Black Stone Minerals有限合夥公司（「BSM」或「合夥公司」）是一家公開交易的特拉華州有限合夥公司，擁有石油和天然氣礦物權益，這構成了絕大部分資產基礎。本合作公司的資產也包括非參與的專有權利和超限專有權益。這些權益，基本上是不承擔費用的，統稱爲「礦物和專有權益」。合作公司的礦物和專有權益位於美國本土的各個州，包括所有主要陸上產油盆地。合作公司還擁有特定石油和天然氣屬性的非經營工作權益。合作公司的普通單位在紐約證券交易所上市，代碼爲「BSM」。
black stone minerals有限合夥公司（「BSM」或「合夥公司」）是一家公開交易的特拉華州有限合夥公司，擁有組成絕大部分資產資產基礎的油氣礦權。 合作伙伴的資產還包括非參與的專有縱向權益和超額縱向權益。 這些權益通常不需要成本，統稱爲「礦權和縱向權益」。 合作伙伴的礦權和縱向權益位於 41 大陸美利堅合衆國（「美國」）的州份，包括所有主要陸上生產盆地。 該合作伙伴還擁有某些油氣物業的無操作工作權益。 合作伙伴的普通單位在紐約證券交易所交易，代碼是"BSm."
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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
2024
2023
2024
2023
(in thousands)
Beginning fair value of commodity derivative instruments
$
(5,118)
$
51,046
$
37,335
$
28,941
Gain (loss) on oil derivative instruments
25,444
(36,013)
988
(21,232)
Gain (loss) on natural gas derivative instruments
6,231
9,091
13,850
57,884
Net cash paid (received) on settlements of oil derivative instruments
3,852
(2,659)
9,257
(4,431)
Net cash paid (received) on settlements of natural gas derivative instruments
(14,716)
(21,530)
(45,737)
(61,227)
Net change in fair value of commodity derivative instruments
20,811
(51,111)
(21,642)
(29,006)
Ending fair value of commodity derivative instruments
$
15,693
$
(65)
$
15,693
$
(65)
The Partnership had the following open derivative contracts for oil as of September 30, 2024:
Weighted Average Price (Per Bbl)
Range (Per Bbl)
Period and Type of Contract
Volume (Bbl)
Low
High
Oil Swap Contracts:
2024
Third Quarter
190,000
$
71.45
$
67.00
$
81.00
Fourth Quarter
570,000
71.45
67.00
81.00
2025
First Quarter
555,000
$
71.22
$
70.02
$
73.15
Second Quarter
555,000
71.22
70.02
73.15
Third Quarter
555,000
71.22
70.02
73.15
Fourth Quarter
555,000
71.22
70.02
73.15
2026
First Quarter
120,000
$
65.85
$
65.52
$
66.23
Second Quarter
120,000
65.85
65.52
66.23
Third Quarter
120,000
65.85
65.52
66.23
Fourth Quarter
120,000
65.85
65.52
66.23
12
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The Partnership had the following open derivative contracts for natural gas as of September 30, 2024:
Weighted Average Price (Per MMBtu)
Range (Per MMBtu)
Period and Type of Contract
Volume (MMBtu)
Low
High
Natural Gas Swap Contracts:
2024
Fourth Quarter
10,580,000
$
3.55
$
3.00
$
3.76
2025
First Quarter
10,800,000
$
3.36
$
3.02
$
3.65
Second Quarter
10,920,000
3.36
3.02
3.65
Third Quarter
11,040,000
3.45
3.34
3.65
Fourth Quarter
11,040,000
3.45
3.34
3.65
2026
First Quarter
7,200,000
$
3.52
$
3.50
$
3.57
Second Quarter
7,280,000
3.52
3.50
3.57
Third Quarter
7,360,000
3.52
3.50
3.57
Fourth Quarter
7,360,000
3.52
3.50
3.57
The Partnership entered into the following derivative contracts for oil subsequent to September 30, 2024:
Weighted Average Price (Per Bbl)
Range (Per Bbl)
Period and Type of Contract
Volume (Bbl)
Low
High
Oil Swap Contracts:
2026
First Quarter
60,000
$
67.18
$
67.00
$
67.35
Second Quarter
60,000
67.18
67.00
67.35
Third Quarter
60,000
67.18
67.00
67.35
Fourth Quarter
60,000
67.18
67.00
67.35
NOTE 5 - FAIR VALUE MEASUREMENTS
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 termof 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).
