Financial Performance - For the three months ended June 30, 2024, net income was $68,322, a decrease of 12.7% compared to $78,392 for the same period in 2023[108]. - Adjusted EBITDA for the quarter was $100,247, down 8.9% from $109,245 in the prior year[108]. - Total revenue for the quarter decreased by 6.3% to $109,624 from $117,000 in the same quarter of 2023, primarily due to a loss on commodity derivative instruments[111]. - Total revenue for the six months ended June 30, 2024, decreased by 26.2% to $215,117,000 compared to $291,578,000 in the same period in 2023, primarily due to a loss on commodity derivative instruments and a decrease in natural gas and NGL sales[122][126]. - General and administrative expenses increased by 12.2% to $27,485,000 for the six months ended June 30, 2024, primarily due to higher professional costs and cash compensation[129]. - Cash flows provided by operating activities decreased by 24.3% to $204,845,000 for the six months ended June 30, 2024, compared to $270,425,000 in the same period in 2023[136]. Revenue Breakdown - Oil and condensate sales increased by 20.0% to $73,889, driven by higher production volumes and realized prices[110]. - Natural gas and NGL sales decreased by 12.3% to $36,493, attributed to lower realized commodity prices despite increased production volumes[113]. - Oil and condensate sales increased by 18.5% to $145,113,000 for the six months ended June 30, 2024, driven by higher production volumes and realized commodity prices[124]. - Natural gas and NGL sales decreased by 20.7% to $78,504,000 for the six months ended June 30, 2024, due to lower realized commodity prices despite higher production volumes[125]. Production and Operations - As of June 30, 2024, the company holds mineral and royalty interests in 41 states, including approximately 68,000 producing wells[84]. - Production volumes for oil and condensate increased by 14.5% to 1,876 MBbls, and natural gas production increased by 5.5% to 32,820 MMcf for the six months ended June 30, 2024[121]. - The company recognized a loss of $5,547 on commodity derivative instruments for the quarter, compared to a gain of $11,303 in the same period last year[110]. - The company recognized a loss of $16,837,000 on commodity derivative instruments for the six months ended June 30, 2024, compared to a gain of $63,574,000 in the same period in 2023[126]. - Exploration expenses remained minimal for the quarter, consistent with the prior period[118]. Market Conditions - The average WTI spot oil price for the second quarter of 2024 was $82.83 per barrel, compared to $70.66 per barrel in the second quarter of 2023, reflecting a significant increase[90]. - The average Henry Hub spot natural gas price for the second quarter of 2024 was $2.42 per MMBtu, up from $2.10 per MMBtu in the second quarter of 2023[90]. - The total U.S. rotary rig count decreased to 581 in the second quarter of 2024 from 674 in the second quarter of 2023, indicating a decline in drilling activity[92]. - Natural gas storage levels are projected to rise to 4.0 Tcf by the end of October 2024, which is 6% higher than the five-year average[95]. - Net natural gas exports averaged 11.9 Bcf per day in the first half of 2024, consistent with the average for the full year of 2023[97]. Strategic Initiatives - The company continues to explore opportunities in renewable energy and carbon sequestration as part of its strategy for energy transition[83]. - Aethon Energy has invoked a time-out provision under Joint Exploration Agreements, potentially delaying drilling obligations until September 2024[86]. - The company utilizes various derivative instruments to manage cash flow variability associated with oil and natural gas production[88]. - The company uses commodity derivative financial instruments to mitigate exposure to price volatility in oil and natural gas[143]. - All counterparties to derivative contracts were rated Baa2 or better by Moody's as of June 30, 2024[145]. Financial Position and Capital Expenditures - The company’s capital expenditure budget for 2024 is expected to be approximately $2.3 million, with $0.4 million already invested in the first half of the year[138]. - Cash flows used in investing activities increased significantly to $(51,681,000) for the six months ended June 30, 2024, compared to $(2,633,000) in the same period in 2023, primarily due to acquisitions of oil and natural gas properties[134]. - The company acquired mineral and royalty interests for a total of $50.5 million, funded by $49.5 million in cash and $1.0 million in equity[139]. - The senior secured revolving credit facility has a maximum credit amount of $1.0 billion, with a reaffirmed borrowing base of $580.0 million as of October 2023[140]. - The company maintained cash commitments at $375.0 million after each borrowing base redetermination[140]. - As of June 30, 2024, the company was in compliance with all debt covenants[141]. - The company had $0.2 million in weighted average outstanding borrowings under the credit facility, with a weighted average interest rate of 7.96%[146]. - The next semi-annual borrowing base redetermination is scheduled for October 2024[140]. Asset Valuation - A 10% discount applied to SEC commodity pricing resulted in an approximate 2.5% reduction of proved reserve volumes[144]. - The company has not designated any of its contracts as fair value or cash flow hedges, impacting net income in the period of change[144].

