of NDB LLC and were accounted for under Financial Accounting Standards Board (“FASB”) ASC Topic 718, Compensation - Stock Compensation (“ASC 718”). Features of the NDB Incentive Units included the ability for NDB LLC to repurchase NDB Incentive Units during a 180-day option period, whereby the fair value price was determined as of the termination date, not the repurchase date, which temporarily takes away the rights and risks and rewards of ownership from the NDB Incentive Unit holder during the option period. Under ASC 718, a feature for which the employee could bear the risks, but not gain the rewards, normally associated with equity ownership requires liability classification. NDB LLC classified the NDB Incentive Units as liability awards. The liability related to the NDB Incentive Units was recognized at NDB LLC as the entity responsible for satisfying the obligation. Share-based compensation income or expense allocated to the Company was recognized as a deemed non-cash contribution to or distribution from member’s equity on the consolidated balance sheets. The share-based compensation income or expense was recognized consistent with NDB LLC’s classification of a liability award resulting in the initial measurement, and subsequent remeasurements, recognized ratably over the vesting period.
At each reporting period, the NDB Incentive Units were remeasured at their fair value, consistent with liability award accounting, using a Monte Carlo Simulation. The Monte Carlo Simulation requires judgment in developing assumptions, which involve numerous variables. These variables include, but are not limited to, the expected unit price volatility over the term of the awards, the expected distribution yield and the expected life of the NDB Incentive Units. The vested portion of the NDB Incentive Units liability was allocated pro rata to the Company, and other NDB LLC operating subsidiaries, as general and administrative expense or income on the consolidated statements of operations. The allocation was based on the Company’s share of the aggregate equity value derived in NDB LLC’s business enterprise valuation.
The Company updated its assumptions each reporting period based on new developments and adjusted such amounts to fair value based on revised assumptions, if applicable, over the vesting period. The fair value measurement was based on significant inputs not observable in the market, and thus represented Level 3 inputs within the fair value hierarchy.
The risk-free rate was determined by reference to the U.S. Treasury yield curve in effect at the time of grant of each award and updated at each balance sheet date for the time period approximating the expected term of such award. The expected distribution yield was based on no previously paid distributions and no intention of paying distributions on the NDB Incentive Units for the foreseeable future.
Due to the Company not having sufficient historical volatility, the Company used the historical volatilities of publicly traded companies that were similar to the Company in size, stage of life cycle and financial leverage.
On July 1, 2024, as a result of the Division, holders of NDB Incentive Units received an identical number of LBH Incentive Units consisting of time-based awards of profits interests in LandBridge Holdings. Following the Division, the LBH Incentive Units held at LandBridge Holdings are the only incentive units attributable and allocated to the Company. There are 31,000 LBH Incentive Units currently authorized pursuant to the A&R LLC Agreement.
Further, in connection with the Division, the repurchase feature of the incentive units was amended such that the repurchase price is the fair value determined as of the repurchase date, which subjects the LBH Incentive Unit holder to the normal rights, risks and rewards of ownership. The repurchase feature is a non-contingent call option as the call becomes effective upon (i) the employee’s termination of employment either by the Company (with or without cause) or (ii) voluntary resignation by employee and it is assured that all employees will eventually terminate. Under ASC 718, a feature for which the employee could bear the risks and rewards normally associated with equity ownership and a non-contingent call option not probable to be exercised within six months requires equity classification. As such, beginning on July 1, 2024, the LBH Incentive Units are no longer required to be remeasured at fair value and no longer require liability award accounting, as the modification results in equity award classification and accounting. See Note 10 - Share-Based Compensation for additional information related to the modification. The fair value measurement of any new issuances, after the Division, are based on significant inputs not observable in the market, and thus represented Level 3 inputs within the fair value hierarchy.
Distributions attributable to LBH Incentive Units are based on returns received by investors of LandBridge Holdings once certain return thresholds have been met. LBH Incentive Units are solely a payment obligation of LandBridge Holdings, and neither the Company nor OpCo has any cash or other obligation to make payments in connection with the LBH Incentive Units.
Revenue Recognition
Oil and gas royalties
Oil and gas royalties are received in connection with oil and natural gas mineral interests owned by the Company. Oil and gas royalties are recognized as revenue as oil and gas are produced or severed from the mineral lease. The oil and gas royalties we receive includes variable consideration that is dependent upon market prices for oil and gas, and producer specific location and contractual price differences. As a result, our oil and gas royalty revenues are typically constrained at the inception of the contract but will be resolved once volumes are produced and settled. Oil and gas royalty payments are typically received one to three months following the month of production. We accrue oil and gas royalties produced but not yet paid based on the historical or estimated royalty interest production and current market prices, net of estimated location and contract pricing differentials. The difference between estimated and actual amounts received for oil and gas royalties are recorded in the period the payment is received.
We monitor drilling and completion activity on our mineral acreage position from publicly available sources to identify when new royalty interest production may be coming online. We estimate our royalty interest ownership in new production wells based on our assessment of available information. Ultimate determination of division order interest from the operator could results in amounts that differ from our initial estimates. The differences related to estimated interest estimated and actual division order interest are recorded in the period in which final division orders are issued or in the period in which the initial payment is received.
As of December 31, 2024 and December 31, 2023, we accrued $1.9 million and $3.2 million of oil and gas royalties in our consolidated statements of operations, respectively.
Recently Issued Accounting Standards
For a summary of recently issued accounting standards, see Note 2 - Summary of Significant Accounting Policies - Basis of Presentation and Consolidation of our Notes to the Consolidated Financial Statements.
Internal Controls and Procedures
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. We are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of the effectiveness of our internal control over financial reporting under Section 404 until our second annual report on Form 10-K after our IPO.
Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting and will not be required to do so for as long as we are an “emerging growth company” and/or a “smaller reporting company” under applicable federal securities laws.
Off Balance Sheet Arrangements
We currently have no material off-balance sheet arrangements.
Emerging Growth Company Status
We are an “emerging growth company,” as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies.” We may take advantage of these exemptions until we are no longer an “emerging growth company.” Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period afforded by the JOBS Act for the implementation of new or revised accounting standards. We have elected to use the extended transition period for complying with new or revised accounting standards and as a result of this election, our financial statements may not be comparable to companies that comply with public company effective dates. We may take advantage of these exemptions up until the last day of the fiscal year following the fifth anniversary of our initial public offering or such earlier time that we are no longer an emerging growth company. We would cease to be an emerging growth company if we have more than $1.235 billion in annual revenue, we have more than $700.0 million in market
value of our stock held by non-affiliates (and we have been a public company for at least 12 months and have filed one annual report on Form 10-K) or we issue more than $1.0 billion of non-convertible debt securities over a three-year period.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks, which include the effects of adverse changes in commodity prices and counterparty and customer credit risks and interest rate risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and counterparty and customer credit and interest rate risk. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risks
One of our major market risk exposures relates to the prices that our customers receive for the oil and natural gas produced from, or serviced on, our land. The market for the use of our land and its resources is indirectly exposed to fluctuations in the price of oil and natural gas, to the extent such fluctuations impact drilling, completion and production activity levels and thus impact the activity levels of our customers in the exploration and production and oilfield services industries. Realized prices are primarily driven by the prevailing prices for oil and natural gas in the United States. We are also directly exposed to these risks with respect to revenues we receive from the oil and natural gas interests. Pricing for oil and natural gas has been historically volatile and unpredictable, and we expect this volatility to continue in the future.
During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. The posted price for WTI has ranged from a low of negative $36.98 per barrel in April 2020 to a high of $123.64 per barrel in March 2022. As of December 31, 2024, the Henry Hub spot market price of natural gas was $3.40 per MMBtu and the posted price for oil was $72.44 per barrel. Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that our customers can produce or service economically. We expect this market will continue to be volatile in the future. A substantial or extended decline in commodity prices may adversely affect our results of operations, cash flows and financial position.
We do not currently intend to hedge our indirect exposure to commodity price risk. We may in the future enter into derivative instruments, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging instruments would allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices.
Market Risks
Demand for the use of land and resources are largely dependent upon the level of activity in the energy industry in the Permian Basin. These activity levels are influenced by numerous factors over which we have no control, including: the supply of and demand for oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available pipeline, rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability domestically, as a result of the recent elections or otherwise, and in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the transition to a low-carbon economy; the price and availability of alternative fuels; technological advancements in the production of alternative energy; the ability of energy companies to raise equity capital and debt financing; and industry consolidation and merger and divestiture activity among energy companies.
The level of U.S. energy production, including oil and natural gas development activity, is volatile. Any prolonged and substantial reduction in oil and natural gas prices would likely affect development and production activity levels and therefore affect demand for oil and natural gas and the use of our land and resources. A material decline in energy, including oil and natural gas, prices or Permian Basin activity levels could have an adverse effect on our results of operations, cash flows and financial position.
Counterparty and Customer Credit Risks
We are subject to risks of loss resulting from nonpayment or nonperformance by our counter-parties and customers of their contractual obligations. Our principal exposure to credit risk is through receivables generated by the activities of customers on our land. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We examine the creditworthiness of any counterparty and customer and monitor our exposure to such counter-parties and customers through credit analysis, and monitoring procedures, including reviewing credit ratings, financial statements and payment history. For the year ended December 31, 2024, three customers accounted for 24%, 14% and 10% of our total revenues,
respectively. For the year ended December 31, 2023, four customers accounted for 15%, 14%, 13% and 13% of our total revenues, respectively. No other customer accounted for more than 10% of total revenues. However, we believe that the credit risk associated with our counterparties and customers is acceptable.
Interest Rate Risks
Our ability to borrow and the rates offered by lenders can be adversely affected by deterioration in the credit markets and/or deterioration of our credit profile rating. We may elect for outstanding borrowings under our credit facility to accrue interest at a rate based on either the Term SOFR, or the base rate, plus an applicable margin, which exposes us to interest rate risk to the extent we have borrowings outstanding under our credit facility.
As of December 31, 2024, we had $385.0 million of outstanding borrowings consisting of $30.0 million of revolving credit borrowings and $355.0 million of term loan borrowings. The weighted average interest rate on the borrowings outstanding under our Credit Facilities for the twelve months ended December 31, 2024 was 8.39% in the case of revolving credit borrowings, and 8.47% in the case of term loan borrowings. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the weighted average interest rate would be $3.9 million per year. We do not currently have or intend to enter into any derivative hedge contracts to protect against fluctuations in interest rates applicable to our outstanding indebtedness. See “- Debt Instruments - Credit Facility.”

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 34)
Consolidated Balance Sheets as of December 31, 2024 and 2023
Consolidated Statements of Operations for the Years Ended December 31, 2024 and 2023
Consolidated Statements of Shareholders’ and Member's Equity for the Years Ended December 31, 2024 and 2023
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024 and 2023
Notes to Consolidated Financial Statements
Note 1. Organization and Nature of Operations
Note 2. Summary of Significant Accounting Policies
Note 3. Additional Financial Statement Information
Note 4. Asset Acquisitions
Note 5. Property, Plant and Equipment
Note 6. Intangible Assets
Note 7. Income Taxes
Note 8. Debt
Note 9. Shareholders’ and Member’s Equity
Note 10. Share-Based Compensation
Note 11. Earnings Per Share
Note 12. Related Party Transactions
Note 13. Commitments and Contingencies
Note 14. Subsequent Events
Note 15. Supplemental Oil and Gas Information (Unaudited)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of LandBridge Company LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of LandBridge Company LLC and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, shareholders’ and member’s equity, and cash flows for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP Houston, Texas
March 5, 2025
We have served as the Company’s auditor since 2022.
