LandBridge Corp: Form 10-Q for the period ended Sep 30, 2024

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 I, Item 1. “Financial Statements” of this Quarterly 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 Quarterly 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 Offering, to OpCo and its subsidiaries, our predecessor for financial reporting purposes, and (ii) subsequent to the consummation of the Corporate Reorganization and the Offering, to LandBridge and its subsidiaries, including OpCo and its subsidiaries. The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report. Our financial statements have been prepared in accordance with GAAP. The unaudited condensed consolidated financial statements as of and for the three and nine months ended September 30, 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 interim periods on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. The results of operations for interim periods are not necessarily indicative of the results that may be expected for any other interim period or for a full year.

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 Offering. Each of the East Stateline Acquisition, the Credit Agreement Amendment, the Corporate Reorganization and the Offering is reflected in the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” solely from and after its respective completion.

Overview

Land is critical to energy development and production. Access to expansive surface acreage is necessary for oil and natural gas development, solar power generation, power storage, data centers and non-hazardous oilfield reclamation and solid waste facilities. Further, the significant industrial economy that exists to service and support energy development requires access to surface acreage to support those activities. These dynamics drove our acquisition and ownership of approximately 221,000 surface acres in Texas and New Mexico located in and around the Delaware sub-basin of the prolific Permian Basin, which is among the most economic, liquids-rich hydrocarbon resources in the United States. Our strategy is to actively manage our land and resources to support and encourage oil and natural gas 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 three and nine months ended September 30, 2023, we generated $11.5 million and $40.5 million, respectively, of non-oil and gas royalty revenue, or $159 and $562, respectively, per owned surface acre. For the three and nine months ended September 30, 2024, we increased non-oil and gas royalty revenue to $25.6 million and $61.9 million, respectively, or $116 and $409, respectively, per owned surface acre. The three and nine months ended September 30, 2024 include the effects of the Acquisitions beginning on March 18, 2024, in the case of the Lea County Acquisition, and May 10, 2024, in the case of the May 2024 Acquisitions. 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, 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 September 30, 2024, handles approximately 2.3 million bpd of water associated with oil and natural gas production, with approximately 3.4 million bpd of total handling capacity. WaterBridge operates primarily under long-term agreements with E&P companies to provide critical produced water handling throughout the full life cycle of its customers’ oil and natural gas wells. 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 September 30, 2024, WaterBridge has constructed or acquired approximately 0.6 million bpd of water handling capacity on our land, with approximately 1.5 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.

Recent Developments

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 Offering, including the underwriters’ option, closed on July 1, 2024. In addition to the Class A shares sold in the Offering, 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 — Other Information — Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds — Private Placement” for additional information on the concurrent private placement.

LandBridge received net proceeds from the Offering, 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 Offering 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 Offering. OpCo used the net proceeds from the Offering 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”), 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 Offering;
• LandBridge contributed all of the net proceeds from the Offering to OpCo in exchange for a number of OpCo Units equal to the number of Class A shares issued in the Offering; and
• LandBridge Holdings received the cash distribution from OpCo describe above and a number of Class B shares equal to the number of OpCo Units held by it immediately following the Offering.

For more information regarding the Corporate Reorganization and the Master Reorganization Agreement, please see “Corporate Reorganization” in the Prospectus and “Master Reorganization Agreement” in Item 1.01 of our Current Report on Form 8-K filed with the SEC on July 3, 2024, respectively.

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 the Company’s Board of Directors for approval.

On November 6, 2024, the Company entered into a purchase and sale agreement with a third-party private seller to acquire approximately 5,800 surface acres in Lea County, New Mexico, for a total purchase price of $26.5 million. The transaction is expected to close in the fourth quarter of 2024.

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 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.