13
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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, 2024 and 2023.
The carrying value of the Partnership's cash and cash equivalents, 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, 2024 and December 31, 2023 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.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
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, 2024
Financial Assets
Commodity derivative instruments
$
—
$
22,636
$
—
$
(3,935)
$
18,701
Financial Liabilities
Commodity derivative instruments
$
—
$
6,943
$
—
$
(3,935)
$
3,008
As of December 31, 2023
Financial Assets
Commodity derivative instruments
$
—
$
41,983
$
—
$
(3,338)
$
38,645
Financial Liabilities
Commodity derivative instruments
$
—
$
4,648
$
—
$
(3,338)
$
1,310
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
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 assessment of 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, 2024 or the year ended December 31, 2023. 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 assessing for impairment. 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 fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.
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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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 significant changes in valuation techniques or related inputs as of September 30, 2024 or December 31, 2023. There were no assets measured at fair value on a non-recurring basis for the nine months ended September 30, 2024 or the year ended December 31, 2023.
NOTE 6 - CREDIT FACILITY
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 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 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 April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million. The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2025.
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 secured overnight financing rate ("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. 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, 2023 and September 30, 2024, 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 8.04% during the nine months ended September 30, 2024 and 7.36% for the twelve months ended December 31, 2023. 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, 2024, the Partnership was in compliance with all financial covenants in the Credit Facility.
There was no aggregate principal balance outstanding at September 30, 2024 and December 31, 2023. The unused portion of the available borrowings under the Credit Facility was $375.0 million at September 30, 2024 and December 31, 2023.
15
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 - COMMITMENTS AND CONTINGENCIES
Environmental Matters
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 significant to the unaudited interim consolidated financial statements, and no provision for potential remediation costs has been recorded.
Litigation
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, 2024 will be resolved without material adverse effect on the Partnership’s financial condition or operations.
NOTE 8 - INCENTIVE COMPENSATION
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,
2024
2023
2024
2023
(in thousands)
Cash—short and long-term incentive plans
$
1,498
$
1,303
$
3,883
$
3,236
Equity-based compensation—restricted common units
1,006
976
2,967
2,872
Equity-based compensation—restricted performance units
621
2,282
2,050
3,968
Board of Directors incentive plan
550
519
1,748
1,572
Total incentive compensation expense
$
3,675
$
5,080
$
10,648
$
11,648
For the nine months ended September 30, 2024, the Partnership repurchased 291,163 common units at a weighted average price of $15.28 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.
NOTE 9 - PREFERRED UNITS
Series B Cumulative Convertible Preferred Units
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
16
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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 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.
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, 2024 and a carrying value of $299.1 million, including accrued distributions of $6.0 million, as of December 31, 2023. 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.
NOTE 10 - EARNINGS PER UNIT
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 (loss) 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.
17
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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,
2024
2023
2024
2023
(in thousands, except per unit amounts)
NET INCOME (LOSS)
$
92,731
$
62,067
$
224,980
$
274,902
Distributions on Series B cumulative convertible preferred units
(7,366)
(5,250)
(22,099)
(15,750)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS
$
85,365
$
56,817
$
202,881
$
259,152
ALLOCATION OF NET INCOME (LOSS):
General partner interest
$
—
$
—
$
—
$
—
Common units
85,365
56,817
202,881
259,152
$
85,365
$
56,817
$
202,881
$
259,152
NUMERATOR:
Numerator for basic EPU - Net income (loss) attributable to common unitholders
$
85,365
$
56,817
$
202,881
$
259,152
Effect of dilutive securities
—
—
—
15,750
Numerator for diluted EPU - Net income (loss) attributable to common unitholders after the effect of dilutive securities
$
85,365
$
56,817
$
202,881
$
274,902
DENOMINATOR:
Denominator for basic EPU - weighted average common units outstanding (basic)
210,687
209,982
210,680
209,963
Effect of dilutive securities
—
—
—
14,969
Denominator for diluted EPU - weighted average number of common units outstanding after the effect of dilutive securities
210,687
209,982
210,680
224,932
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic)
$
0.41
$
0.27
$
0.96
$
1.23
Per common unit (diluted)
$
0.41
$
0.27
$
0.96
$
1.22
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,
2024
2023
2024
2023
(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an as-converted basis
15,072
14,969
15,072
—
NOTE 11 - COMMON UNITS
Common Units
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.