LandBridge Company LLC and Subsidiaries
Consolidated Balance Sheets
(in thousands)
December 31,
Current assets:
Cash and cash equivalents
$
37,032
$
37,823
Accounts receivable, net
12,544
12,383
Related party receivable (Note 12)
2,111
1,037
Prepaid expenses and other current assets
1,628
1,035
Total current assets
53,315
52,278
Non-current assets:
Property, plant and equipment, net
902,742
203,018
Intangible assets, net
45,265
28,642
Deferred tax assets
-
Other assets
1,741
5,011
Total non-current assets
950,159
236,671
Total assets
$
1,003,474
$
288,949
Liabilities and equity
Current liabilities:
Accounts payable
$
$
Taxes payable
2,286
Related party payable (Note 12)
Accrued liabilities
7,185
4,945
Current portion of long-term debt
20,339
Unearned revenue
1,221
Other current liabilities
2,119
Total current liabilities
14,410
27,100
Non-current liabilities:
Long-term debt, net of debt issuance costs
380,815
108,343
Other long-term liabilities
2,759
Total non-current liabilities
380,998
111,102
Total liabilities
395,408
138,202
Commitments and contingencies (Note 13)
Member's equity
-
150,747
Class A shares, unlimited shares authorized and 23,255,419 shares issued and outstanding as of December 31, 2024. None authorized, issued or outstanding as of December 31, 2023.
432,663
-
Class B shares, unlimited shares authorized and 53,227,852 shares issued and outstanding as of December 31, 2024. None authorized, issued or outstanding as of December 31, 2023.
-
-
Retained earnings
3,349
-
Total shareholders' equity attributable to LandBridge Company LLC
436,012
-
Noncontrolling interest
172,054
-
Total shareholders' and member's equity
608,066
150,747
Total liabilities and equity
$
1,003,474
$
288,949
See accompanying notes to the consolidated financial statements
LandBridge Company LLC and Subsidiaries
Consolidated Statements of Operations
(in thousands)
Year Ended December 31,
Revenues:
Surface use royalties
$
13,121
$
7,780
Surface use royalties - Related party (Note 12)
18,499
5,436
Easements and other surface-related revenues
20,629
8,395
Easements and other surface-related revenues - Related party (Note 12)
13,486
4,249
Resource sales
14,964
18,045
Resource sales - Related party (Note 12)
1,785
Oil and gas royalties
16,027
20,743
Resource royalties
9,779
6,432
Resource royalties - Related party (Note 12)
3,062
-
Total revenues
109,954
72,865
Resource sales-related expense
2,113
3,445
Other operating and maintenance expense
3,174
2,740
General and administrative expense (income)
112,302
(12,091
)
Depreciation, depletion, amortization and accretion
8,875
8,762
Operating (loss) income
(16,510
)
70,009
Interest expense, net
23,335
7,016
Other income
(241
)
(549
)
(Loss) income from operations before taxes
(39,604
)
63,542
Income tax expense
1,875
Net (loss) income
$
(41,479
)
$
63,172
Net loss prior to the IPO
(46,877
)
Net income attributable to noncontrolling interest
Net income attributable to LandBridge Company LLC
$
5,110
Net income per share of Class A shares (1)
Basic
$
0.28
Diluted
$
0.07
Weighted average shares outstanding of Class A shares (1)
Basic
17,807,323
Diluted
73,370,073
(1) Represents the period from July 1, 2024 through December 31, 2024, the period following the reorganization transactions and IPO.
See accompanying notes to the consolidated financial statements
LandBridge Company LLC and Subsidiaries
Consolidated Statements of Shareholders’ and Member’s Equity
(in thousands)
Member's Equity
Class A
Class B
Retained Earnings
Non-
controlling
Interest
Total
Shareholders'
and Member's
Equity
Amount
Shares
Amount
Shares
Amount
Amount
Amount
Amount
Balance at January 1, 2023
$
209,959
-
$
-
-
$
-
$
-
$
-
209,959
Distribution to member
(105,165
)
-
-
-
-
-
-
(105,165
)
Deemed non-cash capital distributions
(17,219
)
-
-
-
-
-
-
(17,219
)
Net income
63,172
-
-
-
-
-
-
63,172
Balance at January 1, 2024
$
150,747
-
$
-
-
$
-
$
-
$
-
$
150,747
Contribution from member
120,000
-
-
-
-
-
-
120,000
Deemed non-cash contributions prior to reorganization
72,572
-
-
-
-
-
-
72,572
Net loss prior to reorganization
(46,877
)
-
-
-
-
-
-
(46,877
)
Effect of corporate reorganization and IPO
(296,442
)
17,425,000
94,126
55,726,603
-
-
301,023
98,707
Deemed non-cash contributions subsequent to reorganization
-
-
-
-
-
-
18,735
18,735
Class A share-based compensation expense subsequent to reorganization
-
-
-
-
-
3,049
4,028
Purchase of OpCo Units from LandBridge Holdings, net of placement agent fees
-
-
-
(2,498,751
)
-
-
(145,411
)
(145,411
)
Dividends and distributions
-
-
-
-
-
(1,743
)
(5,573
)
(7,316
)
RSU dividend equivalent rights
-
-
-
-
-
(18
)
(57
)
(75
)
December Private Placement, net of placement agent fees and offering expenses
-
5,830,419
337,558
-
-
-
-
337,558
Net income subsequent to reorganization
-
-
-
-
-
5,110
5,398
Balance at December 31, 2024
$
-
23,255,419
$
432,663
53,227,852
$
-
$
3,349
$
172,054
$
608,066
See accompanying notes to the consolidated financial statements
LandBridge Company LLC and Subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
Year Ended December 31,
Cash flows from operating activities
Net (loss) income
$
(41,479
)
$
63,172
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion
8,875
8,762
Amortization of deferred financing fees
Amortization of debt issuance costs
1,277
Share-based compensation
95,335
(17,230
)
Gain on disposal of assets
-
(239
)
Deferred income tax expense
(411
)
-
Bad debt expense
(7
)
Changes in operating assets and liabilities:
Accounts receivable
2,113
(1,474
)
Related party receivable
(1,074
)
(613
)
Prepaid expenses and other assets
(328
)
Accounts payable
Related party payable
(109
)
Unearned revenue
(989
)
Accrued liabilities and other liabilities
(434
)
Income taxes payable
1,901
Net cash provided by operating activities
67,636
53,042
Cash flows from investing activities
Acquisitions
(723,367
)
-
Capital expenditures
(985
)
(2,783
)
Proceeds from disposal of assets
-
Net cash used in investing activities
(724,352
)
(2,772
)
Cash flows from financing activities
Proceeds from issuance of Class A shares - IPO, net of underwriter discounts & fees
278,263
-
Proceeds from issuance of Class A shares - December Private Placement, net of placement agent fees
339,291
-
Purchase of OpCo Units from LandBridge Holdings, net of placement agent fees
(145,411
)
-
Contributions from member
120,000
-
Dividends, dividend equivalents, and distributions paid
(178,244
)
(105,165
)
Proceeds from term loan
362,500
100,000
Repayments of term loan
(102,500
)
(62,417
)
Proceeds from revolver
55,000
50,000
Repayments of revolver
(60,000
)
(15,000
)
Other financing activities
(462
)
(404
)
Debt issuance costs
(4,326
)
(3,106
)
Offering costs
(8,186
)
(1,706
)
Net cash provided by (used in) financing activities
655,925
(37,798
)
Net (decrease) increase in cash and cash equivalents
(791
)
12,472
Cash and cash equivalents - beginning of period
37,823
25,351
Cash and cash equivalents - end of period
$
37,032
$
37,823
See accompanying notes to the consolidated financial statements
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements
1.Organization and Nature of Operations
LandBridge Company LLC (the “Company,” “LandBridge,” “we,” “our” and “us”) is headquartered in Houston, Texas and was formed on September 27, 2023 as a Delaware limited liability company to serve as the issuer in an initial public offering of equity (the “IPO”). We are governed by our First Amended & Restated Limited Liability Company Agreement, dated as of July 1, 2024 (the “A&R LLC Agreement”), which was entered into in connection with the IPO.
Our accounting predecessor is DBR Land Holdings LLC (“OpCo”) and its subsidiaries. OpCo is a Delaware limited liability company which was formed in September 2021. We are a holding company whose principal asset consists of membership interests in OpCo (“OpCo Units”). As the managing member of OpCo and its subsidiaries, we operate and control all of the business and affairs of OpCo and its subsidiaries, and through OpCo and its subsidiaries, conduct our business.
We generate revenue primarily from the use of our surface acreage, the sale of resources from our land and oil and natural gas royalties. The use of surface acreage generally includes easements or leases and various surface use royalties. Sale of resources generally includes sales of brackish water and other surface composite materials. Our assets consist mainly of fee surface acreage, oil and natural gas mineral interests, brackish water wells and ponds and related facilities.
We own surface acreage in the Delaware Basin in Texas and New Mexico and oil and natural gas mineral interests in the Delaware Basin in Texas.
Initial Public Offering and Private Placement
On July 1, 2024, we completed our IPO of 14,500,000 Class A shares representing limited liability company interests (“Class A shares”) at a price to the public of $17.00 per share. In addition, we granted the underwriters a 30-day option to purchase up to an additional 2,175,000 Class A shares at the public offering price, less underwriting discounts and commissions, which was exercised in full on July 1, 2024. In addition to the Class A shares sold in the IPO, on July 1, 2024, we sold 750,000 Class A shares at a price of $17.00 per Class A share in a concurrent private placement to an accredited investor (the “concurrent private placement”).
The closing of the IPO, including the exercise of the underwriters’ option and the concurrent private placement, resulted in net proceeds of approximately $270.9 million, after deducting underwriting discounts and commissions, placement agent fees, and other offering expenses. The Company contributed all of the net proceeds of the IPO (including the underwriters’ option and the concurrent private placement) to OpCo in exchange for OpCo Units at a per-unit price equal to the per share price paid by the underwriters for Class A shares in the IPO. OpCo distributed approximately $170.9 million to LandBridge Holdings LLC (“LandBridge Holdings”) and utilized approximately $100.0 million to repay outstanding borrowings under the Credit Facilities. Refer to Note 8 - Debt for additional information related to our Credit Facilities.
Corporate Reorganization and Amended and Restated LLC Agreement
On July 1, 2024, immediately prior to the IPO, WaterBridge NDB LLC (“NDB LLC”), the sole member of the Company prior to the corporate reorganization, was divided into two Delaware limited liability companies in accordance with a plan of division: (i) NDB LLC and (ii) LandBridge Holdings, a new Delaware limited liability company created by, and resulting from, the division (collectively, the “Division”). Following the Division and in connection with the IPO, our board of directors authorized and approved the A&R LLC Agreement.
The A&R LLC Agreement authorizes two classes of shares, Class A shares and Class B shares representing limited liability company interests in us. Only our Class A shares have economic rights and entitle holders thereof to participate in any dividends our board of directors may declare. Under the A&R LLC Agreement, the Company is authorized to issue an unlimited number of additional limited liability company interests of any type without the approval of our shareholders, subject to the rules of the New York Stock Exchange. Each holder of a Class A share is entitled to one vote on all matters to be voted on by our shareholders generally. Class B shares are not entitled to participate in any dividends our board of directors may declare but are entitled to vote on the same basis as the Class A shares. Holders of Class A shares and Class B shares vote together as a single class on all matters presented to our shareholders, except as otherwise required by applicable law or by the A&R LLC Agreement. We do not intend to list the Class B shares on any stock exchange. As of December 31, 2024, all of our Class B shares are owned by LandBridge Holdings.