Despite these challenges, we believe the outlook for the oil and natural gas industry, particularly within the Permian Basin, remains positive. Within the Delaware Basin, the most active sub-region within the Permian Basin, oil production increased at a CAGR of 23% from 2016 through the first half of 2024, while water production increased at a CAGR of 21% during the same period. According to Enverus, as of September 30, 2024, there were 170 active drilling rigs in the Delaware Basin, and further, according to the EIA, oil production in the Permian Basin is expected to average 6.3 million bpd in 2024, which is higher than the average daily production of any prior year in the Permian Basin. The EIA expects this growth to continue into 2025 with the Permian Basin increasing oil production by an additional 230,000 bpd. This drilling activity requires significant build out of related infrastructure in the region and access to surface acreage to support such operations.

In addition to positive momentum within the oil and natural gas industry, we expect to benefit from advancements in clean energy alternatives. In August 2022, the IRA was signed into law. The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. While these incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, like oil and natural gas, clean energy technologies often require access to material surface acreage and supporting infrastructure, which we are well positioned to facilitate.

Third Quarter Results

Significant financial and operating highlights for the third quarter of 2024 include:

• Revenues of $28.5 million, an increase of 60% as compared to the third quarter of 2023;
• Net loss of $2.8 million as compared to net income of $16.6 million in the third quarter of 2023;
• Net loss margin of 10% as compared to net income margin of 93% in the third quarter of 2023;
• Adjusted EBITDA(1) of $25.0 million, an increase of 62% as compared with the third quarter of 2023;
• Adjusted EBITDA Margin(1) of 88%, an increase of 1% as compared with the third quarter of 2023;
• Cash flow from operating activities of $7.5 million, a decrease of 54% as compared to the third quarter of 2023;
• Free Cash Flow(1) of $7.1 million, a decrease of 55% as compared to the third quarter of 2023;
• Operating cash flow margin of 26%, a decrease of 65% as compared to the third quarter of 2023; and
• Free Cash Flow Margin(1) of 25%, a decrease of 65% as compared to the third quarter 2023;

(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 third quarter of 2024 include non-cash share-based compensation expense of $11.6 million, of which $1.8 million is attributable to RSUs issued by the Company and $9.8 million is attributable to Incentive Units issued by LandBridge Holdings. Net income and net income margin for the third quarter of 2023 include non-cash share-based compensation income of $6.9 million attributable to the NDB Incentive Units. Subsequent to the Offering, any actual cash expense associated with such Incentive Units is borne solely by LandBridge Holdings and not the Company. Distributions attributable to 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 8 — Share-Based Compensation to our unaudited condensed consolidated financial statements for additional information regarding 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 surface use royalty agreements (“SURAs”) and surface use agreements (“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 and impose only nominal obligations on us. As of September 30, 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 Consumer Price Index (“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 September 30, 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 September 30, 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 September 30, 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:

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, 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 our 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 Offering, 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 Incentive Units at LandBridge Holdings. As of the date of the Division, the Incentive Units held at LandBridge Holdings are the only incentive units attributable and allocated to the Company. The 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 Incentive Units is fully allocated to the noncontrolling interest as the contractual obligation to satisfy the Incentive Units exists at LandBridge Holdings. Subsequent to the Offering, any actual cash expense associated with such Incentive Units is borne solely by LandBridge Holdings and not the Company.

In connection with the Offering, our Board adopted the LTIP. The LTIP allows for the grant of options, 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 unaudited condensed statements of operations prior to allocation to the noncontrolling interest. See Note 8 — Share-Based Compensation to our unaudited condensed 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 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 additional information regarding these non-GAAP financial measures.

Factors Affecting the Comparability of Our Results of Operations

In this Quarterly Report, we present our historical results of operations for the three and nine months ended September 30, 2024 and 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 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 Offering, we incurred incremental, non-recurring costs related to our transition to a publicly traded and taxable entity, including the costs of the Offering 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 Offering. Additionally, we have hired 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 Offering and have no previous operations, assets or liabilities. The historical consolidated financial statements included in this Quarterly Report are based on the financial statements of our accounting predecessor, OpCo, prior to the Corporate Reorganization in connection with the Offering. 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. See “— Recent Developments — Corporate Reorganization.”