18
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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 on each Readjustment Date; 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,
2024
2023
2024
2023
Distributions declared and paid per common unit
$
0.3750
$
0.4750
$
1.2250
$
1.4250
Common Unit Repurchase Program
On October 30, 2023, the Board authorized a $150.0 million unit repurchase program, terminating its existing $75.0 million program authorized in 2018. 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, 2024. The program is funded from the Partnership’s cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.
NOTE 12 - SUBSEQUENT EVENTS
Distribution
On October 16, 2024, the Board approved a distribution for the three months ended September 30, 2024 of $0.375 per common unit. Distributions will be payable on November 15, 2024 to unitholders of record at the close of business on November 8, 2024.
Acquisitions
Subsequent to September 30, 2024, the Partnership acquired mineral and royalty interests from various sellers for cash consideration of $12.6 million. These acquisitions were funded with cash from operating activities.
19
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited 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, 2023 ("2023 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.”
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;
•future operating results;
20
•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 2023 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 September 30, 2024, 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 68,000 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
Shelby Trough Development Update
In September 2024, we entered into letter agreements with Aethon Energy ("Aethon") to amend the Joint Exploration Agreements ("JEAs") in San Augustine and Angelina counties. In those agreements, the parties agreed to revise the current program year drill schedules under each JEA, to extend the respective program years by nine months, and to withdraw the invocation of the time-out provisions. Aethon also released its rights under 25,000 acres from the parties' area of mutual interest defined in the original JEAs. Upon the satisfaction of the current program year performance deadlines as described in the letter agreements, Aethon will have an inventory of ten banked wells in Angelina and one banked well in San Augustine.
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
21
instruments, which have recently consisted of fixed-price swap contracts.
While oil inventories continued to decline in the third quarter of 2024, oil prices decreased during the period because of offsetting concerns that the market would continue to be oversupplied in 2025 without additional growth in demand. OPEC+ members' decision to delay production increases until December 2024 is expected to lead to further reductions in global inventories and is reflective of the lingering impact of rising global inventories experienced in 2023. Heightened geopolitical risk related to continued conflict in the Middle East has increased the possibility for future supply disruptions and price volatility. Natural gas prices decreased sharply in the fourth quarter of 2023 and the first quarter of 2024 as a result of a large surplus of storage inventory. Less natural gas-directed drilling and production curtailments led to increased natural gas prices in the second quarter of 2024 which continued to recover in the third quarter of 2024 due to hot summer temperatures and the related increase in U.S. electricity demand across all sectors. An increase in LNG exports with the addition of capacity further added to natural gas price increases in the third quarter of 2024. Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine and the Middle East, 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:
2024
2023
Benchmark Prices1
Third Quarter
Second Quarter
First Quarter
Third Quarter
Second Quarter
First Quarter
WTI spot oil price ($/Bbl)
$
68.75
$
82.83
$
83.96
$
90.77
$
70.66
$
75.68
Henry Hub spot natural gas ($/MMBtu)
2.65
2.42
1.54
2.68
2.48
2.10
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:
2024
2023
U.S. Rotary Rig Count1
Third Quarter
Second Quarter
First Quarter
Third Quarter
Second Quarter
First Quarter
Oil
484
479
506
502
545
592
Natural gas
99
97
112
116
124
160
Other
4
5
3
5
5
3
Total
587
581
621
623
674
755
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") estimates that natural gas inventories concluded the injection season in October 2024 at 3.9 Tcf, which is 4% higher than the five-year average.
22
The following table shows natural gas storage volumes by region at the end of each quarter presented:
2024
2023
Region1
Third Quarter
Second Quarter
First Quarter
Third Quarter
Second Quarter
First Quarter
East
846
660
363
847
643
335
Midwest
1,013
779
510
991
705
421
Mountain
283
239
162
239
173
80
Pacific
293
282
227
278
216
73
South Central
1,113
1,174
996
1,090
1,141
921
Total
3,548
3,134
2,258
3,445
2,878
1,830
1 Source: EIA
Natural Gas Exports
Net natural gas exports averaged 11.5 Bcf per day during the third quarter of 2024, a 3% decrease from the 2023 average. The EIA forecasts average exports of 13.2 Bcf per day for the remainder of 2024 and 13.8 Bcf per day for 2025. The EIA forecast reflects assumptions that U.S. LNG exports will increase as LNG export projects come on line in late 2024 and mid-2025.
