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(Mark One)

 

Delaware									47-1846692
(State or other jurisdiction of incorporation or organization)									(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 2020
Houston,			Texas						77002
(Address of principal executive offices)									(Zip code)

 

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

As of October 31, 2025, there were 211,862,412 common units and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.

 

						Page
PART I – FINANCIAL INFORMATION
Item 1.			Condensed Financial Statements (Unaudited)
			Consolidated Balance Sheets			1
			Consolidated Statements of Operations			2
			Consolidated Statements of Equity			3
			Consolidated Statements of Cash Flows			5
			Notes to Unaudited Consolidated Financial Statements			6
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 3.			Quantitative and Qualitative Disclosures About Market Risk			32
Item 4.			Controls and Procedures			33
PART II – OTHER INFORMATION
Item 1.			Legal Proceedings			34
Item 1A.			Risk Factors			34
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds			34
Item 5.			Other Information			34
Item 6.			Exhibits			35
			Signatures			37

Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States ("U.S."), including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."

The accompanying unaudited interim condensed consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2024 ("2024 Annual Report on Form 10-K").

The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the nine months ended September 30, 2025 are not necessarily indicative of the results to be expected for the full year.

In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated.

The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying unaudited interim consolidated financial statements.

The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.

The Partnership operates in a single reportable segment. The Partnership generates revenue from the sale of oil and natural gas, as well as lease bonus and other income that is derived from our oil and natural gas properties. These properties are all located within the continental U.S., including all of the major onshore producing basins. Reportable segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker ("CODM") in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the CODM and allocates resources and assesses performance based upon net income reported on the consolidated statements of operations. The measure of segment assets is reported on the consolidated balance sheets as total assets. The CODM uses net income to evaluate the income generated from segment assets in deciding whether to reinvest profits into the Partnership's oil and natural gas properties or for other activities such as distributions to unitholders and reducing outstanding borrowings as applicable.

Significant accounting policies are disclosed in the Partnership’s 2024 Annual Report on Form 10-K. There have been no changes in such policies or the application of such policies during the nine months ended September 30, 2025.

The following table presents information about the Partnership's accrued revenue and accounts receivable:

						September 30, 2025						December 31, 2024
						(in thousands)
Accrued revenue						$	59,219					$	67,047
Accounts receivable						5,148						4,046
Total accrued revenue and accounts receivable						$	64,367					$	71,093

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures, which enhances the disclosures required for certain expense captions in the Partnership's annual and interim consolidated financial statements. The guidance is effective for fiscal years beginning after December 15, 2026 and for interim periods beginning after December 15, 2027, with early adoption permitted. The Partnership is currently evaluating the impact of this standard on its disclosures.

Restricted cash consists of funds reserved for a special purpose and therefore not available for immediate and general use. Our restricted cash is comprised of cash that is contractually required to be restricted to pay for future mineral acquisitions.

On August 14, 2025, the Partnership entered into a purchase and sale agreement to acquire certain unproved oil and gas mineral interests located in East Texas for total consideration, including estimated transaction costs, of approximately $40 million, subject to customary title due diligence and closing adjustments. In connection with this transaction, the Partnership deposited $3.3 million into escrow as of September 30, 2025. These funds are legally restricted from use for general purposes and are held in escrow pursuant to the terms of the purchase and sale agreement, pending the satisfaction of closing conditions. The acquisition is expected to close in the fourth quarter of 2025.

A reconciliation of cash, cash equivalents, and restricted cash as presented on the condensed consolidated statements of cash flows is as follows (in thousands):

						September 30, 2025						December 31, 2024
						(in thousands)
Cash and cash equivalents						$	2,864					$	2,519
Restricted cash						3,304						—
Total cash, cash equivalents and restricted cash						$	6,168					$	2,519

During the nine months ended September 30, 2025, the Partnership acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in the Gulf Coast land region from various sellers for an aggregate of $65.7 million, including capitalized direct transaction costs, and were considered asset acquisitions. The consideration paid consisted of $58.3 million in cash that was funded from operating activities and $7.4 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.

