Black Stone Minerals, L.P.: Form 10-Q for the period ended Mar 31, 2025

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024 ("2024 Annual Report on Form 10-K"). This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”

Cautionary Note Regarding Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

• our ability to execute our business strategies;
• the volatility of realized oil and natural gas prices;
• the level of production on our properties;
• the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production;
• our ability to replace our oil and natural gas reserves;
• general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets;
• competition in the oil and natural gas industry;
• the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions;
• the ability of our operators to obtain capital or financing needed for development and exploration operations;
• title defects in the properties in which we invest;
• the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
• restrictions on the use of water for hydraulic fracturing;
• the availability of pipeline capacity and transportation facilities;
• the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
• federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
• domestic and foreign trade policies, including tariffs and other controls on imports or exports of goods, including energy products;
• future operating results;
• future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;
• exploration and development drilling prospects, inventories, projects, and programs;
• operating hazards faced by our operators;
• the ability of our operators to keep pace with technological advancements;
• conservation measures and general concern about the environmental impact of the production and use of fossil fuels;
• cybersecurity incidents, including data security breaches or computer viruses; and
• certain factors discussed elsewhere in this filing.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our 2024 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.

Overview

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management. We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration.

As of March 31, 2025, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Recent Developments

Development Activity

At the end of the first quarter, EXCO Resources Inc. was operating one rig, and Aethon was operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. During the quarter, Aethon successfully turned to sales 11 gross (0.7 net) wells, with the majority of the wells showing improved results compared to older offsets. Aethon’s development program remains on track, with an estimated 17 gross (1.0 net) additional wells expected to turn to sales during the remainder of 2025.

In the Louisiana Haynesville, development continued under our Accelerated Drilling Agreements (“ADAs”). These agreements provide greater near-term certainty by accelerating development and associated revenue in our high-interest areas in exchange for a modest reduction in royalty burden. During the first quarter, two gross (0.2 net) wells in De Soto Parish were turned to sales under our ADAs.

In the Permian Basin, we continue to monitor several large-scale development projects expected to generate meaningful liquids volumes in 2025 and beyond. As previously disclosed, a large operator has planned more than 35 gross (1.25 net) wells in Culberson County, Texas. To date, 24 of these wells have been spud. We anticipate nine gross wells to turn to sales in the fourth quarter of 2025, with the remainder expected in the first half of 2026.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.

Oil prices decreased during the first quarter of 2025 due to concerns arising from changes in trade policies, including the imposition of tariffs and other import/export restrictions, and their resulting consequences, which raised fears of a global economic slowdown and weakened expectations for oil demand growth. In April 2025, OPEC+ announced plans to accelerate production increases starting in May that were originally set for July, causing oil prices to continue to decrease. Natural gas prices rose in the first quarter of 2025 due to unusually cold weather in January and February, leading to higher consumption for heating and lower than expected storage levels. In addition, two new LNG export facilities began operations during the quarter, driving additional demand and higher prices. Given the dynamic nature of these events, including uncertainty regarding changes in trade policies and their resulting consequences, we cannot reasonably estimate how long these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

The following table reflects commodity prices at the end of each quarter presented:

1 Source: EIA

Rig Count

As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The following table shows the rig count at the end of each quarter presented:

1 Source: Baker Hughes Incorporated

Natural Gas Storage

A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The U.S. Energy Information Administration ("EIA") expects inventories will rise to 3.7 Tcf by the end of October 2025, which would be 3% lower than the five-year average.

The following table shows natural gas storage volumes by region at the end of each quarter presented:

1 Source: EIA

Natural Gas Exports

Net natural gas exports averaged 14.4 Bcf per day during the first quarter of 2025, a 21% increase from the 2024 average. The EIA forecasts average exports of 15.5 Bcf per day for the remainder of 2025 and 16.4 Bcf per day for 2026. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations during 2025.

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

• volumes of oil and natural gas produced;
• commodity prices including the effect of derivative instruments; and
• Adjusted EBITDA and Distributable cash flow.

Volumes of Oil and Natural Gas Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the United States.

• Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as West Texas Intermediate ("WTI"), is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

• Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

Hedging

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, 2025 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.

We are allowed, but not required, to hedge, using swaps and collars with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, 2025, we have hedged a portion of our expected future volumes for the remainder of 2025 and 2026.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production. We do not enter into derivative instruments for speculative purposes.

Non-GAAP Financial Measures

Adjusted EBITDA and Distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance.

Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:

(in thousands)

23

Results of Operations

Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024

The following table shows our production, revenue, and operating expenses for the periods presented:

(Dollars in thousands, except for realized prices)

1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

2 Not meaningful.

Revenue

Total revenue for the quarter ended March 31, 2025 decreased compared to the quarter ended March 31, 2024. The decrease is primarily due to an increase in unrealized losses from our commodity derivative instruments and a decrease in oil, and condensate sales, compared to the corresponding prior period. The decreased in revenue was partially offset by an increase in natural gas and NGL sales.

Oil and condensate sales. Oil and condensate sales decreased for the quarter ended March 31, 2025 as compared to the corresponding period in 2024 primarily due to lower production volumes and realized commodity prices. The decrease in oil and condensate production was driven by reduced mineral and royalty production in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 94% of total oil and condensate volumes for quarters ended March 31, 2025 and 2024, respectively.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2025 as compared to the corresponding prior period. The increase was due to higher realized commodity prices between the comparative periods partially offset by a reduction in production volumes. The decrease in natural gas and NGL production was driven by lower mineral and royalty production in the Haynesville/Bossier, Fayetteville, and Austin Chalk play trends. Mineral and royalty interest production accounted for 97% and 95% of our natural gas volumes for the quarters ended March 31, 2025 and 2024, respectively.

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During the first quarter of 2025, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2024. For the three months ended March 31, 2025, we recognized $3.6 million of realized losses and $52.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.8 million of realized gains and $25.1 million of unrealized losses in the same period in 2024. The unrealized losses on our commodity contracts during the first quarter of 2025 and the unrealized losses in the corresponding period in 2024 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of 2025 was higher than the same period in 2024. Leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana made up the majority of lease bonus and other income for the first quarter of 2025. The majority of lease bonus and other income for the first quarter of 2024 came from leasing activity in the Austin Chalk and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas.

Operating Expenses

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 2025 as compared to the same period in 2024, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended March 31, 2025, production costs and ad valorem taxes decreased as compared to the quarter ended March 31, 2024, primarily due to lower production taxes stemming from lower oil and condensate commodity prices and decreased production volumes.

Exploration expense. Exploration expense typically consists of dry-hole expenses, payments for delay rentals where the Partnership is the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. For the quarter ended March 31, 2025, exploration expenses increased compared to the same period in 2024, primarily due to a one-time $4.0 million purchase of seismic data and additional costs related to seismic data acquisition projects. These seismic initiatives aim to further bolster our subsurface evaluation of the expanded Shelby Trough area. Exploration expenses were minimal in the first quarter of 2024.

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization decreased for the quarter ended March 31, 2025 as compared to the same period in 2024 due to lower production volumes.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2025, general and administrative expenses increased as compared to the same period in 2024, primarily due to increased cash and equity-based compensation. The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during the quarter ended March 31, 2025 compared to minimal price changes in the corresponding period in 2024.

Interest expense. Interest expense in the first quarter of 2025 increased as compared to the corresponding period in 2024, due to increased borrowings under our Credit Facility. Average outstanding borrowings during the first quarter of 2025 were higher than the first quarter of 2024 due to funding acquisitions in 2025 and 2024.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business. On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units was adjusted to 9.8% and will be readjusted every two years thereafter (each, a "Readjustment Date"). The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum. We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value. See "Note 9 - Preferred Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

The Board has adopted a policy pursuant to which, at a minimum, distributions will be paid on each common unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributions on our common units quarterly or on any other basis, and there is no guarantee that we will pay distributions to our common unitholders in any quarter. The Board may change the foregoing distribution policy at any time and from time to time.

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be cancelled. See "Note 11 – Common Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Cash Flows

The following table shows our cash flows for the periods presented:

(in thousands)

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities decreased for the three months ended March 31, 2025 as compared to the same period of 2024. The decrease was primarily due to reduced oil and condensate sales due to lower realized commodity prices and production, changes in operating assets and liabilities due to the timing of payments, and net cash paid on the settlement of commodity derivatives in the three months ended March 31, 2025 compared to net cash received for the same period of 2024. The overall decrease in cash flows from operations was partially offset by increased natural gas and NGL sales resulting from higher realized commodity prices.

Investing Activities. Net cash used in investing activities in the three months ended March 31, 2025 decreased as compared to the same period of 2024. The decrease was primarily due to reduced acquisitions of oil and natural gas properties in the three months ended March 31, 2025 compared to the same period of 2024.

Financing Activities. Cash flows used in financing activities decreased for the three months ended March 31, 2025 as compared to the same period of 2024. The decrease was primarily due to lower distributions paid to unitholders and net borrowings on our Credit Facility for the three months ended March 31, 2025.

Development Capital Expenditures

Our 2025 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, of which $0.1 million has been invested in the three months ended March 31, 2025. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest. Through March 31, 2025, we have also spent $3.0 million acquiring leases on acreage utilized for our drilling programs.