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

In the first half of 2024, we acquired approximately 150,000 surface acres through the consummation of the Acquisitions, which will impact the comparability of our results of operations. See Note 3 — Asset Acquisitions within the notes to our unaudited condensed consolidated financial statements for further information with respect to the 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 entering into our credit facility, we borrowed $100.0 million under the Term Loan and borrowed $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 each of the Acquisitions, we entered into the Credit Agreement Amendment, which amended the credit facility. Among other things, the Credit Agreement Amendment increased the four-year Term Loan to $350.0 million and the four-year Revolving Credit Facility to $75.0 million. Following our entry into the Credit Agreement Amendment, we borrowed $265.0 million under our credit facility to fund a portion of the purchase price of each of the Acquisitions. On November 4, 2024, we entered into the Second Credit Agreement Amendment to increase the maximum available amount under our Revolving Credit Facility to $100.0 million, increase the principal amount of the Term Loan to $300.0 million, with an additional $75.0 million uncommitted delayed draw term loan, and eliminate the Company’s obligation to make Term Loan amortization payments. Our credit facility is secured by a first-priority lien on substantially all assets and guaranteed by us and our subsidiaries. See “—Liquidity and Capital Resources—Debt Instruments—Credit Facility” for more information.

Income Taxes

Prior to the Offering, 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 Offering, 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

Three Months Ended September 30, 2024 Compared to the Three Months Ended September 30, 2023

(In thousands)

Total revenues. Total revenues increased by $10.7 million, or 60%, to $28.5 million for the three months ended September 30, 2024, as compared to $17.8 million for the three months ended September 30, 2023. The increase was primarily attributable to increased surface use royalties of $6.7 million, easements and other surface-related revenues of $4.3 million, resource royalties of $2.5 million and resource sales of $0.6 million, partially offset by decreased oil and gas royalties of $3.4 million. Please see our discussion below regarding comparative period variances in revenue sources.

Surface use royalties. Surface use royalties increased by $6.7 million, or 209%, to $9.9 million for the three months ended September 30, 2024, as compared to $3.2 million for the three months ended September 30, 2023. The increase was primarily attributable to increased produced water handling and associated skim oil royalties of $6.3 million and industrial waste handling royalties of $0.2 million on our surface for the three months ended September 30, 2024, as compared to the three months ended September 30, 2023.

Easements and other surface-related revenues. Easements and other surface-related revenues increased by $4.3 million, or 187%, to $6.6 million for the three months ended September 30, 2024, as compared to $2.3 million for the three months ended September 30, 2023. The increase was primarily attributable to oil and gas transportation and gathering pipelines and produced water handling infrastructure of $3.4 million and other surface and subsurface easements of $0.8 million during the three months ended September 30, 2024, as compared to the three months ended September 30, 2023.

Resource sales. Resource sales increased by $0.6 million, or 14%, to $4.9 million for the three months ended September 30, 2024, as compared to $4.3 million for the three months ended September 30, 2023. The increase was primarily attributable to an increase in brackish water sales volume by 0.7 million barrels, or 9%, for the three months ended September 30, 2024, as compared to the three months ended September 30, 2023, while the unit price per barrel of brackish water sold remained flat. The brackish water sales volume increase is primarily due to the timing of customer demand in the areas surrounding our surface acreage, primarily upstream drilling and completion operations.

Oil and gas royalties. Oil and gas royalties decreased by $3.4 million, or 54%, to $2.9 million for the three months ended September 30, 2024, as compared to $6.3 million for the three months ended September 30, 2023, which consists of decreased royalty income of $3.3 million and lower mineral lease income of $0.1 million. The decrease in mineral lease income is attributable to an immaterial adjustment to a mineral lease during the three months ended September 30, 2024, as compared to no activity during the three months ended September 30, 2023. The table below provides operational and financial data by oil and gas royalty stream for the periods indicated.

Resource royalties. Resource royalties increased by $2.5 million, or 156%, to $4.2 million for the three months ended September 30, 2024, as compared to $1.6 million for the three months ended September 30, 2023. The increase was attributable to brackish water royalties in connection with the East Stateline Ranch acquisition of $2.5 million and increased sand mine volumes of $0.1 million for the three months ended September 30, 2024, as compared to the three months ended September 30, 2023.