During the year ended December 31, 2024, the Partnership acquired mineral and royalty interests that consisted of unproved oil and natural gas properties in the Gulf Coast land region from various sellers for an aggregate of $110.4 million, including capitalized direct transaction costs, and were considered asset acquisitions. The cash portion of the consideration paid of $109.4 million was funded with borrowings under our Credit Facility and funds from operating activities, and $1.0 million in equity that was funded through the issuance of common units of the Partnership based on the fair value of the common units issued on the acquisition date.

The Partnership completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas. These transactions, which are described below, involved partial dispositions of unproved property, and no gains or losses were recognized.

In March 2025, the Partnership closed on a transaction with a third-party operator whereby the Partnership 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, the Partnership closed on a transaction with a third-party operator whereby the Partnership 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, the Partnership closed on a transaction with a third-party operator whereby the Partnership 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.

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.

As of September 30, 2025, the Partnership’s open derivative contracts consisted of fixed-price swap contracts. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in the fair value of the contracts are included in the consolidated statements of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of September 30, 2025 and December 31, 2024. See "Note 5 - Fair Value Measurements" for additional information.    

The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2025, the Partnership had seven counterparties that also serve as lenders under the Credit Facility.

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date:

												September 30, 2025
Classification						Balance Sheet Location						Gross Fair Value						Effect of Counterparty Netting						Net Carrying Value on Balance Sheet
												(in thousands)
Assets:
Current asset						Commodity derivative assets, net						$	14,856					$	(6,349)					$	8,507
Long-term asset						Deferred charges and other long-term assets						2,657						(2,059)						598
Total assets												$	17,513					$	(8,408)					$	9,105
Liabilities:
Current liability						Commodity derivative liabilities, net						$	6,471					$	(6,349)					$	122
Long-term liability						Commodity derivative liabilities, net						7,030						(2,059)						4,971
Total liabilities												$	13,501					$	(8,408)					$	5,093

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented:

						Three Months Ended September 30,												Nine Months Ended September 30,
Derivatives not designated as hedging instruments						2025						2024						2025						2024
						(in thousands)
Beginning fair value of commodity derivative instruments						$	(16,361)					$	(5,118)					$	(13,609)					$	37,335
Gain (loss) on oil derivative instruments						578						25,444						16,988						988
Gain (loss) on natural gas derivative instruments						26,709						6,231						7,082						13,850
Net cash paid (received) on settlements of oil derivative instruments						(2,789)						3,852						(6,444)						9,257
Net cash paid (received) on settlements of natural gas derivative instruments						(4,125)						(14,716)						(5)						(45,737)
Net change in fair value of commodity derivative instruments						20,373						20,811						17,621						(21,642)
Ending fair value of commodity derivative instruments						$	4,012					$	15,693					$	4,012					$	15,693

The Partnership had the following open derivative contracts for oil as of September 30, 2025:

												Weighted Average Price (Per Bbl)						Range (Per Bbl)
Period and Type of Contract						Volume (Bbl)												Low						High
Oil Swap Contracts:
2025
Third Quarter						185,000						$	71.22					$	70.02					$	73.15
Fourth Quarter						555,000						71.22						70.02						73.15
2026
First Quarter						615,000						$	64.39					$	62.00					$	67.35
Second Quarter						615,000						64.39						62.00						67.35
Third Quarter						615,000						64.39						62.00						67.35
Fourth Quarter						615,000						64.39						62.00						67.35

The Partnership entered into the following derivative contracts for oil subsequent to September 30, 2025:

												Weighted Average Price (Per Bbl)						Range (Per Bbl)
Period and Type of Contract						Volume (Bbl)												Low						High
Oil Swap Contracts:
2027
First Quarter						120,000						$	59.90					$	59.28					$	60.10
Second Quarter						120,000						59.90						59.28						60.10
Third Quarter						120,000						59.90						59.28						60.10
Fourth Quarter						120,000						59.90						59.28						60.10

The Partnership had the following open derivative contracts for natural gas as of September 30, 2025:

												Weighted Average Price (Per MMBtu)						Range (Per MMBtu)
Period and Type of Contract						Volume (MMBtu)												Low						High
Natural Gas Swap Contracts:
2025
Fourth Quarter						11,040,000						$	3.45					$	3.34					$	3.65
2026
First Quarter						11,700,000						$	3.67					$	3.50					$	4.05
Second Quarter						11,830,000						3.67						3.50						4.05
Third Quarter						11,960,000						3.67						3.50						4.05
Fourth Quarter						11,960,000						3.67						3.50						4.05
2027
First Quarter						2,700,000						$	3.86					$	3.85					$	3.88
Second Quarter						2,730,000						3.86						3.85						3.88
Third Quarter						2,760,000						3.86						3.85						3.88
Fourth Quarter						2,760,000						3.86						3.85						3.88