23
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.
24
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 September 30, 2024 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, 2024, we had hedged 75% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively. As of September 30, 2024, we had also hedged 77% and 79% of our available natural gas hedge volumes for 2024 and 2025, respectively.
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.
25
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,
2024
2023
2024
2023
(in thousands)
Net income (loss)
$
92,731
$
62,067
$
224,980
$
274,902
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization
11,258
12,367
34,253
33,935
Interest expense
724
621
1,979
2,080
Income tax expense (benefit)
39
(109)
225
177
Accretion of asset retirement obligations
324
254
962
749
Equity–based compensation
2,177
3,777
6,765
8,412
Unrealized (gain) loss on commodity derivative instruments
(20,811)
51,111
21,642
29,006
(Gain) loss on sale of assets, net
—
(73)
—
(73)
Adjusted EBITDA
86,442
130,015
290,806
349,188
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue
(1)
(1)
(3)
(8)
Cash interest expense
(453)
(359)
(1,172)
(1,305)
Preferred unit distributions
(7,366)
(5,250)
(22,099)
(15,750)
Distributable cash flow
$
78,622
$
124,405
$
267,532
$
332,125
26
Results of Operations
Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023
The following table shows our production, revenue, and operating expenses for the periods presented:
Three Months Ended September 30,
2024
2023
Variance
(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)
875
1,092
(217)
(19.9)
%
Natural gas (MMcf)1
15,369
16,980
(1,611)
(9.5)
%
Equivalents (MBoe)
3,437
3,922
(485)
(12.4)
%
Equivalents/day (MBoe)
37.4
42.6
(5.2)
(12.2)
%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)
$
73.15
$
78.50
$
(5.35)
(6.8)
%
Natural gas ($/Mcf)1
2.41
2.87
(0.46)
(16.0)
%
Equivalents ($/Boe)
$
29.40
$
34.30
$
(4.90)
(14.3)
%
Revenue:
Oil and condensate sales
$
63,999
$
85,724
$
(21,725)
(25.3)
%
Natural gas and natural gas liquids sales1
37,039
48,815
(11,776)
(24.1)
%
Lease bonus and other income
2,143
2,180
(37)
(1.7)
%
Revenue from contracts with customers
103,181
136,719
(33,538)
(24.5)
%
Gain (loss) on commodity derivative instruments
31,675
(26,922)
58,597
217.7
%
Total revenue
$
134,856
$
109,797
$
25,059
22.8
%
Operating expenses:
Lease operating expense
$
2,422
$
2,615
$
(193)
(7.4)
%
Production costs and ad valorem taxes
12,369
16,441
(4,072)
(24.8)
%
Exploration expense
2,562
1,711
851
49.7
%
Depreciation, depletion, and amortization
11,258
12,367
(1,109)
(9.0)
%
General and administrative
12,801
14,448
(1,647)
(11.4)
%
Other expense:
Interest expense
724
621
103
16.6
%
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.
Revenue
Total revenue for the quarter ended September 30, 2024 increased compared to the quarter ended September 30, 2023. The increase in total revenue in the third quarter of 2024 is primarily due to a gain on our commodity derivative instruments compared to a loss in the corresponding prior period, which were partially offset by a decrease in natural gas, NGL, oil, and condensate sales.
Oil and condensate sales. Oil and condensate sales decreased for the quarter ended September 30, 2024 as compared to the corresponding period in 2023 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 95% and 96% of total oil and condensate volumes for quarters ended September 30, 2024 and 2023, respectively.
27
Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended September 30, 2024 as compared to the corresponding prior period. The decrease was due to lower realized commodity prices between the comparative periods and 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 play trend. Mineral and royalty interest production accounted for 94% and 94% of our natural gas volumes for the quarters ended September 30, 2024 and 2023, 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 2024, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2023. For the three months ended September 30, 2024, we recognized $10.9 million of realized gains and $20.8 million of unrealized gains from our oil and natural gas commodity contracts, compared to $24.2 million of realized gains and $51.1 million of unrealized losses in the same period in 2023. The unrealized gains on our commodity contracts during the third quarters of 2024 and the unrealized losses in the corresponding period in 2023 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 third quarter of 2024 was lower than the same period in 2023. Leasing activity in the Bakken/Three Forks made up the majority of lease bonus and other income for the third quarter of 2024, while the majority of the third quarter 2023 activity came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.