As of December 31, 2024, the Company has the following outstanding shares:
•23,255,419 Class A shares, and
•53,227,852 Class B shares
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Redemption Rights
Pursuant to the Amended and Restated Limited Liability Company Agreement of OpCo, dated as of July 1, 2024, as amended by Amendment No. 1 thereto, dated effective as of September 30, 2024 (collectively, the “OpCo LLC Agreement”), each holder of an OpCo Unit (other than the Company) (each, a “Redeeming Member”) has the right, subject to certain limitations (the “Redemption Right”), to cause OpCo to acquire all or a portion of its OpCo Units (along with the cancellation of a corresponding number of our Class B shares) for, at OpCo’s election, (x) Class A shares at a redemption ratio of one Class A share for each OpCo Unit redeemed, subject to conversion rate adjustments for equity splits, dividends and reclassifications and other similar transactions (“applicable conversion rate adjustments”) or (y) cash in an amount equal to the Cash Election Amount (as defined in the OpCo LLC Agreement) of such Class A shares. Alternatively, upon the exercise of the Redemption Right, the Company has the right, pursuant to the Call Right (as defined in the OpCo LLC Agreement), to acquire each tendered OpCo Unit directly from the Redeeming Member for, at the Company’s election, (x) one Class A share, subject to applicable conversion rate adjustments, or (y) cash in an amount equal to the Cash Election Amount of such Class A shares. Notwithstanding the foregoing, to the extent a Redeeming Member and its affiliates own at least 40% of the voting power of the Company, (i) OpCo may elect to settle a redemption by such Redeeming Member in cash only to the extent that, prior to or contemporaneously with making such election, the Company issues a number of equity securities at least equal to the number of OpCo Units subject to such redemption and contributes to OpCo an amount in cash equal to the net proceeds received by the Company from the issuance of such equity securities, and (ii) the Company may make a Cash Election (as defined in the OpCo LLC Agreement) in connection with its exercise of its Call Right with respect to a redemption by such Redeeming Member only to the extent that, prior to or contemporaneously with making such election, the Company issues a number of equity securities at least equal to the number of OpCo Units subject to such redemption.
Corporate Reorganization
The transactions described above (collectively, the “Corporate Reorganization”) have been accounted for as a reorganization of entities under common control. As a result, our consolidated financial statements recognize the assets and liabilities in the Corporate Reorganization at their historical carrying amounts, reflected in the historical financial statements of OpCo.
December Private Placement
On December 19, 2024, we closed a private placement transaction pursuant to which certain persons reasonably believed to be accredited investors or qualified institutional buyers purchased an aggregate 5,830,419 Class A shares from us at $60.03 per share (the “December Private Placement”). The closing of the December Private Placement resulted in net proceeds of approximately $339.3 million, after deducting placement agent fees. Additionally, we incurred approximately $1.7 million in offering costs associated with the December Private Placement. The Company used approximately $200.0 million, net of placement agent fees, of such proceeds from the December Private Placement to partially fund our December 19, 2024 acquisition (refer to Note 4 - Asset Acquisitions), and approximately $150.0 million, net of placement agent fees, of such proceeds to purchase 2,498,751 OpCo Units (along with the cancellation of corresponding number of Class B shares) from LandBridge Holdings. In connection with the December Private Placement, the Company, its directors and executive officers, LandBridge Holdings, and the Five Point (defined below) funds that own LandBridge Holdings entered into lock-up agreements and are subject to certain restrictions with respect to the sale or other disposition of Class A Shares, or securities convertible into or exercisable or exchangeable for Class A Shares, including OpCo Units and Class B Shares, until 60 days after the consummation of the December PIPE (February 17, 2025), subject to certain exceptions.
2.Summary of Significant Accounting Policies
Basis of Presentation and Consolidation
Our consolidated financial statements (“Financial Statements”) have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).
All dollar amounts, except per share/unit amounts, in the Financial Statements and tables in the notes are stated in thousands of dollars unless otherwise indicated.
In these Financial Statements, periods prior to the consummation of the Corporate Reorganization and the IPO reflect the financial statements of OpCo and its subsidiaries. Periods subsequent to the consummation of the Corporate Reorganization and the IPO reflect the financial statements of the consolidated Company, including LandBridge, OpCo and its subsidiaries.
We have determined that the members with equity at risk in OpCo lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact OpCo’s economic performance; therefore, OpCo is considered a variable interest entity.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
As the managing member of OpCo, we operate and control all of the business and affairs of OpCo and also have the obligation to absorb losses or the right to receive benefits that could be potentially significant to us. Therefore, we are considered the primary beneficiary and consolidate OpCo.
The Financial Statements include the accounts of the Company, OpCo and its wholly owned subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation.
Noncontrolling Interest
When we consolidate an entity, we include 100% of the assets, liabilities, revenues and expenses of the subsidiary in our Financial Statements. For those entities that we consolidate in which our ownership is less than 100%, we record a noncontrolling interest as a component of equity on our consolidated balance sheets, which represents the third party ownership in the net assets of the respective consolidated subsidiary. Additionally, the portion of net income or loss attributable to the noncontrolling interest is reported as net income (loss) attributable to noncontrolling interest on our consolidated statements of operations. Changes in our ownership interests in an entity that do not result in deconsolidation are generally recognized within equity. Our Financial Statements include a noncontrolling interest representing the percentage of OpCo Units not held by us.
Segment Information
The Company operates in a single operating and reportable segment. All of our long-lived assets are located in the United States. Accounting Standards Codification (“ASC”) Topic 280, Segment Reporting, defines characteristics of operating segments as being components of an enterprise in which separate discrete financial information is available for evaluation by the chief operating decision maker (“CODM”) in making decisions on how to allocate resources and assess performance. The Company’s one segment approach is consistent with the reporting structure of the Company’s internal organization, as well as with the financial information used by the Company’s CODM. The Company’s CODM is the Chief Executive Officer who allocates resources and assess performance based upon financial information at the consolidated level. The financial measure regularly provided to the CODM that is most consistent with GAAP is net income (loss), as presented on our consolidated statements of operations. The measure of segment assets is reported on the consolidated balance sheets as total assets. The Company presents all of its significant segment expenses and other metrics as used by the CODM to make decisions regarding the Company’s business, including resource allocation and performance assessment in our Financial Statements.
Use of Estimates
The preparation of the Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and accompanying notes.
The Company evaluates its estimates and related assumptions regularly, including those related to the fair value measurements of assets acquired and liabilities assumed in a business combination, the collectability of accounts receivable, the assessment of recoverability and useful lives of long-lived assets, including property, plant and equipment, intangible assets, and the valuation of the Incentive Units. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from such estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Whenever available, fair value is based on or derived from observable market prices or parameters. When observable market prices or inputs are not available, unobservable prices or inputs are used to estimate the fair value. The three levels of the fair value measurement hierarchy are as follows:
•Level 1: Quoted market prices in active markets for identical assets or liabilities.
•Level 2: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly.
•Level 3: Unobservable inputs that are not corroborated by market data.
The carrying value of the Company’s cash and cash equivalents, accounts receivable, net of current expected credit losses, and accounts payable and accrued liabilities reported on the consolidated balance sheets approximate fair value due to their highly liquid nature or short-term maturity.
The Company adjusts the carrying amount of certain non-financial assets, property, plant and equipment and definite-lived intangible assets, to fair value on a non-recurring basis when they are impaired.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
The fair value of debt is the estimated amount the Company would have to pay to transfer its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Refer to Note 8 - Debt for additional information.
Recurring fair value measurements were performed for NDB Incentive Units (defined below) prior to the Division and award modifications (when the incentive units were accounted for as liability awards at NDB LLC), as disclosed in Note 10 - Share-Based Compensation.
During the years ended December 31, 2024 and December 31, 2023, there were no transfers between the fair value hierarchy levels.
Cash and Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains cash balances that may at times exceed federally insured limits.
Accounts Receivable
The Company extends credit to customers and other parties in the normal course of business. Accounts receivable consists of trade receivables recorded at the invoiced amount, plus accrued revenue that is earned but not yet billed, less an estimated allowance for doubtful accounts. Account receivables are generally due within 45 days or less. An allowance for expected credit losses is determined based upon historical write-off experience, aging of accounts receivables, current macroeconomic industry conditions and customer collectability patterns. Accounts receivable are charged against the allowance when determined to be uncollectible. When the Company recovers amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery.
As of December 31, 2024 and 2023, the Company had balances of immaterial amounts in allowance for doubtful accounts. There were immaterial amounts of write-offs and no recoveries during the years ended December 31, 2024 and December 31, 2023.
As of December 31, 2024, the Company had three customers that accounted for approximately 19%, 15%, and 14% of accounts receivable, respectively. As of December 31, 2023, the Company had three customers that accounted for approximately 14%, 13%, and 10% of accounts receivable, respectively
The Company accrues oil and gas royalties for amounts not received during the period but produced based on historical production volumes and current market prices. Produced water and other surface use royalties are also accrued for during the period based on historical trends or expected activity and contract prices. These accrued amounts are both included within accounts receivable, net on the consolidated balance sheets.
Property, Plant and Equipment
Property, plant, and equipment is stated at cost or, upon acquisition, at its fair value. Expenditures for construction activities, major improvements and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Costs of abandoned projects are charged to operating expense upon abandonment. The cost of assets sold or disposed of, and the related accumulated depreciation are removed from the accounts in the period of sale or disposal, and the resulting gains or losses are recorded in earnings in the respective period. Refer to Note 5 - Property, Plant and Equipment.
Depreciation is computed using the straight-line method over the estimated useful lives for each asset group, as noted below:
Water wells, pipelines, facilities, ponds and related equipment
3 - 15 years
Buildings
30 years
Vehicles, equipment, furniture and other
3 - 5 years
The Company follows the successful efforts method of accounting for its oil and natural gas properties acquired. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisitions of oil and natural gas properties are recorded at their estimated fair value as of the acquisition date.
Proved properties
Costs of proved oil and natural gas properties are depleted on a basin-wide basis utilizing the units-of-production method using total proved reserves.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Unproved properties
Costs of unproved oil and natural gas properties are not subject to depletion. These costs are transferred into costs subject to depletion on an ongoing basis as wells are completed and as proved reserves are established or confirmed.
Intangible Assets
Our intangible assets with definite useful lives include water contracts and surface use agreements. The amounts are presented at the Company’s cost basis. Such intangible assets with definite lives are amortized on a straight-line basis and assume no residual value. Refer to Note 6 - Intangible Assets for further information.
Debt Issuance Costs
Debt issuance costs represent costs associated with long-term financing and are amortized over the term of the related debt using a method which approximates the effective interest method. The Company’s debt issuance costs associated with the revolving credit facility are deferred and presented within prepaid expenses and other current assets, and other assets on the consolidated balance sheets. Debt issuance costs associated with the term loan are reflected as a reduction of long-term debt on the consolidated balance sheets. Refer to Note 8 - Debt for further information.
Offering Costs
Offering costs consist of costs related to underwriting, legal, accounting, and other expenses incurred through the balance sheet date that are directly related to the IPO and the December Private Placement. These costs were offset against proceeds upon consummation of the IPO and December Private Placement. As of December 31, 2024, the Company had $10.4 million of offering costs included in shareholders’ and member’s equity on the consolidated balance sheets, of which $0.5 million was accrued. Prior to the consummation of the IPO, offering costs were deferred. As of December 31, 2024, we had no deferred offering costs included in other assets on the consolidated balance sheets related to the IPO and December Private Placement. As of December 31, 2023, the Company had $3.7 million of deferred offering costs related to the IPO included in other assets on the consolidated balance sheets, of which $2.0 million was accrued.