The Partnership entered into the following derivative contracts for natural gas subsequent to September 30, 2025:

												Weighted Average Price (Per MMbtu)						Range (Per MMbtu)
Period and Type of Contract						Volume (MMbtu)												Low						High
Natural Gas Swap Contracts:
2027
First Quarter						2,700,000						$	3.97					$	3.97					$	3.97
Second Quarter						2,730,000						3.97						3.97						3.97
Third Quarter						2,760,000						3.97						3.97						3.97
Fourth Quarter						2,760,000						3.97						3.97						3.97

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of fair value hierarchy for the nine months ended September 30, 2025 and 2024.

The carrying value of the Partnership's cash and cash equivalents, restricted cash, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of September 30, 2025 and December 31, 2024 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See "Note 4 - Commodity Derivative Financial Instruments" for additional information.

The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: 

						Fair Value Measurements Using																		Effect of Counterparty Netting						Total
						Level 1						Level 2						Level 3
						(in thousands)
As of September 30, 2025
Financial Assets
Commodity derivative instruments						$	—					$	17,513					$	—					$	(8,408)					$	9,105
Financial Liabilities
Commodity derivative instruments						$	—					$	13,501					$	—					$	(8,408)					$	5,093
As of December 31, 2024
Financial Assets
Commodity derivative instruments						$	—					$	5,634					$	—					$	(3,810)					$	1,824
Financial Liabilities
Commodity derivative instruments						$	—					$	19,243					$	—					$	(3,810)					$	15,433

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for impairment.

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership had no business combinations for the nine months ended September 30, 2025 or the year ended December 31, 2024. See "Note 3 - Oil and Natural Gas Properties."

Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when impaired. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. The factors used to determine future cash flows associated with those properties include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and, with respect to estimating fair value, a risk-adjusted discount rate.

The Partnership’s estimates of fair value are determined at discrete points in time based on relevant market data. These estimates involve uncertainty, and cannot be determined with precision. There were no assets measured at fair value on a non-recurring basis for the nine months ended September 30, 2025 or the year ended December 31, 2024.

The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion. 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 October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base. In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base. The November 2024 and April 2025 borrowing base redeterminations reaffirmed the borrowing base at $580.0 million. In October 2025, the Partnership amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and reduce the adjustment applied to secured overnight financing rate ("SOFR") loans. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was reaffirmed at $580.0 million and the Partnership elected to maintain cash commitments under the Credit Facility at $375.0 million. All existing banks in the lender syndicate elected to continue participating in the Credit Facility. No other significant terms were changed as part of the amendment. The next semi-annual redetermination is scheduled for April 2026.

The Partnership’s borrowings under the Credit Facility bear interest at a floating rate determined by the type of loan the Partnership has elected to take: a SOFR loan or a base-rate loan. Both types of loans bear interest at a reference rate plus a margin that varies with the amount of borrowings outstanding under the Credit Facility. The reference rate for SOFR loans is equal to SOFR as published by the Federal Reserve Bank of New York, adjusted for the borrowing term, plus 0.10%, which is referred to as Adjusted Term SOFR. Effective October 31, 2025, Adjusted Term SOFR was amended to be equal to SOFR for the applicable borrowing term. The reference rate for base rate loans is the highest of (a) Wells Fargo’s prime commercial lending rate for that day, (b) the Federal Funds Rate in effect on that day plus 0.50%, and (c) the Adjusted Term SOFR for a one-month tenor, plus 1.00%. As of December 31, 2024 and September 30, 2025, the applicable margin for the base rate loans ranged from 1.50% to 2.50%, and the margin for SOFR loans ranged from 2.50% to 3.50%.

The Partnership is obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary SOFR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date.

The weighted-average interest rate of the Credit Facility was 7.16% during the nine months ended September 30, 2025 and 7.50% for the twelve months ended December 31, 2024. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. Distributions are not permitted if there is a default under the Credit Facility (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0. As of September 30, 2025, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $95.0 million and $25.0 million at September 30, 2025 and December 31, 2024, respectively. The unused portion of the available borrowings under the Credit Facility was $280.0 million and $350.0 million at September 30, 2025 and December 31, 2024, respectively.