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 September 30, 2024 as compared to the same period in 2023, 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 September 30, 2024, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2023, primarily due to lower production taxes stemming from lower 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 September 30, 2024, exploration expenses increased compared to the same period in 2023, primarily due to an increase in seismic purchases and delay rentals.
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, 2024 as compared to the same period in 2023 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 ofemployee salariesand related benefits, office expenses, and fees for professional services. For thequarter ended September 30, 2024, general and administrative expenses decreased as compared to the same period in2023, primarily due to a decrease in consulting costs and equity-based compensation, partially offset by an increase in salaries. The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the quarter ended September 30, 2024 compared to upward movements in the corresponding prior period.
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Interest expense. Interest expense in the third quarter of 2024 increased as compared tothecorresponding period in 2023, with minimal average outstanding borrowings under our Credit Facility during each period. Interest expense for both periods primarily consisted of commitment fees and amortization of debt issuance costs.
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023
The following table shows our production, revenues, pricing, and expenses for the periods presented:
Nine Months Ended September 30,
2024
2023
Variance
(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)
2,751
2,731
20
0.7
%
Natural gas (MMcf)1
48,190
48,101
89
0.2
%
Equivalents (MBoe)
10,783
10,748
35
0.3
%
Equivalents/day (MBoe)
39.4
39.4
—
—
%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)
$
76.01
$
76.23
$
(0.22)
(0.3)
%
Natural gas ($/Mcf)1
2.40
3.07
(0.67)
(21.8)
%
Equivalents ($/Boe)
$
30.11
$
33.13
$
(3.02)
(9.1)
%
Revenue:
Oil and condensate sales
$
209,112
$
208,184
$
928
0.4
%
Natural gas and natural gas liquids sales1
115,543
147,857
(32,314)
(21.9)
%
Lease bonus and other income
10,480
8,682
1,798
20.7
%
Revenue from contracts with customers
335,135
364,723
(29,588)
(8.1)
%
Gain (loss) on commodity derivative instruments
14,838
36,652
(21,814)
(59.5)
%
Total revenue
$
349,973
$
401,375
$
(51,402)
(12.8)
%
Operating expenses:
Lease operating expense
$
7,433
$
8,149
$
(716)
(8.8)
%
Production costs and ad valorem taxes
38,876
41,952
(3,076)
(7.3)
%
Exploration expense
2,579
1,719
860
50.0
%
Depreciation, depletion, and amortization
34,253
33,935
318
0.9
%
General and administrative
40,286
38,950
1,336
3.4
%
Other expense:
Interest expense
1,979
2,080
(101)
(4.9)
%
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.
Revenue
Total revenue for the nine months ended September 30, 2024 decreased compared to the corresponding prior period. The decrease in total revenue is primarily due to a reduced gain on our commodity derivative instruments compared to the gain in the corresponding prior period and a decrease in natural gas and NGL sales, which were partially offset by an increase in oil and condensate sales.
29
Oil and condensate sales. Oil and condensate sales during the nine months ended September 30, 2024 slightly increased compared to the corresponding prior period primarily due to higher production volumes. Our mineral and royalty interest oil and condensate volumes accountedfor 95%and 94% of total oil and condensate volumes for thenine months ended September 30, 2024 and 2023, respectively.
Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 30, 2024 decreased compared to the corresponding prior period due to lower realized commodity prices. Mineral and royalty interest production accounted for 94% and 94% of our natural gas volumes for the nine months ended September 30, 2024 and 2023, respectively.
Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2024, we recognized a reduced gain from our commodity derivative instruments as compared to the gain recognized for the same period in 2023. In the nine months ended September 30, 2024, we recognized $36.4 million of realized gains and $21.6 million of unrealized losses from our oil and natural gas commodity contracts, compared to $65.7 million of realized gains and $29.0 million of unrealized losses in the same period in 2023. The unrealized losses on our commodity contracts during the nine months ended September 30, 2024 and the corresponding period in 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.
Lease bonus and other income. Lease bonus and other income for the nine months ended September 30, 2024 was higher than the same period in 2023. Leasing activity in the Permian Basin, Bakken/Three Forks, and the Austin Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas composed the majority of lease bonus and other income for the nine months ended September 30, 2024, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.
Operating and Other Expenses
Lease operating expense. Lease operating expense decreased for the nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.