Acquisitions
To determine if a transaction should be accounted for as a business combination or an asset acquisition, we first calculate the relative fair value of the assets acquired. If substantially all of the relative fair value is concentrated in a single asset or group of similar assets, or, if not, but the transaction does not include a significant process (does not meet the definition of a business), the transaction is recorded as an asset acquisition. We record asset acquisitions using the cost accumulation model. Under the cost accumulation model of accounting, the cost of the acquisition, including certain transaction costs, are allocated to the assets acquired using relative fair values. All other transactions are recorded as business combinations. We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Transactions in which we acquire control of a business are accounted for under the acquisition method. The identifiable assets, liabilities and any noncontrolling interests are recorded at the estimated fair value as of the acquisition date. The purchase price in excess of the fair value of assets acquired and liabilities assumed is recorded as goodwill.
Impairment of Long-Lived Assets
Management reviews the Company’s long-lived assets, which primarily includes property, plant and equipment and definite-lived intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying value of the assets might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability is generally determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
Proved reserves
The Company evaluates its proved oil and natural gas properties for impairment when events or changes in circumstances indicate the related carrying value may not be recoverable. This evaluation is performed on a basin-wide basis. The Company assesses the valuation of its proved oil and natural gas properties for impairment by comparing the carrying value to estimated undiscounted future net cash flows using estimated production and prices at which the Company estimates the commodity will be sold. If the carrying value exceeds undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying value exceeds the fair value. In
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
the impairment assessment, the Company estimates the fair value of proved oil and natural gas properties using valuation techniques that convert future cash flows to a single undiscounted amount. Significant inputs and assumptions to the valuation of proved oil and natural gas properties include estimates of reserves, future production volumes, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate.
Unproved reserves
Unproved oil and natural gas properties are also evaluated periodically for impairment. Impairment is assessed when events and circumstances indicate the carrying value may not be recoverable, at which an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Impairment assessment criteria includes, but is not limited to, commodity prices forecasts, macroeconomic conditions and current and future operator activity in the basin.
We did not recognize any impairment for the years ended December 31, 2024 and December 31, 2023.
Share-Based Compensation
Incentive Units
The Company accounts for share-based compensation expense for incentive units granted in exchange for employee services. Incentive units are subject to time-based vesting, and vest to the participant over the course of the vesting period which is generally three years. Forfeitures are accounted for upon occurrence.
Prior to the Division, our management and employees participated in an equity-based incentive unit plan, managed by NDB LLC, the direct parent of the Company. The incentive units consisted of time-based awards of profits interests in NDB LLC (the “NDB Incentive Units”).
The NDB Incentive Units represented a substantive class of equity of NDB LLC and were accounted for under Financial Accounting Standards Board (“FASB”) ASC Topic 718, Compensation - Stock Compensation (“ASC 718”). Features of the NDB Incentive Units included the ability for NDB LLC to repurchase NDB Incentive Units during a 180-day option period, whereby the fair value price was determined as of the termination date, not the repurchase date, which temporarily takes away the rights and risks and rewards of ownership from the NDB Incentive Unit holder during the option period. Under ASC 718, a feature for which the employee could bear the risks, but not gain the rewards, normally associated with equity ownership requires liability classification. NDB LLC classified the NDB Incentive Units as liability awards. The liability related to the NDB Incentive Units was recognized at NDB LLC as the entity responsible for satisfying the obligation. Share-based compensation income or expense allocated to the Company was recognized as a deemed non-cash contribution to or distribution from member’s equity on the consolidated balance sheets. The share-based compensation income or expense was recognized consistent with NDB LLC’s classification of a liability award resulting in the initial measurement, and subsequent remeasurements, recognized ratably over the vesting period.
At each reporting period, the NDB Incentive Units were remeasured at their fair value, consistent with liability award accounting, using a Monte Carlo Simulation. The Monte Carlo Simulation requires judgment in developing assumptions, which involve numerous variables. These variables include, but are not limited to, the expected unit price volatility over the term of the awards, the expected distribution yield and the expected life of the NDB Incentive Units. The vested portion of the NDB Incentive Unit liability was allocated pro rata to the Company, and other NDB LLC operating subsidiaries, as general and administrative expense or income on the consolidated statements of operations. The allocation was based on the Company’s share of the aggregate equity value derived in NDB LLC’s business enterprise valuation.
The Company updated its assumptions each reporting period based on new developments and adjusted such amounts to fair value based on revised assumptions, if applicable, over the vesting period. The fair value measurement was based on significant inputs not observable in the market, and thus represented Level 3 inputs within the fair value hierarchy.
The risk-free rate was determined by reference to the U.S. Treasury yield curve in effect at the time of grant of each award and updated at each balance sheet date for the time period approximating the expected term of such award. The expected distribution yield was based on no previously paid distributions and no intention of paying distributions on the NDB Incentive Units for the foreseeable future.
Due to the Company not having sufficient historical volatility, the Company used the historical volatilities of publicly traded companies that were similar to the Company in size, stage of life cycle and financial leverage.
On July 1, 2024, as a result of the Division, holders of NDB Incentive Units received an identical number of LBH Incentive Units consisting of time-based awards of profits interests in LandBridge Holdings. Following the Division, the LBH Incentive Units held at
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
LandBridge Holdings are the only incentive units attributable and allocated to the Company. There are 31,000 LBH Incentive Units currently authorized pursuant to the A&R LLC Agreement.
Further, in connection with the Division, the repurchase feature of the incentive units was amended such that the repurchase price is the fair value determined as of the repurchase date, which subjects the Incentive Unit holder to the normal rights, risks and rewards of ownership. The repurchase feature is a non-contingent call option as the call becomes effective upon (i) the employee’s termination of employment either by the Company (with or without cause) or (ii) voluntary resignation by employee and it is assured that all employees will eventually terminate. Under ASC 718, a feature for which the employee could bear the risks and rewards normally associated with equity ownership and a non-contingent call option not probable to be exercised within six months requires equity classification. As such, beginning on July 1, 2024, the LBH Incentive Units are no longer required to be remeasured at fair value and no longer require liability award accounting, as the modification results in equity award classification and accounting. See Note 10 - Share-Based Compensation for additional information related to the modification. The fair value measurement of any new issuances, after the Division, are based on significant inputs not observable in the market, and thus represented Level 3 inputs within the fair value hierarchy.
Distributions attributable to LBH Incentive Units are based on returns received by investors of LandBridge Holdings once certain return thresholds have been met. LBH Incentive Units are solely a payment obligation of LandBridge Holdings, and neither the Company nor OpCo has any cash or other obligation to make payments in connection with the LBH Incentive Units.
LTIP and Restricted Share Units
In connection with the IPO, our board of directors adopted the LTIP. The LTIP allows for the grant of options, SARs, restricted share units (“RSUs”), share awards, dividend equivalents, other share-based awards, cash awards, substitute awards, or any combination thereof.
There were 3,600,000 Class A shares reserved for delivery under the LTIP as of December 31, 2024, subject to increase on January 1 of each calendar year by a number of shares equal to the lesser of (x) 5% of the total number of Class A shares and Class B shares outstanding as of December 31 of the immediately preceding calendar year; (y) the number of shares required to bring the total shares available for issuance under the LTIP to 5% of the total number of Class A shares and Class B shares outstanding as of December 31 of the immediately preceding calendar year; or (z) such smaller number of shares as determined by our board of directors.
RSUs issued to participants are recorded on grant date at fair value. Expense is recognized on a straight-line basis over the requisite service period (generally the vesting period of the award) as either other operating and maintenance expense or general and administrative expense in the consolidated statements of operations. We have elected to account for forfeitures as they occur. Therefore, compensation cost previously recognized for an award that is forfeited because of failure to satisfy a service condition will be reversed in the period of the forfeiture. RSUs include dividend equivalent rights that permit holders of granted but unvested RSUs to receive nonforfeitable distributions alongside common equity holders of the Company as if such RSUs were granted as of the applicable record date for such distribution.
See Note 10 - Share-Based Compensation for additional information.
Earnings Per Share Attributable to LandBridge
We use the two-class method in our computation of earnings per share. Our RSUs include dividend equivalent rights that permit holders of granted but unvested RSUs to receive a non-forfeitable cash amount equal in value to dividends paid with respect to a specified number of shares and are contemplated as participating when the Company is in a net income position. These awards participate in dividend equivalents on a basis equivalent to other Class A shares but do not participate in losses. Class B shares do not have economic rights and are not entitled to participate in any dividends our board of directors may declare but are entitled to vote on the same basis as the Class A shares.
Basic earnings (loss) per share (“EPS”) of our Class A shares is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our Class A shares contemplates adjustments to the numerator and the denominator under the if-converted method for the convertible Class B shares. The Company uses the treasury stock method or two-class method when evaluating dilution for RSUs. The more dilutive of the two methods is included in the calculation for diluted EPS. See Note 11 - Earnings Per Share for additional information.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Revenue Recognition
Oil and gas royalties
Oil and gas royalties are received in connection with oil and natural gas mineral interests owned by the Company. Oil and gas royalties are recognized as revenue as oil and gas are produced or severed from the mineral lease. The oil and gas royalties we receive includes variable consideration that is dependent upon market prices for oil and gas, and producer specific location and contractual price differences. As a result, our oil and gas royalty revenues are typically constrained at the inception of the contract but will be resolved once volumes are produced and settled. Oil and gas royalty payments are typically received one to three months following the month of production. The Company accrues oil and gas royalties produced but not yet paid based on historical or estimated royalty interest production and current market prices, net of estimated location and contract pricing differentials. The difference between estimated and actual amounts received for oil and gas royalties are recorded in the period the payment is received. Refer to Note 3 - Additional Financial Statement Information for additional information regarding amounts accrued on the consolidated statements of operations.
Oil and gas royalties also include mineral lease bonus revenues. The Company receives lease bonus revenue by leasing its mineral interests to exploration and production (“E&P”) companies. When we execute a mineral lease contract, it generally transfers the rights to any oil or gas discovered to the E&P company and grants us the right to a specified royalty interest payable on future production. Mineral lease bonuses are nonrefundable. Mineral lease bonus revenues are recognized when the agreement is executed as control is transferred and the Company has satisfied its performance obligation at that point in time.
Resource sales and royalties
Resource sales generally includes brackish water and other surface, composite material, such as caliche, that the Company sells to E&P companies and other customers. Resource sales revenue is generally recognized upon delivery of the brackish water or other surface material as the Company's performance obligation has been deemed satisfied at that point in time. In certain instances, a third party other than a customer may be involved in a resource sale transaction, such as a revenue sharing agreement or brokered sale transaction. In these instances, the Company will either act as the principal or the agent in the transaction. If the Company is deemed to be acting as the principal, the revenues are reported on a gross basis in resource sales and corresponding costs reported as resource sales-related expense. If the Company is deemed to be acting as the agent, revenue is recorded net of the corresponding costs and included in the resource sales lines of the consolidated statements of operations. The Company enters into resource royalty agreements that generate recurring resource royalty revenue. When we execute a resource royalty agreement, it generally transfers all rights to explore and produce a resource as specified in the agreement and grants us the right to a royalty on future production of that resource. Resource royalty agreements include, but are not limited to, sand, brackish water, and other resources that can be extracted from the Company's surface estate. Resource royalty revenue includes variable consideration that is dependent upon production from those resources, which is typically constrained at the inception of the agreement but is resolved when volumes are produced and settled. Resource royalty payments are typically received one month following the month of production. The Company accrues resource royalties produced but not yet paid based on historical or estimated royalty production and contract prices. The difference between estimated and actual amounts received for royalties are recorded in the period the payment is received. Refer to Note 3 - Additional Financial Statement Information for additional information regarding amounts accrued on the consolidated statements of operations.
In certain instances, resource royalty contracts provide for a bonus payment. These bonus payments are nonrefundable. Resource royalty bonus revenues are recognized when the agreement is executed as control is transferred and the Company has satisfied its performance obligation at that point in time.