The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.

The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be material to the unaudited interim consolidated financial statements, and no provision for potential remediation costs has been recorded.

From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of September 30, 2025 will be resolved without material adverse effect on the Partnership’s financial condition or operations. 

The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented:

						Three Months Ended September 30,												Nine Months Ended September 30,
						2025						2024						2025						2024
						(in thousands)
Cash—short and long-term incentive plans						$	937					$	1,498					$	3,458					$	3,883
Equity-based compensation—restricted common units						1,043						1,006						3,178						2,967
Equity-based compensation—restricted performance units						615						621						2,395						2,050
Board of Directors incentive plan						550						550						1,650						1,748
Total incentive compensation expense						$	3,145					$	3,675					$	10,681					$	10,648

For nine months ended September 30, 2025, the Partnership repurchased 256,771 common units at a weighted average price of $14.62 per unit for the purpose of satisfying tax withholding obligations upon the vesting of certain long-term incentive equity awards held by our executive officers and certain other employees. Specifically, when an employee's equity award vests, the Partnership withholds a portion of the units to cover the employee's tax liability.

On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership for a cash purchase price of $20.39 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300.0 million.

The Series B cumulative convertible preferred units were initially entitled to quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the "Distribution Rate"). On November 28, 2023, the Distribution Rate 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; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the then-distribution rate shall be increased by 2.0% per annum for such quarter. The Partnership cannot pay any distributions on any junior securities, including common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions.

The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.39, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.

The Partnership has the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units during biennial 90-day windows. On August 21, 2025, the Partnership entered into an agreement with the holders of its Series B cumulative convertible preferred units. Under the agreement, the Partnership agreed not to exercise its redemption option, and the holders agreed to vote their preferred units in accordance with the recommendations of the Partnership’s Board of Directors on ordinary course matters and to certain customary transfer and standstill restrictions. These provisions remain in effect through November 27, 2027, with the next redemption window opening on November 28, 2027.

The Partnership must provide 20 business days' notice to the holders of the Series B cumulative convertible preferred units of its intent to redeem, and the holders may either allow the redemption to occur or elect to convert the Series B cumulative convertible preferred units into common units as described above.

The Series B cumulative convertible preferred units had a carrying value of $300.5 million, including accrued distributions of $7.4 million, as of September 30, 2025 and December 31, 2024. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.

Net income attributable to the Partnership is allocated to the Partnership’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.

The Partnership assesses the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted EPU. The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period.

The following table sets forth the computation of basic and diluted earnings per common unit:

						Three Months Ended September 30,												Nine Months Ended September 30,
						2025						2024						2025						2024
						(in thousands, except per unit amounts)
NET INCOME						$	91,729					$	92,731					$	227,705					$	224,980
Distributions on Series B cumulative convertible preferred units						(7,366)						(7,366)						(22,099)						(22,099)
NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS						$	84,363					$	85,365					$	205,606					$	202,881
ALLOCATION OF NET INCOME:
General partner interest						$	—					$	—					$	—					$	—
Common units						84,363						85,365						205,606						202,881
						$	84,363					$	85,365					$	205,606					$	202,881
NUMERATOR:
Numerator for basic EPU - Net income attributable to common unitholders						$	84,363					$	85,365					$	205,606					$	202,881
Effect of dilutive securities						—						—						—						—
Numerator for diluted EPU - Net income (loss) attributable to common unitholders after the effect of dilutive securities						$	84,363					$	85,365					$	205,606					$	202,881
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)						211,852						210,687						211,600						210,680
Effect of dilutive securities						—						—						—						—
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities						211,852						210,687						211,600						210,680
NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)						$	0.40					$	0.41					$	0.97					$	0.96
Per common unit (diluted)						$	0.40					$	0.41					$	0.97					$	0.96

The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:

						Three Months Ended September 30,												Nine Months Ended September 30,
						2025						2024						2025						2024
						(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis						15,072						15,072						15,072						15,072

The common units represent limited partner interests in the Partnership. The holders of common units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units under the partnership agreement. 

The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in Black Stone Minerals Company, L.P. prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner (the "Board"), holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control, may not vote on any matter.