Resource sales-related expense. Resource sales related expense decreased by $0.6 million, or 60%, to $0.4 million for the three months ended September 30, 2024, as compared to $1.0 million for the three months ended September 30, 2023. The decrease was primarily attributable to lower utility expenses due to installation and connection to overhead electric infrastructure and lower water well repairs and maintenance for the three months ended September 30, 2024, as compared to the three months ended September 30, 2023.

General and administrative expense (income). General and administrative expense (income), excluding share-based compensation expense, increased by $9.1 million, or 650%, to $10.5 million for the three months ended September 30, 2024, as compared to $1.4 million for the three months ended September 30, 2023. The increase was primarily attributable to Offering-related employee bonuses of $5.0 million, a contract termination payment of $2.6 million and higher professional services fees and other non-capitalizable expenses associated with transitioning to a publicly traded company of $1.3 million.

General and administrative expense (income), inclusive of share-based compensation, increased by $27.7 million, or 495%, to $22.1 million for the three months ended September 30, 2024, as compared to income of $5.6 million for the three months ended September 30, 2023. The increase was attributable to the change in share-based compensation expense of $18.5 million and increased cash expenses noted above. The share-based compensation is comprised of an increase related to the Incentive Units of $16.7 million and $1.8 million related to the issuance of RSUs issued during the three months ended September 30, 2024. The Incentive Units expense increase is primarily due to new issuances and post-modification equity award accounting amortization resulting in expense of $9.8 million for the three months ended September 30, 2024, as compared to income of $6.9 million for the three months ended September 30, 2023 due to the remeasurement of the NDB Incentive Units. See Note 8 — Share-Based Compensation within the notes to our unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion decreased by $0.6 million, or 23%, to $2.0 million for the three months ended September 30, 2024, as compared to $2.6 million for the three months ended September 30, 2023. The decrease was primarily attributable to lower depletion expense of $0.6 million due to a natural decline in oil and gas production with minimal oil and gas royalty development activities during 2024.

Interest expense, net. Interest expense, net, increased by $4.2 million, or 145%, to $7.1 million for the three months ended September 30, 2024, as compared to $2.9 million for the three months ended September 30, 2023. The increase was primarily attributable to additional borrowings under our Credit Facilities during the three months ended September 30, 2024, as compared to the three months ended September 30, 2023. See “— Liquidity and Capital Resources” for additional information regarding the Company’s debt instruments and interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

(In thousands)

Total revenues. Total revenues increased by $18.1 million, or 33%, to $73.5 million for the nine months ended September 30, 2024, as compared to $55.4 million for the nine months ended September 30, 2023. The increase was comprised of an increase in surface use royalties of $12.4 million, easements and other surface-related revenues of $9.7 million and resource royalties of $4.6 million, partially offset by decreased resource sales of $5.3 million and oil and gas royalties of $3.3 million. Please see our discussion below regarding comparative period variances in revenue sources.

Surface use royalties. Surface use royalties increased by $12.4 million, or 144%, to $21.0 million for the nine months ended September 30, 2024, as compared to $8.6 million for the nine months ended September 30, 2023. The increase was primarily attributable to increased produced water handling and associated skim oil royalties of $11.8 million and industrial waste handling royalties of $0.5 million on our surface for the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023.

Easements and other surface-related revenues. Easements and other surface-related revenues increased by $9.7 million, or 102%, to $19.2 million for the nine months ended September 30, 2024, as compared to $9.5 million for the nine months ended September 30, 2023. The increase was primarily attributable to oil and natural gas gathering and transportation pipelines and produced water handling infrastructure of $7.6 million and $2.1 million in other surface easements for the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023.