Easements and other surface-related income
Easement and other surface use agreement contracts permit operators to install pipelines, roadways, electric lines, and other equipment on land owned by the Company. When the Company executes the contract, receives payment and the contract becomes effective, we make available the respective parcel of land to the grantee. Revenue is recognized upon the execution of the agreement at the effective date as the performance obligation has been satisfied and the customer has right of use. In the event of a renewal of an existing contract, the Company recognizes the revenue upon receipt of the renewal payment and the contract becomes effective. At that point, the Company has satisfied its performance obligation and control has been transferred to the grantee. Refer to Note 3 - Additional Financial Statement Information for additional information regarding amounts accrued on the consolidated statements of operations.
In certain instances, these contracts may include a provision for royalties. Royalties associated with the use of surface acreage are included in surface use royalties below.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Surface use royalties
The Company enters into surface use royalty agreements that generate recurring surface use royalty revenue. When we execute a surface use royalty agreement, it generally transfers all rights of use of the surface acreage as specified in the agreement and grants us the right to a royalty calculated on the basis of use, gross revenues or volumetric use. Surface use royalties, include but are not limited to, produced water handling and throughput royalties, skim oil royalties, and waste and reclamation royalties. Surface use royalty revenue includes variable consideration that is dependent upon volumetric use and is typically constrained at the inception of the agreement but is resolved when volumes are produced and settled. Surface use royalty payments are typically received one month following the month of production. The Company accrues surface use royalties produced but not yet paid based on historical or estimated basis of the royalty and contract prices. The difference between estimated and actual amounts received for royalties are recorded in the period the payment is received. Refer to Note 3 - Additional Financial Statement Information for additional information regarding amounts accrued on the consolidated statements of operations.
Contract Liabilities
Contract liabilities primarily relate to revenue sharing arrangements or other surface use agreements where the Company may receive payments from customers in advance of the related performance obligation being satisfied. Contract liabilities are recognized as earned over time or at a point in time based on the provisions set forth in the agreement. Current and non-current contract liabilities are presented in other current liabilities and other long-term liabilities on the consolidated balance sheets, respectively.
Income Taxes
The Company has elected to be treated as a corporation for U.S. federal income tax purposes and is subject to U.S. federal and state corporate income taxes. The Company had no activity or holdings prior to the IPO. U.S. federal income tax expense (benefit) included in the consolidated statements of operations for the year ended December 31, 2024 is calculated primarily based on the Company's share of net income (loss) of OpCo, which is taxed as a partnership. State income tax expense (benefit) included in the consolidated statements of operations for the years ended December 31, 2024, and December 31, 2023, is primarily based on the Texas Franchise Tax liability applicable to the Company and OpCo on a consolidated basis.
OpCo is treated as a partnership, or, prior to the IPO, a disregarded entity for U.S. federal income tax purposes, and therefore, has not been subject to U.S. federal income tax at an entity level. As a result, the consolidated net income (loss) in our historical financial statements does not reflect the tax expense (benefit) we would have incurred if we were subject to U.S. federal income tax at an entity level during the periods prior to the IPO. OpCo continues to be treated as a partnership for U.S. federal income tax purposes, and as such, is not subject to U.S. federal income tax. Instead, taxable income is allocated to members, including the Company, and taxable income (loss) of OpCo is reported in the respective tax returns of its members.
The Company recognizes the amount of taxes payable or refundable for the current year as well as deferred tax assets and liabilities for the future tax consequences of items which vary with respect to the timing of recognition in the Financial Statements and tax returns.
The Company recognizes the tax benefits of uncertain tax positions only if it is more likely than not that the position will be sustained on examination by taxing authorities. As of December 31, 2024 and December 31, 2023, the Company evaluated its tax filing positions and did not record a reserve with respect to uncertain tax positions. Refer to Note 7 - Income Taxes for additional information.
Concentrations of Risk
In the normal course of business, we maintain cash balances in excess of federally insured limits. The Company regularly monitors these institutions’ financial condition. We have not experienced any losses in our accounts and believe we are not exposed to any significant credit risk on cash or cash equivalents.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Significant Customers
Customers that individually comprised more than 10% of the Company’s consolidated revenues were as follows:
Year Ended December 31,
Customer A
24%
13%
Customer B
14%
15%
Customer C
10%
14%
Customer D
0%
13%
Other Contingencies
The Company recognizes liabilities for other contingencies when there is exposure that indicates it is both probable and the amount of loss can be reasonably estimated. These types of liabilities may also arise from acquisition related transactions or other commercial agreements entered into from time to time by the Company. Refer to Note 13 - Commitments and Contingencies for additional information on specific contingent liabilities.
Recently Adopted Accounting Pronouncements
In 2024, we adopted ASU 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with a single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. This ASU was effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The adoption of this update did not have a material impact on our Financial Statements.
On January 1, 2023, we adopted ASU 2016-13, Financial Instruments - Credit Losses (Topic 326), which changed how we account for credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The adoption of this update did not have a material impact on our Financial Statements.
Recent Accounting Pronouncements Not Yet Adopted
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. We plan to adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for annual periods beginning after December 15, 2024.
In November 2024, the FASB issued ASU 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40). This guidance requires tabular disclosure of specified natural expenses in certain expense captions, a qualitative description of amounts that are not separately disaggregated, and disclosure of the Company's definition and total amount of selling expenses. We plan to adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for annual periods beginning after December 15, 2026.
3. Additional Financial Statement Information
Other balance sheet information is as follows:
December 31,
Accrued liabilities
Accrued interest
$
3,795
$
1,547
Accrued professional fees
1,459
2,521
Accrued operating and capital expenses
1,035
Accrued property taxes
Accrued payroll
Total accrued liabilities
$
7,185
$
4,945
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Other income statement information is as follows related to accrued revenue amounts within the consolidated statements of operations:
December 31,
Accrued Revenue
Oil and gas royalties
$
1,680
$
3,241
Resource sales
1,282
Resource sales - Related party
Resource royalties
1,170
Resource royalties - Related party
-
Easements and other surface-related revenues
2,755
1,692
Easements and other surface-related revenues - Related party
Surface use royalties
2,033
Surface use royalties - Related party
2,054
Total accrued revenue
$
11,410
$
7,849
Supplemental cash flow information is as follows:
Year Ended December 31,
Supplemental cash flow information:
Cash paid for income taxes
$
$
Cash paid for interest
$
19,677
$
5,914
Non-cash investing and financing activities:
Offering costs in accrued liabilities
$
$
1,997
Acquisition expenditures in accounts payable and accrued liabilities
$
$
-
Insurance financing
$
$
Asset financing
$
-
$
4. Asset Acquisitions
On March 18, 2024, the Company acquired approximately 11,000 acres of land in Lea County, New Mexico for total purchase consideration of $26.4 million, inclusive of $0.3 million in transaction costs. The purchase consideration was attributed to land value of $25.9 million and intangible asset value of $0.5 million.
On May 10, 2024, the Company acquired approximately 103,000 surface acres in the Loving and Winkler Counties, Texas, and Lea County, New Mexico from a private third-party seller, for total purchase consideration of $362.6 million, inclusive of $2.1 million in transaction costs. The purchase consideration was attributed to land value of $359.7 million and other assets of $2.9 million.
On May 10, 2024, the Company acquired approximately 34,000 surface acres in Lea County, New Mexico and Andrews County, Texas from the same private third-party seller, for total purchase consideration of $42.2 million, inclusive of $0.3 million in transaction costs. The purchase consideration was all attributed to land value.
On November 1, 2024, the Company acquired approximately 1,280 surface acres in Winkler County, Texas, supply water assets and a related commercial contract from a private, third-party seller for total purchase consideration of $20.5 million, inclusive of $0.3 million in transaction costs. Of the $20.5 million total purchase consideration, $1.1 million was retained by the Company and is payable to seller within one year, contingent on no pre-closing liabilities being identified. The total purchase consideration was attributed to intangible asset value of $13.6 million, supply water assets of $4.0 million, land value of $3.8 million, other assets of $0.2 million and an assumed liability of $1.1 million.
On November 22, 2024, the Company acquired approximately 5,820 surface acres in Lea County, New Mexico from a private, third-party seller, for total purchase consideration of $26.8 million, inclusive of $0.2 million in transaction costs. The purchase consideration was attributed to land value of $18.9 million, intangible asset value of $5.1 million and other assets of $2.7 million.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
On December 19, 2024, the Company acquired approximately 46,000 surface acres in Reeves and Pecos County, Texas from a private, third-party seller, for total purchase consideration of $246.8 million, inclusive of $0.9 million in transaction costs (the “Wolf Bone Acquisition”). The purchase consideration was all attributed to land value.
5. Property, Plant and Equipment
Property, plant and equipment, net of accumulated depreciation and depletion consisted of the following:
December 31,
Oil and natural gas properties
Proved
$
36,068
$
36,054
Unproved
3,043
3,057
Total oil and natural gas properties
39,111
39,111
Land and land improvements
855,092
157,737
Water wells, pipelines, facilities, ponds and related equipment
21,109
15,132
Buildings, vehicles, equipment, furniture and other
5,162
2,594
Construction in progress
-
920,488
214,574
Less: accumulated depreciation and depletion
(17,746
)
(11,556
)
Total property, plant and equipment, net
$
902,742
$
203,018
Depreciation expense was $2.6 million and $2.4 million for the years ended December 31, 2024 and 2023, respectively. Depletion expense was $3.6 million and $4.0 million for the years ended December 31, 2024 and 2023, respectively.
6. Intangible Assets
Intangible assets, net of accumulated amortization consisted of the following:
December 31,
Water contracts
$
28,556
$
14,956
Surface use agreements
24,247
18,619
Subtotal
52,803
33,575
Less: accumulated amortization
(7,538
)
(4,933
)
Total intangible assets, net
$
45,265
$
28,642
December 31,
Accumulated amortization
Water contracts
$
3,516
$
2,193
Surface use agreements
4,022
2,739
Total accumulated amortization
$
7,538
$
4,933
On March 18, 2024, the Company acquired a surface use agreement as part of an acquisition of land in Lea County, New Mexico. The purchase consideration attributable to the surface use agreement was approximately $0.5 million, which will be amortized over a term of 30 years.
On November 1, 2024, the Company acquired a water contract as part of an acquisition of land in Winkler County, Texas. The purchase consideration attributable to the surface use agreement was approximately $13.6 million, which will be amortized over a term of 7 years.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
On November 22, 2024, the Company acquired surface use agreements as part of an acquisition of land in Lea County, New Mexico. The purchase consideration attributable to the surface use agreements was approximately $5.1 million, which will be amortized over a term of 15 years.
The Company recognized $2.6 million and $2.2 million in amortization expense for the years ended December 31, 2024 and 2023, respectively. The remaining weighted average amortization period for both surface use agreements and water contracts was 10.9 years and 12.8 years as of December 31, 2024 and 2023, respectively.
Future amortization expense related to such intangibles for the next five years and thereafter as of December 31, 2024 is as follows:
Amortization
Expense
4,560
4,560
4,560
4,560
4,560
Thereafter
22,465
Total
$
45,265
7. Income Taxes
As a result of the IPO, the Company became the sole managing member of OpCo, which is treated as a partnership for U.S. federal and state and local income tax purposes. As a partnership, OpCo is not subject to U.S. federal and certain state and local income taxes. The taxable income or loss generated by OpCo is passed through to, and included in, the taxable income or loss of its members, including the Company. Beginning with the IPO, the Company is subject to U.S. federal income taxes and state and local income taxes with respect to its allocable share of taxable income or loss of OpCo, as well as any stand-alone income or loss generated by the Company. Prior to the IPO, OpCo was subject to entity level state income tax in the state of Texas.