The partnership agreement generally provides that beginning on November 28, 2023 any distributions are paid each quarter in the following manner:

• first, to the holders of the Series B cumulative convertible preferred units in an amount equal to 9.8% of the face amount of the preferred units per annum, subject to readjustment every two years thereafter; and

• second, to the holders of common units.

The following table provides information about the Partnership's per unit distributions to common unitholders:

						Three Months Ended September 30,												Nine Months Ended September 30,
						2025						2024						2025						2024
Distributions declared and paid per common unit						$	0.300					$	0.375					$	1.050					$	1.225

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program. The unit repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market condition, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership made no repurchases under this program for the nine months ended September 30, 2025. The program is funded from the Partnership’s cash on hand or through borrowings under the Credit Facility. Any repurchased units are canceled.

On October 15, 2025, the Board approved a distribution for the three months ended September 30, 2025 of $0.30 per common unit. Distributions will be payable on November 13, 2025 to unitholders of record at the close of business on November 6, 2025.

In October 2025, the Partnership revised and amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was reaffirmed at $580.0 million and the Partnership elected to maintain cash commitments under the Credit Facility at $375.0 million. All existing banks in the lender syndicate elected to continue participating in the Credit Facility. No other significant terms were changed as part of the amendment.

On November 3, 2025, the Partnership announced its leadership succession plan, which will be effective January 1, 2026. At that time, Thomas Carter will move into the role of Executive Chairman, and Fowler Carter and Taylor DeWalch will succeed him as co-Chief Executive Officers and be appointed to the Board. Chris Bonner will be promoted to Senior Vice President and Chief Financial Officer.

On October 30, 2025, William Mathis tendered his resignation from the Board, effective immediately, to focus on other commitments. Mr. Mathis’s resignation is not the result of any disagreement with the Partnership’s operations, policies, or procedures.

Will Randall has been named as Chair of the Nominating and Governance Committee, and Jerry Kyle has been appointed to fill the vacancy on that committee. The Board expects to fill the vacancy caused by Mr. Mathis’s resignation in due course.

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 Haynesville 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.

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 September 30, 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.

At the end of the third quarter, Aethon Energy ("Aethon") was operating one rig on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. Aethon’s development program remains on track, with 3 wells spud of the total 15 wells expected to be drilled in the current program year ending in June 2026. Aethon successfully turned to sales 2 gross (0.09 net) wells during the third quarter and has an inventory of 12 gross (0.78 net) wells from the previous program year that it expects to turn to sales during the fourth quarter of 2025 and early 2026.

In the Louisiana Haynesville, development continued under our Accelerated Drilling Agreements (“ADAs”). These agreements incentivize operators to accelerate development in our high-interest areas in exchange for a modest reduction in royalty burden, allowing us to capture near-term revenue and reduce uncertainty about where the locations sit in the operator's development plan. Recently, 2 gross (0.13 net) wells in De Soto and Sabine Parishes were turned to sales under our ADAs. This brings the total well count under the ADA program to 9.

In the Permian Basin, we continue to monitor activity including a large-scale development. A large operator has spud 34 gross (1.22 net) wells on our acreage in Culberson County, Texas. During the third quarter, 5 gross (0.18 net) wells were turned to sales. We anticipate 13 gross wells (0.47 net) to turn to sales in the fourth quarter of 2025, with the remaining 16 gross (0.57 net) wells expected in the first half of 2026.

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

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 nine months ended September 30, 2025 compared to the same period in 2024, primarily due to weakening global demand amid, changes in trade policies, including imposition of tariffs and other import/export restrictions, and escalating trade tensions between the United States and China. The decline was further driven by an oversupplied market, as OPEC+ members unwound voluntary production cuts and non-OPEC+ producers increased output. Natural gas prices increased during the nine months ended September 30, 2025 relative to the prior-year period. Prices were supported by unusually cold weather in the first quarter of 2025, which drove higher heating demand and resulted in lower-than-average storage levels. Natural gas pricing was also supported by higher wholesale power pricing this summer compared to last summer. In the third quarter of 2025, natural gas pricing experienced a slight decline due to milder weather conditions lowering electricity demand.