Resource sales. Resource sales decreased by $5.3 million, or 30%, to $12.2 million for the nine months ended September 30, 2024, as compared to $17.5 million for the nine months ended September 30, 2023. Brackish water sales volume decreased by 7.7 million barrels, or 22%, to 27.8 million barrels for the nine months ended September 30, 2024, as compared to 35.5 million barrels for the nine months ended September 30, 2023. Additionally, the per unit sales price decreased by approximately 15%. 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 nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023.

Oil and gas royalties. Oil and gas royalties decreased by $3.3 million, or 22%, to $11.6 million for the nine months ended September 30, 2024, as compared to $14.9 million for the nine months ended September 30, 2023, which consists of decreased royalty income of $3.0 million offset by lower mineral lease income of $0.3 million. Mineral lease income decreased $0.3 million, primarily attributable to fewer net mineral acres leased during the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023. The table below provides operational and financial data by oil and gas royalty stream for the periods indicated.

Resource royalties. Resource royalties increased by $4.6 million, or 96%, to $9.4 million for the nine months ended September 30, 2024, as compared to $4.8 million for the nine months ended September 30, 2023. The increase was primarily attributable to brackish water royalties in connection with the East Stateline Ranch acquisition of $3.6 million and an increase attributable to sand mine royalty rates of $0.5 million and sand mine volumes of $0.4 million.

Resource sales-related expense. Resource sales-related expense decreased by $1.4 million, or 45%, to $1.7 million for the nine months ended September 30, 2024, as compared to $3.1 million for the nine months ended September 30, 2023. The decrease was primarily attributable to lower utility expenses and purchase of third-party water and transfer costs associated with sales of brackish water driven by the lower volumes sold during the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023.

Other operating and maintenance expense. Other operating and maintenance expense decreased by $0.2 million, or 10%, to $1.8 million for the nine months ended September 30, 2024, as compared to $2.0 million for the nine months ended September 30, 2023. The decrease was primarily attributable to lower production taxes on oil and gas royalties due to decreased oil and gas royalty income for the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023.

General and administrative expense (income). General and administrative expense (income), excluding share-based compensation expense, increased by $10.2 million, or 268%, to $14.0 million for the nine months ended September 30, 2024, as compared to $3.8 million for the nine months ended September 30, 2023. The increase was primarily attributable to Offering-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 $1.3 million, professional services fees primarily associated with amending the Company’s Credit Facilities in conjunction with acquisition-related activities and entity restructuring of $0.7 million and $0.3 million in increased corporate shared services allocation from WaterBridge.

General and administrative expense (income), inclusive of share-based compensation, increased by $118.7 million, or 576%, to expense of $98.1 million for the nine months ended September 30, 2024, as compared to income of $20.6 million for the nine months ended September 30, 2023. The increase was attributable to the change in share-based compensation expense of $108.5 million and increased cash expenses noted above. The share-based compensation is comprised of an increase related to the Incentive Units of $106.8 million and $1.8 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 $9.8 million for the nine months ended September 30, 2024, as compared to income of $24.4 million due to remeasurement of the NDB Incentive Units for the nine months ended September 30, 2023. See Note 8 — Share-Based Compensation within the notes to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion decreased by $0.1 million, or 2%, to $6.3 million for the nine months ended September 30, 2024, as compared to $6.4 million for the nine months ended September 30, 2023. The decrease was primarily attributable to lower depletion expense of $0.2 million due to a natural decline in oil and gas production with minimal oil and gas royalty development activities during 2024 partially offset by higher depreciation expense of $0.1 million related to capital expenditures associated with brackish water supply infrastructure.

Interest expense, net. Interest expense, net, increased by $12.0 million, or 286%, to $16.2 million for the nine months ended September 30, 2024, as compared to $4.2 million for the nine months ended September 30, 2023. The increase was primarily attributable to additional principal borrowings under our Credit Facilities during the nine months ended September 30, 2024, as compared to borrowings under our then-existing debt instruments for the nine months ended September 30, 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.

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.