Income Tax Provision
The components of the income tax expense are as follows:
Year Ended December 31,
Current tax expense
Federal
$
1,693
$
-
State
Total current tax expense
2,286
Deferred tax benefit
Federal
(406
)
-
State
(5
)
-
Total deferred tax benefit
(411
)
-
Total income tax expense
$
1,875
$
Effective Tax Rate
The Company's overall effective tax rate differs from the U.S statutory rate primarily due to the fact that prior to the IPO, OpCo was structured as a partnership for U.S. federal income tax and subsequent to the IPO, the OpCo income (loss) attributable to the noncontrolling interests in OpCo is not subject to U.S. federal income tax at the Company or OpCo.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
The reconciliation of income taxes at the federal statutory level to provision for income taxes is as follows:
Year Ended December 31,
$
%
$
%
U.S. federal tax (benefit) expense at statutory rate
$
(8,317
)
21.0
%
$
13,344
21.0
%
State tax, net of federal benefit
-1.4
%
0.6
%
Pre-IPO non-taxable loss (income)
9,794
-24.7
%
(13,344
)
-21.0
%
Noncontrolling interests
(168
)
0.4
%
-
-
Non-deductible expenses
-
0.0
%
-
-
Total effective tax rate
$
1,875
-4.7
%
$
0.6
%
Deferred Tax Assets and Liabilities
The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdictions in which the Company operates for the year in which those temporary differences are expected to be recovered or settled.
The tax effects of each temporary difference and carryforward are as follows:
December 31,
Deferred tax assets:
Investment in partnership
$
$
-
Disallowed interest carryforward
-
Total deferred tax assets:
-
Deferred tax liabilities
-
-
Valuation allowance
-
-
Net deferred tax assets
$
$
-
The Company evaluates all deferred tax assets as to their future realization using positive and negative evidence. As of December 31, 2024, the Company believes it is more likely than not that all deferred tax assets will be realized and as a result, the Company has not recorded a valuation allowance against its deferred tax assets.
The Company evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. As of December 31, 2024, the Company has no significant uncertain tax positions.
The Company files income tax returns in the U.S. federal jurisdiction and New Mexico on a separate basis. The Company and OpCo file the Texas Franchise Tax on a consolidated basis. There are currently no federal or state income tax examinations underway for these jurisdictions. The Company's federal and state returns remain open to examination for tax years 2021 through 2024.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
8. Debt
As of December 31, 2024 and December 31, 2023, our debt consisted of the following:
December 31,
Term loan
$
355,000
$
95,000
Revolving credit facility
30,000
35,000
Other
Total debt
385,496
130,494
Current portion of long-term debt
(424
)
(20,339
)
Unamortized debt issuance costs
(4,257
)
(1,812
)
Total long-term debt
$
380,815
$
108,343
Credit Facilities
On July 3, 2023, the Company entered into a four-year credit agreement providing for (i) a $100.0 million term loan (as amended and as described herein, the “Term Loan”), and (ii) a $50.0 million revolving credit facility (as amended and as described herein, the “Revolving Credit Facility” and, together with the Term Loan, the “Credit Facilities”). Upon the closing of the Credit Facilities, the Ag Loan (as defined below) was terminated.
On May 10, 2024, the Company entered into a credit agreement amendment (the “First Credit Agreement Amendment”), which amended the Credit Facilities to increase the principal amount of the Term Loan to $350.0 million and increase the available capacity of the Revolving Credit Facility to $75.0 million. Following the First Credit Agreement Amendment, the Company borrowed approximately $265.0 million under the Term Loan to fund a portion of the purchase price of certain acquisitions permitted by the credit agreement.
Immediately following the IPO, we used approximately $100.0 million of the net proceeds to repay outstanding borrowings under our Credit Facilities.
On November 4, 2024, the Company entered into a credit agreement amendment (“Second Credit Agreement Amendment”) to (i) increase the maximum available amount under the Revolving Credit Facility to $100.0 million, (ii) increase the principal amount of the Term Loan to $300.0 million, (iii) provide for additional $75.0 million uncommitted delayed draw term loan (the “Uncommitted DDTL”), and (iv) eliminate the Company’s obligation to make Term Loan amortization payments. On December 19, 2024, the Company borrowed $55.0 million under the Uncommitted DDTL to fund a portion of the purchase price of the Wolf Bone Acquisition, thereby increasing the aggregate outstanding amount of the Term Loan to $355.0 million. The Uncommitted DDTL terminated following such borrowing, and the Company is not permitted to borrow any additional amounts under the Uncommitted DDTL.
We may elect for outstanding borrowings under our Credit Facilities to accrue interest at a rate based on either (i) a forward-looking term rate based on the secured overnight financing rate (“Term SOFR”) plus 0.10%, or (ii) the base rate, in each case plus an applicable margin. Borrowings under our Credit Facilities accrue interest based on a five-tiered pricing grid tied to our current leverage ratio. The applicable margin ranges from (i) prior to the consummation of the IPO, 3.00% to 4.00% in the case of Term SOFR loans and letter of credit fees, and 2.00% to 3.00% in the case of base rate loans, and commitments fees of 0.50%, and (ii) following consummation of the IPO, 2.75% to 3.75% in the case of Term SOFR loans and letter of credit fees, and 1.75% to 2.75% in the case of base rate loans, and commitment fees range from 0.375% to 0.50%. Interest on all outstanding SOFR loans shall be payable on the last day of each interest period, which may be, at the Company’s election, 1-month, 3-months, or 6-months. Interest on all outstanding base rate loans shall be payable on the first day of each calendar quarter.
Our Credit Facilities are secured by a first priority security interest in substantially all of our assets and the assets of our restricted subsidiaries, which are party to our Credit Facilities as guarantors.
Subject to certain exceptions and materiality qualifiers, our Credit Facilities include certain customary affirmative and negative covenants, which, among other things, restrict our ability and our restricted subsidiaries’ ability, subject to certain exceptions, to incur debt, grant liens, make restricted payments and investments, issue equity, sell or lease assets, dissolve or merge with another entity, enter into transactions with affiliates or restrictive agreements, change our business, prepay debt and amend our organizational
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
documents and material agreements. Our Credit Facilities allow us to make cash restricted payments to our shareholders in accordance with the Company’s constituent documents, subject to the following conditions: (i) if the Company’s pro forma leverage ratio is less than 3.50 to 1:00 for the most recently ended four-fiscal quarter period, so long as (A) no default or event of default exists or would result from such restricted payment and (B) the Company’s pro forma liquidity is at least $10,000,000, and (ii) if the Company’s pro forma leverage ratio is greater than 3.50 to 1:00 for the most recently ended four-fiscal quarter period, so long as (A) no default or event of default exists or would result from such restricted payment, (B) the Company’s pro forma liquidity is at least $25,000,000, and (C) the Company’s Distributable Free Cash Flow Amount is greater than $0 after giving effect to such restricted payment. “Distributable Free Cash Flow Amount” is the lesser of the Company’s free cash flow for (x) the most recently ended four-fiscal quarter period and (y) the most recently ended two-fiscal quarter period, in each case minus the aggregate amount of certain restricted payments made during or after each such period.
In addition, we are required to comply with the following financial maintenance covenants: (i) a maximum leverage ratio as of the last day of each fiscal quarter of (a) prior to the consummation of the IPO, no greater than 3.50:1.00 for the period of the last four consecutive fiscal quarters, or (b) following the consummation of the IPO, 4.00:1.00 for the period of the last four consecutive fiscal quarters (subject, in either case, to (x) a 0.50:1.00 leverage step-up for any “qualified acquisition” for the fiscal quarter in which such “qualified acquisition” occurs and the immediately following two fiscal quarters, at the Company’s election, (y) cap of 0.50:1.00 on such step-up regardless of the total number of “qualified acquisitions” and certain other limitations set forth therein, and (z) an additional step up of 0.25 for the second quarter of 2024 in connection with consummation of the East Stateline Acquisition; (ii) a minimum interest coverage ratio of at least 2.75 to 1.00 as of the last day of each fiscal quarter ending on or after the date of the closing of the IPO; and (iii) a minimum debt service coverage ratio of at least 1.25 to 1.00 as of the last day of each fiscal quarter ending prior to the date on which the IPO is consummated.
Our Credit Facilities contain customary events of default, including for our failure and the failure of other loan parties to comply with the various financial, negative and affirmative covenants under our Credit Facilities (subject to the cure provisions set forth therein). During the existence of an event of default (as defined under our Credit Facilities), the agent, with the consent of or at the direction of the requisite lenders thereunder, has a right to, among other available remedies, terminate the commitments and/or declare all outstanding loans and accrued interest and fees under our Credit Facilities to be immediately due and payable.
The Company was in compliance with these covenants as of December 31, 2024.
The estimated fair value of our Credit Facilities approximates the principal amount outstanding because the interest rates applicable to such amounts are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
Term Loan
The Term Loan was subject to quarterly principal amortization payments payable on the first day of each quarter through the third quarter of 2024; as a result of the Second Credit Agreement Amendment, the Company’s obligation to make the quarterly principal amortization payments was eliminated. Any principal amounts outstanding on the maturity date, July 3, 2027, become due and payable on such date.
Debt issuance costs associated with the Term Loan consist of fees incurred to secure the financing and are amortized over the life of the loan using the effective interest method. The amortization of these costs totaled $1.2 million and $0.3 million for the years ended December 31, 2024 and 2023, respectively, which are included in interest expense, net in the consolidated statements of operations. As of December 31, 2024 and December 31, 2023, net debt issuance costs of $4.3 million and $1.8 million, respectively, associated with the Term Loan are reported as a direct deduction from the carrying amount of the related long-term debt.
As of December 31, 2024 and 2023, the Company incurred $19.2 million and $4.2 million, respectively, of interest expense related to the Term Loan and the related weighted average interest rate was 8.47% and 8.62%, respectively. The accrued interest payable related to the Term Loan was $3.4 million and $1.2 million as of December 31, 2024 and December 31, 2023, respectively.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Revolving Credit Facility
The Revolving Credit Facility provides for incremental borrowings up to the revolving commitment of $100.0 million. It also includes an incremental revolving commitment that permits the Company to increase the aggregate amount of the Revolving Credit Facility, subject to the applicable lenders’ willingness to participate and other customary terms and conditions, by an amount not to exceed the sum of (i) $50.0 million plus (ii) the amount of any prior principal repayments of the Term Loan following the closing of the Credit Agreement Amendment (up to $50.0 million). The Revolving Credit Facility provides availability for the issuance of letters of credit on the Company’s behalf in an aggregate amount not to exceed $5.0 million.
Principal amounts borrowed under the Revolving Credit Facility may be repaid from time to time without penalty. Any principal amounts outstanding on the maturity date, July 3, 2027, become due and payable on such date.
The Company also pays a commitment fee to each lender quarterly in arrears on the daily average unused amount of the revolving credit commitment of such lender under the Revolving Credit Facility. For the year ended December 31, 2024, the Company paid $0.2 million in commitment fees. For the year ended December 31, 2023, the Company paid an immaterial amount in commitment fees.
Debt issuance costs associated with the Revolving Credit Facility consist of fees incurred to secure the financing and are amortized over the life of the loan using the effective interest method. The amortization of these costs totaled $0.4 million and $0.1 million for the years ended December 31, 2024 and 2023, respectively, which is included in interest expense, net, in the consolidated statements of operations. Short-term debt issuance costs of $0.5 million and $0.3 million associated with the Revolving Credit Facility as of December 31, 2024 and December 31, 2023, respectively, are deferred and presented in prepaid expenses and other current assets on the consolidated balance sheets. Long-term debt issuance costs of $0.7 million and $0.6 million associated with the Revolving Credit Facility as of December 31, 2024 and December 31, 2023, respectively, are deferred and presented in other assets on the consolidated balance sheets.