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:

						2025																		2024
Benchmark Prices1						Third Quarter						Second Quarter									First Quarter						Third Quarter						Second Quarter						First Quarter
WTI spot oil price ($/Bbl)						$	63.17					$	66.30								$	71.87					$	68.75					$	82.83					$	83.96
Henry Hub spot natural gas ($/MMBtu)						$	3.12					3.26									4.11						2.65						2.42						1.54

1 Source: EIA

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:

						2025																		2024
U.S. Rotary Rig Count1						Third Quarter						Second Quarter						First Quarter						Third Quarter						Second Quarter						First Quarter
Oil						424						432						484						484						479						506
Natural gas						117						109						103						99						97						112
Other						8						6						5						4						5						3
Total						549						547						592						587						581						621

1 Source: Baker Hughes Incorporated

The majority of the production volumes attributable to our interests are derived from natural gas production. 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") estimates that natural gas inventories concluded the injection season in October 2025 at 4.0 Tcf, which is 5% higher than the five-year average.

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

						2025																		2024
Region1						Third Quarter						Second Quarter						First Quarter						Third Quarter						Second Quarter						First Quarter
East						832						602						284						846						660						363
Midwest						972						688						364						1,013						779						510
Mountain						269						228						165						283						239						162
Pacific						302						287						202						293						282						227
South Central						1,186						1,148						758						1,113						1,174						996
Total						3,561						2,953						1,773						3,548						3,134						2,258

1 Source: EIA

Net natural gas exports averaged 14.5 Bcf per day during the third quarter of 2025, a 22% increase from the 2024 average. The EIA forecasts average exports of 16.0 Bcf per day for the remainder of 2025 and 16.3 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 the remainder of 2025 and into 2026.

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.

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.

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.

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 September 30, 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 September 30, 2025, we have hedged a portion of our expected future volumes for the remainder of 2025, 2026, and 2027.

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.

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:

						Three Months Ended September 30,												Nine Months Ended September 30,
						2025						2024						2025						2024
						(in thousands)
Net income						$	91,729					$	92,731					$	227,705					$	224,980
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization						9,900						11,258						28,217						34,253
Interest expense						2,426						724						6,093						1,979
Income tax expense (benefit)						41						39						(36)						225
Accretion of asset retirement obligations						344						324						1,013						962
Equity–based compensation						2,208						2,177						7,223						6,765
Unrealized (gain) loss on commodity derivative instruments						(20,372)						(20,811)						(17,621)						21,642
Adjusted EBITDA						86,276						86,442						252,594						290,806
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue						(1)						(1)						(3)						(3)
Cash interest expense						(2,146)						(453)						(5,263)						(1,172)
Preferred unit distributions						(7,366)						(7,366)						(22,099)						(22,099)
Distributable cash flow						$	76,763					$	78,622					$	225,229					$	267,532

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

						Three Months Ended September 30,
						2025						2024						Variance
						(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)						912						875						37						4.2		%
Natural gas (MMcf)1						14,556						15,369						(813)						(5.3)		%
Equivalents (MBoe)						3,338						3,437						(99)						(2.9)		%
Equivalents/day (MBoe)						36.3						37.4						(1.1)						(2.9)		%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)						$	62.60					$	73.15					$	(10.55)					(14.4)		%
Natural gas ($/Mcf)1						2.96						2.41						0.55						22.8		%
Equivalents ($/Boe)						$	30.01					$	29.40					$	0.61					2.1		%
Revenue:
Oil and condensate sales						$	57,091					$	63,999					$	(6,908)					(10.8)		%
Natural gas and natural gas liquids sales1						43,086						37,039						6,047						16.3		%
Lease bonus and other income						5,006						2,143						2,863						133.6		%
Revenue from contracts with customers						105,183						103,181						2,002						1.9		%
Gain (loss) on commodity derivative instruments						27,287						31,675						(4,388)						(13.9)		%
Total revenue						$	132,470					$	134,856					$	(2,386)					(1.8)		%
Operating expenses:
Lease operating expense						$	2,753					$	2,422					$	331					13.7		%
Production costs and ad valorem taxes						10,935						12,369						(1,434)						(11.6)		%
Exploration expense						2,151						2,562						(411)						(16.0)		%
Depreciation, depletion, and amortization						9,900						11,258						(1,358)						(12.1)		%
General and administrative						12,287						12,801						(514)						(4.0)		%
Other expense:
Interest expense						2,426						724						1,702						235.1		%

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.