Production costs and ad valorem taxes. For the nine months ended September 30, 2024, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2023, primarily due to a decrease in production taxes from lower oil and natural gas commodity prices.
Exploration expense. For the nine months ended September 30, 2024 exploration expenses increased compared to the same period in 2023, primarily due to an increase in seismic purchases and delay rentals.
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization slightly increased for the nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to increased production volumes.
General and administrative. For the nine months ended September 30, 2024, general and administrative expenses increased as compared to the same period in2023, primarily due to higher professional costs related to outside legal fees, consulting costs for internal projects, and cash compensation, partially offset by a decrease in equity-based compensation. The increase in cash compensation was driven by increases in salaries and costs recognized under our short-term cash incentive plan. The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the nine months ended September 30, 2024 compared to upward movements in the corresponding prior period.
Interest expense. Interest expense was lower in the nine months ended September 30, 2024 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.
30
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:
Nine Months Ended September 30,
2024
2023
Change
(in thousands)
Cash flows provided by operating activities
$
298,087
$
387,135
$
(89,048)
Cash flows provided by (used in) investing activities
(64,227)
(4,946)
(59,281)
Cash flows provided by (used in) financing activities
(283,179)
(330,466)
47,287
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 nine months ended September 30, 2024 as compared to the same period of 2023. The decrease was primarily due to lower natural gas and NGL sales stemming from lower realized commodity prices and a reduction in cash received on the settlement of commodity derivatives in the nine months ended September 30, 2024 compared to the same period of 2023.
Investing Activities. Net cash used in investing activities in the nine months ended September 30, 2024 increased as compared to the same period of 2023. The increase was primarily due to acquisitions of oil and natural gas properties in the nine months ended September 30, 2024 as compared to minimal acquisition activity in the corresponding prior period.
Financing Activities. Cash flows used in financing activities decreased for the nine months ended September 30, 2024 as compared to the same period of 2023. The decrease was primarily due to lower distributions paid to unitholders and no net repayments on our Credit Facility for the nine months ended September 30, 2024 compared to net repayments for the nine months ended September 30, 2023.
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Development Capital Expenditures
Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, net of farmout reimbursements, of which $0.7 million has been invested in the nine months ended September 30, 2024. 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 September 30, 2024, we have also spent $1.8 million acquiring leases in areas around our drilling programs.
Acquisitions
During the nine months ended September 30, 2024, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $65.2 million, including capitalized direct transaction costs. The consideration paid consisted of $64.2 million in cash that was funded 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 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 Exchange
In the third quarter of 2024, we closed on a transaction with a third-party operator whereby we received 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.
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 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million. The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 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 September 30, 2024, 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 September 30, 2024, there have been no material changes to our contractual obligations previously disclosed in our 2023 Annual Report on Form 10-K.
Critical Accounting Policies and Related Estimates
As of September 30, 2024, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2023 Annual Report on Form 10-K.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
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,
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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 September 30, 2024. Applying this discount results in an approximate 2.5% reduction of proved reserve volumes as compared to the undiscounted September 30, 2024 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 September 30, 2024, 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 nine months ended September 30, 2024, we had $1.8 million weighted average outstanding borrowings under our Credit Facility, bearing interest at a weighted average interest rate of 8.04%. 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 nine months ended September 30, 2024, 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.
Item 4. Controls and Procedures
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 September 30, 2024 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 September 30, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II – OTHER INFORMATION
Item 1. Legal Proceedings
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations.
Item 1A. Risk Factors
In addition to the other information set forth in this report, readers should carefully consider the risks under the heading “Risk Factors” in our 2023 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 2023 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.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.
Item 5. Other Information
During the three months ended September 30, 2024, none of our directors or executive officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.
Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).
Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of the Black Stone Minerals, L.P., dated as of April 22, 2020 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on April 24, 2020 (SEC File No. 001-37362)).
Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).
Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BLACK STONE MINERALS, L.P.
By:
Black Stone Minerals GP, L.L.C., its general partner
Date: November 5, 2024
By:
/s/ Thomas L. Carter, Jr.
Thomas L. Carter, Jr.
President, Chief Executive Officer, and Chairman
(Principal Executive Officer)
Date: November 5, 2024
By:
/s/ Taylor DeWalch
Taylor DeWalch
Senior Vice President, Chief Financial Officer, and Treasurer