As of December 31, 2024 and 2023, the Company incurred $2.8 million and $1.1 million, respectively, of interest expense related to the Revolving Credit Facility and the related weighted average interest rate was 8.39% and 8.65%, respectively. The accrued interest payable related to the Revolving Credit Facility was $0.4 million and $0.3 million as of December 31, 2024 and December 31, 2023, respectively.
Ag Loan
On October 14, 2021, the Company entered into a seven-year $65.0 million credit agreement (the “Ag Loan”) with Capital Farm Credit, ACA, as agent for a federal land credit association.
The Ag Loan was terminated on July 3, 2023 in connection with the closing of the Credit Facilities. The Ag Loan was secured by a perfected first-lien security interest in substantially all assets of certain subsidiaries of DBR Land LLC and was guaranteed by such subsidiaries and DBR Land LLC.
For the year ended December 31, 2023, the Company incurred $1.5 million of interest expense and a weighted average interest rate of 5.25% related to the Ag Loan.
Debt Maturities
The following table summarizes the Company’s debt obligations as of December 31, 2024. Estimated future payments for the debt based on the amount outstanding are shown below:
As of December 31,
Total
Term loan
$
-
$
-
$
355,000
$
-
$
-
$
355,000
Revolving credit facility
-
-
30,000
-
-
30,000
Other
-
-
-
Total debt
$
$
$
385,000
$
-
$
-
$
385,496
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
9. Shareholders’ and Member’s Equity
Shareholders’ Equity
Holders of Class A shares and Class B shares vote together as a single class on all matters presented to our shareholders, except as otherwise required by applicable law or by the A&R LLC Agreement. To the extent we pay any cash dividends on our Class A shares, under the terms of our organizational documents, Class B shares are not entitled to participate.
Member’s Equity
Prior to the Division, NDB LLC held 100% of the limited liability company interests of OpCo. OpCo’s limited liability company interests were generally consistent with ordinary equity ownership interests. Distributions (including liquidating distributions) were to be made to the sole member at a time to be determined by the board of managers. There were no restrictions on distributions. The sole member’s equity account was adjusted for distributions paid to, and additional capital contributions that were made by the sole member. All revenues, costs and expenses of OpCo were allocated to the sole member in accordance with the initial limited liability company agreement of LandBridge Company LLC, dated as of September 27, 2023 (the “Prior LLC Agreement”).
Redemptions and Cancellations
During the year ended December 31, 2024, no Class B shares were redeemed for Class A shares.
In December 2024, as part of the December Private Placement we purchased 2,498,751 OpCo Units from LandBridge Holdings, which resulted in the cancellation of a corresponding number of Class B shares. Refer to Note 1 - Organization and Nature of Operations.
Dividends and Distributions
On November 5, 2024, our board of directors declared a dividend on our Class A shares of $0.10 per share to shareholders of record as of December 5, 2024. The dividends declared totaled $1.7 million and were paid on December 19, 2024. In conjunction with the dividend payment, a distribution of $0.10 per unit was paid to OpCo unit holders. The distribution, totaling $5.6 million, was also paid on December 19, 2024.
On February 21, 2025, our board of directors declared a dividend on our Class A shares of $0.10 per share, payable on March 20, 2025 to shareholders of record as of March 6, 2025.
10. Share-Based Compensation
A summary of the Company’s aggregate share-based compensation expense (income) is shown below. Substantially all share-based compensation expense (income) is included in general and administrative expense (income) on the consolidated statements of operations.
Year Ended December 31,
Incentive Units
$
91,307
$
(17,230
)
Restricted Share Units
4,028
-
Total share-based compensation expense (income)
$
95,335
$
(17,230
)
Incentive Units
Prior to the Division, our management and employees participated in an equity-based incentive unit plan managed by NDB LLC, the direct parent of the Company. The NDB Incentive Units consisted of time-based awards of profits interest in NDB LLC.
On July 1, 2024, as a result of the Division, holders of NDB Incentive Units received an identical number of LBH Incentive Units consisting of time-based awards of profits interest in LandBridge Holdings. Pursuant to the Division, the LBH Incentive Units held at LandBridge Holdings are the only incentive units attributable and allocated to the Company.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
The incentive units received by the NDB Incentive Unit holders in conjunction with the Division were considered a modification of the awards under ASC 718. As discussed above, the NDB Incentive Units that previously received liability award accounting are now accounted for as equity awards at LandBridge Holdings. In conjunction with the modification, there was no immediate incremental expense recognized as the fair value of the modified equity awards at the modification date was less than the fair value of the liability awards remeasured immediately prior to modification. As of the modification date, the LBH Incentive Units had $24.2 million of unrecognized share-based compensation expense that will be recognized over a weighted average remaining term of 2.0 years.
The NDB Incentive Units prior to the modification date were estimated using a Monte Carlo Simulation with the following inputs to determine the remeasurement date fair values:
6/30/2024
12/31/2023
Estimated equity value
$
1,541,210
$
811,521
Expected life (in years)
1.7
2.8
Risk-free interest rate
4.7
%
4.0
%
Dividend yield
%
%
Volatility
%
%
Marketability discount
18% - 19%
24% - 26%
LBH Incentive Units granted during the year were estimated using a Monte Carlo Simulation with the following inputs at each of the following grant dates:
7/1/2024(1)
7/18/2024
10/29/2024
12/9/2024
Share price
$
22.96
$
28.45
$
53.84
$
62.29
Expected life (in years)
1.5
2.0
2.2
2.1
Risk-free interest rate
4.8
%
4.4
%
4.0
%
4.0
%
Dividend yield
%
%
%
%
Volatility
40% - 225%
40% - 132%
35% - 72%
40% - 76%
Marketability discount
11% - 32%
12% - 30%
12% - 22%
13% - 22%
(1) The LBH Incentive Units utilized the same inputs for the modification date fair value as it occurred on the same date as the 7/1/2024 grant date.
A summary of LBH Incentive Units activity during the year ended December 31, 2024 is shown in the following table:
Incentive Units
Weighted Average Grant Date Fair Value
Weighted Average Remaining Contractual Term (years)
Outstanding at December 31, 2023(1)
9,992
$
3,590
Granted
21,070
3,712
Forfeited
(1,042
)
3,591
Outstanding at December 31, 2024(2)
30,020
$
5,130
1.46
(1) Prior to the Division, incentive units outstanding at December 31, 2023 were the NDB Incentive Units. The per unit amount reflected is the weighted average fair value per unit as of the measurement date as required for liability accounting.
(2) The units outstanding as of December 31, 2024 reflect the effects of the Division and only include the LBH Incentive Units. The grant date fair value per unit amount includes the modification date weighted average per unit fair value of $7,959 per unit.
As of December 31, 2024, remaining unrecognized compensation expense for the LBH Incentive Units was $80.4 million and the weighted average remaining vesting period was approximately 2.3 years.
Included in share-based compensation expense during the year ended December 31, 2024 is the reversal of an immaterial amount of expense related to employee departures. Share-based compensation expense during the year ended December 31, 2024, includes $1.2 million of additional expense related to accelerated vesting due to an employee departure. There were no accelerations during the year ended December 31, 2023.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Restricted Share Units
Under the LTIP, participants were granted RSUs which are subject to graded vesting generally ranging from one to three years. The fair value of the awards is based on our share price on the date of grant with compensation expense recognized on a straight-line basis over the applicable vesting period.
A summary of RSU activity during the year ended December 31, 2024 is shown in the following table:
RSUs
Weighted Average Grant Date Fair Value
Weighted Average Remaining Contractual Term (years)
Aggregate Intrinsic Value
Outstanding at December 31, 2023
-
$
-
-
$
-
Granted
772,854
31.36
Forfeited
(23,325
)
31.16
Vested
-
-
Outstanding at December 31, 2024
749,529
$
31.37
1.46
$
48,420
As of December 31, 2024, remaining unrecognized compensation expense for the RSUs was $19.5 million and the weighted average remaining vesting period was approximately 2.5 years.
Included in share-based compensation expense during the year ended December 31, 2024 is the reversal of an immaterial amount of expense related to employee departures. There were no accelerations of expense during the years ended December 31, 2024 and 2023.
Defined Contribution Plan
WaterBridge Management Company LLC, an affiliate of the Company, sponsors a defined contribution plan available to all eligible employees. Qualifying participants receive a matching contribution based on the amount participants contribute to the plan up to 7% of their qualifying compensation. Contributions of an immaterial amount were made during the years ended December 31, 2024 and 2023.
11. Earnings Per Share
The Company’s unvested RSUs are deemed to be participating securities; therefore, the Company will apply the two-class method for the calculation of basic EPS for the Class A shares. Diluted EPS attributable to Class A shares is calculated under both the two-class method and the treasury stock method, and the more dilutive of the two calculations is presented.
Class B Shares are considered potentially dilutive shares of Class A shares because they are convertible into Class A shares on a one-for-one basis; therefore, the Company applied the if-converted method for the calculation of diluted EPS for the Class A shares.
We determined that the presentation of EPS for the period prior to the IPO would not be meaningful due to the significant nature of the Corporate Reorganization on our capital structure. Therefore, EPS information has not been presented for periods prior to the IPO.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
The following table sets forth the computation of basic and diluted EPS attributable to our Class A shares for the period from July 1, 2024 to December 31, 2024, which represents the period subsequent to the IPO.
(in thousands, except for share and per share amounts)
Period of July 1 - December 31, 2024
Numerator
Net income
$
5,398
Less: Net income attributable to noncontrolling interest
Net income attributable to LandBridge Company LLC
5,110
Less: Earnings allocated to participating securities
Basic net income attributable to LandBridge Company LLC
$
4,912
Plus: Net income attributable to noncontrolling interest
Plus: Undistributed earnings reallocation adjustment to participating securities
Diluted net income attributable to shareholders
$
5,290
Denominator
Basic weighted average shares outstanding
17,807,323
Dilutive Class B shares outstanding
55,562,750
Diluted weighted average shares outstanding
73,370,073
Basic net income per share of Class A shares
$
0.28
Diluted net income per share of Class A shares
$
0.07
Class B shares outstanding as of December 31, 2024 were determined to be dilutive and have been included in the computation of diluted net income per share. In addition, weighted-average RSUs of 693,123 were evaluated under the treasury stock method for potentially dilutive effects and were determined to be anti-dilutive for the year ended December 31, 2024 and have been excluded from the computation of diluted net income per share.
12. Related Party Transactions
Year Ended December 31,
Financial Statements Location
Revenues - Related Party
Affiliate access agreements
Surface use royalties
$
18,499
$
5,436
Data center agreement
Easements and other surface-related revenues
8,000
-
Affiliate access agreements
Easements and other surface-related revenues
5,486
4,249
Affiliate access agreements
Resource royalties
3,062
-
Affiliate access agreements
Resource sales
1,785
$
35,434
$
11,470
December 31,
Financial Statements Location
Accounts Receivable - Related Party
Affiliate access agreements
Related party receivable
$
2,111
$
1,037
Accounts Payable - Related Party
Shared services agreement
Related party payable
$
$
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Shared Services Agreement
The Company is party to a services agreement with WaterBridge Operating LLC (“WaterBridge Operating”), an affiliate of the Company, and other affiliates pursuant to which the Company receives common management and general, administrative, overhead and operating services in support of the Company’s operations and development activities. The Company reimburses all fees incurred by WaterBridge Operating or its affiliates for services provided to the Company under the agreement. For shared services, the basis of allocation is an approximation of time spent on activities supporting the Company. For shared expenses paid on behalf of the Company, the costs are directly allocated to the Company based on its pro rata share of the expenses. For the years ended December 31, 2024 and 2023, the Company paid approximately $10.1 million and $5 million for the shared services and direct cost reimbursements, respectively.