Total revenue for the quarter ended September 30, 2025 decreased compared to the quarter ended September 30, 2024. The decrease in total revenue in the third quarter of 2025 is primarily due to a decreased gain on our commodity derivative instruments compared to the corresponding prior period and a decrease in oil and condensate sales, which were partially offset by an increase in natural gas and NGL sales and lease bonus and other income.

Oil and condensate sales. Oil and condensate sales decreased for the quarter ended September 30, 2025 as compared to the corresponding period in 2024 primarily due to lower realized commodity prices, which were partially offset by increased production volumes. The increase in oil and condensate production was driven by higher mineral and royalty volumes in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 95% of total oil and condensate volumes for quarters ended September 30, 2025 and 2024, respectively.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended September 30, 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 decrease in production volumes. The decrease in production was driven by reduced royalty interest volumes, primarily within the Haynesville/Bossier play. Mineral and royalty interest production accounted for 96% and 94% of our natural gas volumes for the quarters ended September 30, 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 third quarter of 2025, gains from our commodity derivative instruments decreased compared to the same period in 2024. For the three months ended September 30, 2025, we recognized $6.9 million of realized gains and $20.4 million of unrealized gains from our oil and natural gas commodity contracts, compared to $10.9 million of realized gains and $20.8 million of unrealized gains in the same period in 2024. The unrealized gains on our commodity contracts during the third quarter of 2025 were primarily driven by changes in the forward commodity price curves for natural gas. The unrealized gains for the same period in 2024 were primarily driven by changes in the forward commodity price curves for oil.

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 third quarter of 2025 was higher than the same period in 2024. Leasing activity in the Permian Basin and Haynesville/Bossier plays made up the majority of lease bonus and other income for the third quarter of 2025, while the majority of the third quarter 2024 activity came from leasing activity in the Bakken/Three Forks.

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 increased for the quarter ended September 30, 2025 as compared to the same period in 2024, primarily due to increased 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 September 30, 2025, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2024, primarily due to lower production taxes from decreased oil commodity prices and reduced natural gas production, as well as lower ad valorem tax estimates.

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 September 30, 2025, exploration expenses decreased compared to the same period in 2024, primarily due to a decrease in seismic costs.

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 September 30, 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 September 30, 2025, general and administrative expenses slightly decreased as compared to the same period in 2024, primarily due to lower costs recognized under our short-term cash incentive plan.

Interest expense. Interest expense increased for the quarter ended September 30, 2025 as compared to the corresponding period in 2024. The increase was due to higher average outstanding borrowings under our Credit Facility.

The following table shows our production, revenues, pricing, and expenses for the periods presented:

						Nine Months Ended September 30,
						2025						2024						Variance
						(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)						2,491						2,751						(260)						(9.5)		%
Natural gas (MMcf)1						43,119						48,190						(5,071)						(10.5)		%
Equivalents (MBoe)						9,678						10,783						(1,105)						(10.2)		%
Equivalents/day (MBoe)						35.4						39.4						(4.0)						(10.2)		%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)						$	65.43					$	76.01					$	(10.58)					(13.9)		%
Natural gas ($/Mcf)1						3.42						2.40						1.02						42.5		%
Equivalents ($/Boe)						$	32.08					$	30.11					$	1.97					6.5		%
Revenue:
Oil and condensate sales						$	162,991					$	209,112					$	(46,121)					(22.1)		%
Natural gas and natural gas liquids sales1						147,510						115,543						31,967						27.7		%
Lease bonus and other income						16,645						10,480						6,165						58.8		%
Revenue from contracts with customers						327,146						335,135						(7,989)						(2.4)		%
Gain (loss) on commodity derivative instruments						24,070						14,838						9,232						62.2		%
Total revenue						$	351,216					$	349,973					$	1,243					0.4		%
Operating expenses:
Lease operating expense						$	7,905					$	7,433					$	472					6.4		%
Production costs and ad valorem taxes						30,146						38,876						(8,730)						(22.5)		%
Exploration expense						9,010						2,579						6,431						249.4		%
Depreciation, depletion, and amortization						28,217						34,253						(6,036)						(17.6)		%
General and administrative						41,383						40,286						1,097						2.7		%
Other expense:
Interest expense						6,093						1,979						4,114						207.9		%