(In thousands)

(1) Share-based compensation - Incentive Units for the three and nine months ended September 30, 2024, consists of $9.8 million related to the Incentive Units, and $72.6 million related to the NDB Incentive Units, and $9.8 million related to the Incentive Units, respectively. Share-based compensation - Incentive Units for the three and nine months ended September 30, 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 Offering, any actual cash expense associated with such Incentive Units is borne solely by LandBridge Holdings and not the Company. Distributions attributable to 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 Offering-related charges.

(3) Non-recurring expenses consist primarily of $5.0 million in Offering-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.

(In thousands)

(1) Operating cash flow data 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 NDB LLC, cash flows from operating activities and borrowings under our debt instruments. Following the completion of the Offering, our primary sources of liquidity are cash flows from operating activities and, if required, proceeds from borrowings under our Credit Facilities. 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 Acquisitions. We believe that we are able to fully fund our ongoing capital expenditures, working capital requirements and other capital needs for the foreseeable short-term and long-term future through cash on hand and cash flows from our operating activities. Although we believe that we will be able to fully fund our ongoing capital expenditures, working capital requirements and other capital needs for the foreseeable future through cash on hand and cash flows from our operating activities, we may choose 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 September 30, 2024, we had a working capital deficit, defined as current assets less current liabilities, of $11.7 million and we had cash and cash equivalents of $14.4 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:

Nine Months Ended September 30, 2024 Compared to the Nine Months Ended September 30, 2023

(In thousands)

42

Net Cash Provided by Operating Activities. Net cash provided by operating activities increased $0.1 million or less than 1% to $40.7 million for the nine months ended September 30, 2024, as compared to $40.6 million for the nine months ended September 30, 2023. The increase was attributable to cash flow related to working capital accounts, primarily accounts receivable, of $2.1 million offset by lower net income, net of non-cash items, of $2.0 million.

Net Cash Used in Investing Activities. Net cash used in investing activities increased $429.4 million or 16,515% to $432.0 million for the nine months ended September 30, 2024, as compared to $2.6 million for the nine months ended September 30, 2023. The increase was attributable to acquisition-related expenditures of $431.3 million consisting of the purchase of Lea County Ranches, Speed Ranch and East Stateline Ranch offset by lower capital expenditures, primarily supporting brackish water supply sales, of $1.9 million for the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023.

Net Cash Provided by (Used In) Financing Activities. Net cash provided by financing activities increased $413.9 million or 900% to $367.9 million of cash provided by financing activities for the nine months ended September 30, 2024, as compared to cash used of $46.0 million for the nine months ended September 30, 2023. For the nine months ended September 30, 2024, cash provided by financing activities consisted of $271.3 million of proceeds from the Offering, net of offering costs and discount, $147.5 million of debt borrowings, net of repayments and debt issuance costs, primarily used to fund the May 2024 Acquisitions, offset by net distributions to member prior to the Corporate Reorganization of $50.9 million. For the nine months ended September 30, 2023, cash used in financing activities was attributable to member distributions of $105.2 million and by debt proceeds, net of repayments and issuance costs, of $59.2 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 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 three months ended September 30, 2024, we incurred approximately $0.8 million for acquisition-related capital expenditures. For the nine months ended September 30, 2024, we incurred $431.3 million in acquisition-related capital expenditures, inclusive of $2.7 million of transaction-related expenses, in connection with the consummation of the 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 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 from time to time.

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, DBR Land LLC, a Delaware limited liability company and wholly-owned subsidiary of OpCo (“DBR Land”) and certain of our other subsidiaries entered into a credit facility providing (i) a $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 facility 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. In connection with the Acquisitions, we amended the credit facility to, among other things, increase (i) the four-year term loan facility to $350.0 million and (ii) the four-year revolving credit facility to $75.0 million. Following our entry into the amendment, we borrowed $265.0 million under our term loan facility to fund a portion of the purchase price of each of the Acquisitions. On November 4, 2024, we entered into the Second Credit Agreement Amendment to increase the maximum available amount under our Revolving Credit Facility to $100.0 million, increase the principal amount of the Term Loan to $300.0 million, with an additional $75.0 million uncommitted delayed draw term loan, and eliminate the Company’s obligation to make Term Loan amortization payments. Our credit facility is secured by a first-priority lien on substantially all of our assets and guaranteed by DBR Land and our restricted subsidiaries (other than certain immaterial subsidiaries).