Financial Data and Key Metrics Changes - Total production for Q2 2024 was 40,400 BOE per day, consistent with Q1 2024, generating $68 million in net income and over $100 million in adjusted EBITDA [5][9] - The distribution was maintained at $0.375 per unit, with excess coverage utilized for growth opportunities [5][10] - Distributable cash flow for the quarter was $92.5 million, representing a coverage ratio of 1.17x [9][10] Business Line Data and Key Metrics Changes - Mineral and royalty production was 38,200 BOE per day, flat compared to the previous quarter [9] - An increase in oil volumes helped offset the downturn in the gas market [9] Market Data and Key Metrics Changes - The company has hedged over 60% of expected volumes for the remainder of 2024, with natural gas hedges at approximately $3.55 per MMBtu compared to an average price of about $2 per MMBtu at Henry Hub for Q2 [10][11] Company Strategy and Development Direction - The company is focused on organic growth and targeted acquisitions to enhance its asset base and development opportunities [5][7] - A targeted grassroots acquisition program was initiated to enhance existing asset positions, with $26.5 million in minerals and royalty acquisitions added during the quarter [7] Management's Comments on Operating Environment and Future Outlook - Management expressed confidence in the long-term decision-making opportunities and a constructive outlook for natural gas [6] - The company is preparing for anticipated improvements in the natural gas market while maintaining a strong balance sheet [6][10] Other Important Information - The company has added 8 wells in the second quarter with initial production rates between 25 million to 30 million cubic feet per day [8] - The company continues to work with multiple operators to promote development on its acreage [7] Q&A Session Summary Question: Clarification on delayed initial production from Aethon wells - Management clarified that the delayed production refers to previously announced wells, with 8 of 10 expected to come online in the second half of the year [12] Question: Status of Aethon coming out of timeout - Management indicated ongoing discussions with Aethon regarding their status, with new wells having come online but no definitive updates available [13][14] Question: Details on undisclosed Gulf Coast mineral acquisitions - Management stated that they are not disclosing details publicly as they are still assimilating a position that is accretive to their existing assets [15]

Production and Revenue - Mineral and royalty production for Q2 2024 was 38.2 MBoe/d, with total production at 40.4 MBoe/d[2] - Oil and gas revenue for Q2 2024 was $110.4 million, down 3% from Q1 2024[5] - Total revenue for Q2 2024 was $109,624, a decrease of 6.4% from $117,000 in Q2 2023[20] - Oil and condensate sales increased to $73,889 in Q2 2024 from $61,551 in Q2 2023, representing a growth of 20.5%[20] - Natural gas and natural gas liquids sales decreased to $36,493 in Q2 2024 from $41,619 in Q2 2023, a decline of 12.8%[20] - Production of oil and condensate increased to 953 MBbls in Q2 2024 from 846 MBbls in Q2 2023, a rise of 12.7%[22] Financial Performance - Net income for Q2 2024 was $68.3 million, and Adjusted EBITDA totaled $100.2 million[2][6] - Distributable cash flow for Q2 2024 was $92.5 million, with a distribution of $0.375 per unit and coverage of 1.17x[2][8] - Net income for Q2 2024 was $68,322, down 13.7% from $78,392 in Q2 2023[20] - Adjusted EBITDA and Distributable cash flow are used to assess financial performance, but specific figures for these measures were not provided in the documents[25] - Net income for 2024 is $68,322,000, a decrease of 12.6% from $78,392,000 in 2023[26] - Adjusted EBITDA for 2024 is $100,247,000, down 8.9% from $109,245,000 in 2023[26] - Distributable cash flow for 2024 is $92,522,000, a decline of 10.7% compared to $103,606,000 in 2023[26] - Distributable cash flow per unit for 2024 is $0.439, down 10.9% from $0.493 in 2023[26] Expenses and Losses - The company reported a loss on commodity derivative instruments of $5.5 million for Q2 2024[6] - Total operating expenses for Q2 2024 were $41,134, an increase of 7.4% from $38,239 in Q2 2023[20] - The company reported a loss on commodity derivative instruments of $5,547 in Q2 2024, compared to a gain of $11,303 in Q2 2023[20] - Depreciation, depletion, and