Affiliate Facility Access Agreements
The Company is party to facility access and surface use agreements and easements and rights-of-way with WaterBridge Texas Midstream LLC, WaterBridge Stateline LLC and Desert Environmental LLC, each an affiliate of the Company. Under these agreements, the Company has granted such affiliates certain rights to construct, operate and maintain produced water, brackish water and waste reclamation facilities on our land, as applicable, in the ordinary course of business. These agreements include a standard fee schedule and provision for specified surface use activities. The agreements also include a provision for royalties related to certain specified activities.
Equity Sponsor Services Agreement
Five Point Energy, LLC (“Five Point”), our financial sponsor, invoices the Company, and the Company reimburses Five Point in cash, for expenses associated with the Company’s use of Five Point’s geographic information system (“GIS”) and certain legal services provided by Five Point. The reimbursement includes allocated Five Point personnel costs and third-party software and hardware expenses and is determined based on the Company’s use of Five Point’s total services for such period. For the years ended December 31, 2024 and 2023, the GIS and legal services reimbursements paid were $0.3 million and $0.2 million, respectively. As of December 31, 2024 and December 31, 2023, the Company had an immaterial amount due to Five Point.
Data Center Agreement
The Company is party to 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, a joint venture between a third-party developer and funds affiliated with Five Point (“PowLan”). PowLan is obligated to meet certain timing milestones to maintain its lease, to include the commencement of site development within a two-year period and 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, for a two-year site selection and pre-development period. The deposit of $8.0 million was paid in December 2024 and is included within Easements and other surface-related revenues - Related Party on the consolidated statements of operations for the year ended December 31, 2024.
13. Commitments and Contingencies
Subordination payments
In connection with the October 2021 business acquisition of Hanging H Ranch, Inc., the Company agreed to pay one of the sellers $5.0 million as additional consideration over the next ten years on each anniversary of closing, beginning on October 14, 2022, and in exchange for the additional consideration, such seller agreed to subordinate its rights under a grazing lease to the rights of the Ag Loan lender.
On August 8, 2024, the Company entered into an agreement accelerating the remaining subordination payments and terminating the grazing lease for a total consideration of $5.8 million. On August 13, 2024, the existing liability balances on the consolidated balance sheets as of August 8, 2024, consisting of $0.5 million within other current liabilities and $2.7 million within other long-term liabilities, were released. The incremental consideration of $2.6 million was recorded within general and administrative expense (income) on the consolidated statements of operations.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
As of December 31, 2023, $0.5 million was reflected within other current liabilities, with nothing reflected as of December 31, 2024 on the consolidated balance sheets. As of December 31, 2023, $2.6 million was reflected within other long-term liabilities, with nothing reflected as of December 31, 2024 on the consolidated balance sheets. These amounts as of December 31, 2023 represented the present value of the total $5.0 million in additional consideration.
Litigation
The Company records liabilities related to litigation and other legal proceedings when they are either known or considered probable and can be reasonably estimated. Legal proceedings are inherently unpredictable and subject to significant uncertainties, and significant judgment is required to determine both probability and the estimated amount. As a result of these uncertainties, any liabilities recorded are based on the best information available at the time. As any new information becomes available, the Company reassesses the potential liability related to pending litigation. As of December 31, 2024 and December 31, 2023, the Company had no amounts recorded in liabilities related to any legal matters.
14. Subsequent Events
On February 25, 2025, the Company acquired approximately 3,000 surface acres in Lea County, New Mexico, from a private third-party seller for total consideration of $16.7 million.
15. Supplemental Oil and Gas Information (Unaudited)
The Company’s oil and natural gas reserves are attributable solely to properties within the United States, specifically in the Permian Basin.
Capitalized Oil and Natural Gas Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion are as follows:
December 31,
(in thousands)
Oil and natural gas interests:
Proved
$
36,068
$
36,054
Unproved
3,043
3,057
Total oil and natural gas interests
39,111
39,111
Accumulated depletion
(10,732
)
(7,157
)
Net oil and natural gas interests capitalized
$
28,379
$
31,954
Costs Incurred in Oil and Natural Gas Activities
The Company did not incur any oil and natural gas property acquisition, exploration or development activities during the years ended December 31, 2024 and 2023.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Results of Operations from Oil and Natural Gas Producing Activities
The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas activities. It does not include any interest costs or general and administrative costs and therefore, is not necessarily indicative of the net operating results of the Company’s oil and natural gas activities.
December 31,
(in thousands)
Oil and gas royalties
$
16,027
$
20,743
Severance and ad valorem taxes
(1,252
)
(1,159
)
Transportation, processing and other
(93
)
(86
)
Depletion
(3,575
)
(4,050
)
Results of operations from oil and gas producing activities
$
11,107
$
15,448
The reserves as of December 31, 2024 and December 31, 2023 presented below were prepared by W.D. Von Gonten & Co, whose reports as of those dates are filed as exhibits to this Annual Report. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, price changes and other factors. The reserves are located in the Delaware Basin across Loving, Reeves and Pecos Counties in Texas.
Guidelines indicated in FASB ASC Topic 932 Extractive Industries - Oil and Gas (“ASC 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including quality and basis differentials, to the period-end estimated quantities of oil and natural gas to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future production costs are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the Securities and Exchange Commission (“SEC”). These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
Analysis of Changes in Proved Reserves
The following table sets forth information regarding the Company’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for the period presented:
Oil
Natural Gas
Natural Gas Liquids
Total
(MBbls)
(MMcf)
(MBbls)
(MBOE)
Net Proved Reserves as of January 1, 2023
1,776
4,972
2,936
Revisions of previous estimates (1)
(80
)
(11
)
(71
)
Extensions, discoveries and other additions (2)
Production
(225
)
(693
)
(68
)
(409
)
Net Proved Reserves as of December 31, 2023
1,696
5,235
2,913
Revisions of previous estimates (1)
1,492
Extensions, discoveries and other additions (2)
Production
(179
)
(729
)
(77
)
(378
)
Net Proved Reserves as of December 31, 2024
1,619
6,010
3,018
Net Proved Developed Reserves
January 1, 2023
1,821
1,047
December 31, 2023
2,957
1,495
December 31, 2024
4,010
1,739
Net Proved Undeveloped Reserves
January 1, 2023
1,154
3,151
1,889
December 31, 2023
2,278
1,418
December 31, 2024
2,000
1,279
(1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.
(2) Extensions and other additions were from conversions of unproved reserves to proved developed reserves due to additional drilling activity. These extensions included no additions to proved undeveloped reserves for the years ended December 31, 2023 or 2024.
Changes in proved reserves that occurred during the year ended December 31, 2023 were primarily due to:
•negative revisions of approximately 71 Mboe. 97 Mboe decrease due to changes in commodity prices partially offset by 26 Mboe due to changes in projected well performance; and
•well additions, extensions and discoveries of approximately 457 Mboe. 457 Mboe was added as proved over fourteen gross well locations based on increased operator drilling activity.
Changes in proved reserves that occurred during the year ended December 31, 2024 were primarily due to:
•positive revisions of approximately 473 Mboe. 520 Mboe increase primarily due to changes in projected well performance partially offset by negative revisions of 47 Mboe due to changes in commodity prices; and
•well additions, extensions and discoveries of approximately 10 Mboe. 10 Mboe was added as proved over one gross well location based on decreased operator drilling activity.
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted first-day-of-the-month commodity prices for the period presented. All prices are adjusted for quality, energy content and
LandBridge Company LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)
regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves.
The following table sets forth the future net cash flows related to proved oil and gas reserves based on the standardized measure prescribed in ASC 932:
December 31,
(in thousands)
Future cash inflows
$
133,197
$
146,605
Future production costs
(8,804
)
(9,745
)
Future income tax expense
(11,195
)
(1,026
)
Future net cash flows (undiscounted)
113,198
135,834
Annual discount 10% for estimated timing
(50,468
)
(61,055
)
Total
$
62,730
$
74,779
The primary sources of change in the standardized measure of discounted future net cash flows are as follows:
December 31,
December 31,
(in thousands)
Standardized measure, beginning of period
$
74,779
$
94,146
Sales, net of production costs
(14,682
)
(19,498
)
Net changes in prices and production costs related to future production
(8,679
)
(20,475
)
Extensions, discoveries and improved recovery, net of future production costs
15,419
Revisions of previous quantity estimates, net of related costs
9,647
(1,836
)
Net change in income taxes
(5,752
)
Accretion of discount
6,490
7,169
Changes in timing and other
(304
)
Net decrease in standardized measures
(12,049
)
(19,367
)
Standardized measure, end of period
$
62,730
$
74,779

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2024.
In designing and evaluating our disclosure controls and procedures, management recognizes that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Additionally, in designing disclosure controls and procedures, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected.
Management’s Annual Report on Internal Control Over Financial Reporting.
This Annual Report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company's registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
Changes in Internal Control over Financial Reporting
We will not be required to make our first assessment of the effectiveness of our internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act until our Annual Report on Form 10-K for the fiscal year ended December 31, 2025. Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Emerging Growth Company Status” for more information.

---

ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
Trading Arrangements
During the three months ended December 31, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(c) of Regulation S-K.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to our proxy statement for the 2025 Annual Meeting of Stockholders (the “2025 Proxy Statement”), which will be filed with the SEC not later than 120 days subsequent to December 31, 2024.
We have adopted a Code of Business Conduct and Ethics and whistleblower policy (“Code of Ethics”) that applies to all of our directors, officers and employees, including our principal executive, principal financial and principal accounting officers, or persons performing similar functions, and other employees of the Company and/or its affiliates who provide services to the Company. Our Code of Ethics is posted on our website located at https://ir.landbridgeco.com/governance/governance-documents. We intend to disclose future amendments to certain provisions of the Code of Ethics, and waivers of the Code of Ethics granted to executive officers and directors, on the website within four business days following the date of the amendment or waiver.
We have an insider trading policy governing the purchase, sale and other dispositions of our securities that applies to all of our personnel, including directors, officers, employees, and other covered persons. We believe that our insider trading policy and repurchase procedures are reasonably designed to promote compliance with insider trading laws, rules and regulations, and listing standards applicable to the Company. A copy of the Company’s insider trading policy is filed as Exhibit 19.1 to this Annual Report.

---

ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2024.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain information as of December 31, 2024, with respect to compensation plans under which equity securities of LandBridge are authorized for issuance.
Plan Category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted- average exercise price of outstanding options, warrants and rights (1)
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(2)
(a)
(b)
(c)
Equity compensation plans approved by security holders
-
-
-
Equity compensation plans not approved by security holders
749,529
-
2,850,471
Total
749,529
-
2,850,471
(1)	All outstanding awards under the LTIP represent restricted stock units subject to time-based vesting, which do not have an exercise price.
(2) On January 1 of each calendar year, the total number of Class A shares reserved and available for delivery with respect to awards under the LTIP increases by a number of Class A shares equal to the lesser of (x) 5% of the total number of Class A shares and Class B shares outstanding as of December 31 of the immediately preceding calendar year; (y) the number of Class A shares required to bring the total Class A shares available for issuance under the LTIP to 5% of the total number of Class A shares and Class B shares outstanding as of December 31 of the immediately preceding calendar year; or (z) such smaller number of Class A shares as determined by our board of directors.
The other information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2024.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2024.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2024.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as a part of this report:
(1) Financial Statements: The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8. Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.
(2) Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted.
(3) Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form 10-K.