Acquisitions

During the three months ended March 31, 2025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $14.2 million, including capitalized direct transaction costs. The consideration paid consisted of $10.3 million in cash that was funded from operating activities and $3.9 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. These acquisitions were considered asset acquisitions and were primarily located in the Gulf Coast land region. Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

See "Note 3 – Oil and Natural Gas Properties" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Asset Exchanges

During 2024 and the first quarter of 2025, we completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas.

In March 2025, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana.

In February 2025, we closed on a transaction with a third-party operator whereby we exchanged oil and natural gas leases covering certain acreage in East Texas. The Partnership acquired approximately 2,100 net leasehold acres in exchange for approximately 3,700 net leasehold acres.

In July 2024, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

Shelby Trough Development Agreements

We have Joint Exploration Agreements ("JEAs") with Aethon Energy ("Aethon") to develop certain portions of our undeveloped acreage in San Augustine County and Angelina County in East Texas. The agreements provide for minimum annual well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract areas. The Partnership's development agreement and related drilling commitments covering its San Augustine County acreage are independent of the development agreement and associated commitments covering Angelina County.

If Aethon drills more than the minimum commitment wells in a given program year, Aethon may reduce its minimum well commitment in future program years by the number of excess wells, which we refer to as "banked" wells. Aethon's ability to apply banked wells to reduce its drilling commitments is capped at three or four wells each year, depending on the JEA. Upon the satisfaction of the current program year performance deadlines as described in the agreements, Aethon will have an inventory of one banked well in San Augustine and 10 banked wells in Angelina that will be available to satisfy its drilling commitments in future program years.

The San Augustine JEA provides for a minimum of nine wells to be drilled in the current (third) program year ending in May 2025, with a minimum of 12 wells to be drilled in the fourth program year scheduled to commence in June 2025 and each program year thereafter. As of March 31, 2025, Aethon had drilled eight wells in the third program year under the San Augustine JEA, with one more well expected to be drilled by the end of the current program year in May 2025.

The Angelina JEA provides for a minimum 15 wells to be drilled in the current (fourth) program year ending in June 2025 and, each program year thereafter. As of March 31, 2025, Aethon had drilled nine wells in the fourth program year under the Angelina JEA, with six more wells expected to be drilled by the end of the current program year in June 2025.

Farmout Agreements

We have entered into farmout arrangements designed to reduce our working interest capital expenditures and thereby significantly lower our capital spending other than for mineral and royalty interest acquisitions. Under these agreements, we conveyed our rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests. These farmout arrangements cover a portion of our share of working interests under active development by Aethon in San Augustine and Angelina County in East Texas.

Credit Facility

We maintain a senior secured revolving credit agreement, as amended, (the "Credit Facility"). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. The April 2024, November 2024, and April 2025 borrowing base redeterminations reaffirmed the borrowing base at $580.0 million. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October 2025.

We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets. As of March 31, 2025, we were in compliance with all debt covenants.

See "Note 6 – Credit Facility" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Contractual Obligations

As of March 31, 2025, there have been no material changes to our contractual obligations previously disclosed in our 2024 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of March 31, 2025, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2024 Annual Report on Form 10-K.

Commodity Price Risk

Our major market risk exposure is the pricing of oil, natural gas, and NGLs produced by our operators. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs in the United States. Prices for oil, natural gas, and NGLs have been historically volatile, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative financial instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly in cash based on the difference between the fixed contract price and the market settlement price. The market settlement price is based on the NYMEX benchmark for oil and natural gas. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the change. See "Note 4 - Commodity Derivative Financial Instruments" and "Note 5 - Fair Value Measurements" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Commodity prices have been historically volatile based upon the dynamics of supply and demand. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SEC commodity pricing for the three months ended March 31, 2025. Applying this discount results in an approximate 1.3% reduction of proved reserve volumes as compared to the undiscounted March 31, 2025 SEC pricing scenario.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2025, we had seven counterparties, all of which were rated Baa2 or better by Moody’s and are lenders under our Credit Facility.

Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. During the three months ended March 31, 2025, we had $47.1 million weighted average outstanding borrowings under our Credit Facility, bearing interest at a weighted average interest rate of 6.92%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in a de minimis increase in interest expense, and a corresponding decrease in our results of operations, for the three months ended March 31, 2025, assuming that our indebtedness remained constant throughout the period. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation 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 on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2025 to provide reasonable assurance.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

In addition to the other information set forth in this report, readers should carefully consider the risks under the heading “Risk Factors” in our 2024 Annual Report on Form 10-K. Except to the extent updated below, there has been no material change in our risk factors from those described in our 2024 Annual Report on Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.