amortization increased to $11,356,000 in 2024 from $10,421,000 in 2023[26] - Interest expense decreased slightly to $626,000 in 2024 from $645,000 in 2023[26] - Preferred unit distributions increased to $7,366,000 in 2024 from $5,250,000 in 2023[26] - Unrealized loss on commodity derivative instruments for 2024 is $17,366,000, compared to a gain of $16,881,000 in 2023[26] Strategic Acquisitions and Operations - Black Stone acquired $26.5 million in mineral and royalty interests in Q2 2024, totaling $65.1 million since September 2023[12] - The company continues to focus on strategic mineral and royalty interest acquisitions to enhance its asset base[3][12] - As of June 30, 2024, Black Stone had 62 rigs operating, down from 78 in Q1 2024[9] Pricing and Market Trends - Average realized price per Boe was $30.01, a decrease of 3% from Q1 2024 and 4% from Q2 2023[4] - Realized prices for oil and condensate were $77.53 per Bbl in Q2 2024, compared to $72.76 per Bbl in Q2 2023, an increase of 10.5%[22] - The weighted average common units outstanding (basic) was 210,703 in Q2 2024, slightly up from 209,967 in Q2 2023[20] - Total units outstanding increased to 210,689 in 2024 from 209,986 in 2023[26] - The estimated distribution for the three months ended June 30, 2024, is based on 210,689,203 common units[26]

Black Stone Minerals (BSM) - For the March quarter, BSM reported EBITDA of $104 million, exceeding Street estimates of $93 million, with Distributable Cash Flow (DCF) of $0.46 per share, down from $0.59 in Q4 2023 [3] - The company cut its distribution by 22% due to lower natural gas prices and expiring gas hedges, but coverage is now at 1.22x with a 9% yield [4][5] - Production volumes fell 2% year-over-year, and realized prices decreased by 12%, indicating earnings may be at a trough [6] - DCF per share is projected to fall to $1.63 in 2024 from over $2.14 in 2023, with a run rate of $1.84 appearing strong [4][7] - The stock is viewed as a good inflation hedge, with potential annual returns of ~9% even if the company does not grow [7] Healthcare Realty (HR) - For the March quarter, HR beat AFFO per share estimates by $0.01 at $0.39, with guidance for Q2 reaffirmed at 38-39 cents and $1.54 for 2024 [9][10] - HR announced a joint venture with KKR, selling an 80% stake in 12 assets for approximately $300 million, with a cap rate of 6.6% [11][13] - The company plans to use excess capital from asset sales to repurchase shares, with a buyback plan of $500 million, representing 8% of shares outstanding [18] - Occupancy rates improved, with same-store occupancy increasing by 50 basis points in Q1, and the company aims for NOI growth of 4.4-5.5% in 2024 [16] - Current stock valuation suggests a price range of $12-20, with management's recent actions indicating potential upside [19][20]

[PART I – FINANCIAL INFORMATION](index=3&type=section&id=PART%20I%20%E2%80%93%20FINANCIAL%20INFORMATION) [Item 1. Financial Statements (Unaudited)](index=3&type=section&id=Item%201.%20Financial%20Statements%20%28Unaudited%29) This section presents the unaudited consolidated financial statements for Black Stone Minerals, L.P., including the balance sheets, statements of operations, statements of equity, statements of cash flows, and detailed notes [Consolidated Balance Sheets](index=3&type=section&id=Consolidated%20Balance%20Sheets) The consolidated balance sheets show a decrease in total assets from $1,266,884 thousand at December 31, 2023, to $1,231,675 thousand at March 31, 2024, primarily driven by reduced cash and commodity derivative assets Consolidated Balance Sheet Highlights (in thousands) | Metric | March 31, 2024 | December 31, 2023 | | :----- | :------------- | :---------------- | | Total Current Assets | $146,165 | $193,127 | | Total Assets | $1,231,675 | $1,266,884 | | Total Current Liabilities | $27,380 | $25,836 | | Total Liabilities | $55,873 | $49,539 | | Mezzanine Equity (Preferred Units) | $300,478 | $299,137 | | Total Equity | $875,324 | $918,208 | - Cash and cash equivalents decreased from **$70,282 thousand** at December 31, 2023, to **$40,456 thousand** at March 31, 2024[120](index=120&type=chunk) - Commodity derivative assets decreased by **$7,532 thousand**, while commodity derivative liabilities increased by **$17,400 thousand** (current and long-term combined)[120](index=120&type=chunk) [Consolidated Statements of