Our credit facility includes certain affirmative and restrictive covenants common in such agreements that apply to DBR Land and its subsidiaries. See Note 6 — Debt within the notes to our condensed consolidated financial statements and included elsewhere in this Quarterly 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 Offering, 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 Offering, 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 September 30, 2024, we had $281.3 million of outstanding borrowings consisting of $15.0 million of revolving credit borrowings and $266.3 million of term loan borrowings. The weighted average interest rate on the total amount of borrowings outstanding under new credit facility for the three months ended September 30, 2024 was 8.54% in the case of revolving credit borrowings, and 8.56% in the case of term loan borrowings. The weighted average interest rate on the total amount of borrowings outstanding under new credit facility for the nine months ended September 30, 2024 was 8.45% in the case of revolving credit borrowings and 8.49% 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 Policies and Estimates

The preparation of our financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and disclosures of contingent assets and liabilities. We consider our critical accounting estimates those that require subjectivity and that could inherently influence our financial result based on changes in those estimates. See Note 2 — Summary of Significant Accounting Policies - Basis of Presentation and Consolidation within the notes to our unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report.

Share-Based Compensation

Incentive Units

The Company accounts for share-based compensation expense for incentive units granted in exchange for employee services.

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 represented a substantive class of equity of NDB LLC and were accounted for under FASB 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 pushed down to the Company was recognized as a deemed non-cash contribution to or distribution from member’s equity on the condensed 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 Unit. 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 Incentive Units consisting of time-based awards of profits interests in LandBridge Holdings. Following the Division, the Incentive Units held at LandBridge Holdings are the only Incentive Units attributable and allocated to the Company.

Further, as part of the Division, the repurchase feature triggering liability award accounting of the NDB Incentive Units under the Amended and Restated Limited Liability Company Agreement of NDB LLC (the “NDB LLC Agreement”) was amended in connection with the entry into the LandBridge Holdings Limited Liability Company Agreement, dated July 1, 2024 (the “Holdings LLC Agreement”). Features of the Incentive Units include the ability for LandBridge Holdings to repurchase Incentive Units during a 180-day option period, whereby the fair value price is 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 Incentive Units are no longer required to be remeasured at fair value, as the modification results in equity award classification and accounting. See Note 8 — Share-Based Compensation for additional information related to the modification.

Distributions attributable to Incentive Units are based on returns received by investors of LandBridge Holdings once certain return thresholds have been met. 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 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.

During the three and nine months ended September 30, 2024 and 2023, we accrued $1.3 million and $3.6 million of oil and gas royalties in our condensed consolidated statements of operations, respectively.

Recently Issued Accounting Pronouncements

We adopted ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), on January 1, 2023, 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 did not have a significant impact on our financial statements.

In November 2023, the FASB issued ASU No. 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. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.

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 our annual report for the year ending December 31, 2025.

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 we become a public company.

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.

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 $1.25 per MMBtu in March 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 September 30, 2024, the Henry Hub spot market price of natural gas was $2.65 per MMBtu and the posted price for oil was $68.75 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 fall 2024 U.S. presidential election and congressional 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.

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 September 30, 2024, we had $281.3 million of outstanding borrowings consisting of $15.0 million of revolving credit borrowings and $266.3 million of term loan borrowings. The weighted average interest rate on the borrowings outstanding under our Credit Facilities for the nine months ended September 30, 2024 was 8.45% in the case of revolving credit borrowings, and 8.49% 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 $2.8 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.”

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 Quarterly 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 September 30, 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.

Internal Control over Financial Reporting

There were no other changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

This Quarterly Report on Form 10-Q should be read in conjunction with the risk factors disclosed under the heading “Risk Factors” in the Prospectus. There have been no material changes to the risk factors disclosed under the heading “Risk Factors” in the Prospectus.