Operations](index=4&type=section&id=Consolidated%20Statements%20of%20Operations) For the three months ended March 31, 2024, total revenue significantly decreased by 39.6% year-over-year, primarily due to a loss on commodity derivative instruments compared to a gain in the prior year, and lower natural gas and NGL sales Consolidated Statements of Operations Highlights (in thousands, except per unit amounts) | Metric | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | Change | Change (%) | | :----- | :-------------------------------- | :-------------------------------- | :----- | :--------- | | Total Revenue | $105,493 | $174,578 | $(69,085) | (39.6)% | | Income (Loss) from Operations | $63,974 | $135,199 | $(71,225) | (52.7)% | | Net Income (Loss) | $63,927 | $134,443 | $(70,516) | (52.4)% | | Net Income (Loss) Attributable to Common Units | $56,560 | $129,193 | $(72,633) | (56.2)% | | Basic EPU | $0.27 | $0.62 | $(0.35) | (56.5)% | | Diluted EPU | $0.27 | $0.60 | $(0.33) | (55.0)% | - Revenue from contracts with customers decreased by **4.5%** to **$116,783 thousand**, driven by lower natural gas and NGL sales, partially offset by increased oil and condensate sales[181](index=181&type=chunk)[253](index=253&type=chunk) - The company recognized a loss of **$11,290 thousand** on commodity derivative instruments in Q1 2024, a significant shift from a gain of **$52,271 thousand** in Q1 2023[181](index=181&type=chunk)[253](index=253&type=chunk) [Consolidated Statements of Equity](index=5&type=section&id=Consolidated%20Statements%20of%20Equity) The consolidated statements of equity show a decrease in total partners' equity from $918,208 thousand at December 31, 2023, to $875,324 thousand at March 31, 2024, primarily due to distributions and repurchases, partially offset by net income Consolidated Statements of Equity Highlights (in thousands) | Metric | March 31, 2024 | December 31, 2023 | | :----- | :------------- | :---------------- | | Common Units Outstanding | 210,656 | 209,991 | | Partners' Equity | $875,324 | $918,208 | | Distributions to Common Unitholders | $(99,899) | N/A (period activity) | | Distributions on Series B Preferred Units | $(7,367) | N/A (period activity) | | Repurchases of Common Units | $(4,381) | N/A (period activity) | | Net Income (Loss) | $63,927 | N/A (period activity) | - Repurchases of common units amounted to **$4,381 thousand** for the three months ended March 31, 2024[123](index=123&type=chunk) [Consolidated Statements of Cash Flows](index=6&type=section&id=Consolidated%20Statements%20of%20Cash%20Flows) Cash flows from operating activities decreased by 23.8% year-over-year, primarily due to reduced natural gas and NGL sales from lower realized commodity prices, while investing activities saw a significant increase in cash used Consolidated Statements of Cash Flows Highlights (in thousands) | Metric | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | Change | Change (%) | | :----- | :-------------------------------- | :-------------------------------- | :----- | :--------- | | Net Cash Provided by Operating Activities | $104,460 | $137,155 | $(32,695) | (23.8)% | | Net Cash Used in Investing Activities | $(23,964) | $(1,954) | $(22,010) | (1126.4)% | | Net Cash Used in Financing Activities | $(110,322) | $(120,358) | $10,036 | (8.3)% | | Net Change in Cash and Cash Equivalents | $(29,826) | $14,843 | $(44,669) | (300.9)% | | Cash and Cash Equivalents – End of Period | $40,456 | $19,150 | $21,306 | 111.2% | - Acquisitions of oil and natural gas properties accounted for **$22,966 thousand** in cash used in investing activities in Q1 2024, compared to none in Q1 2023[125](index=125&type=chunk) - Distributions to common unitholders were **$99,899 thousand** in Q1 2024, slightly up from **$99,600 thousand** in Q1 2023[125](index=125&type=chunk) [Notes to Unaudited Consolidated Financial Statements](index=7&type=section&id=Notes%20to%20Unaudited%20Consolidated%20Financial%20Statements) This section provides detailed notes to the unaudited consolidated financial statements, clarifying the Partnership's operations as an owner of oil and natural gas mineral interests and detailing significant financial instruments and equity structures - The Partnership operates primarily as an owner of oil and natural gas mineral interests across 41 states, with assets being substantially non-cost-bearing[104](index=104&type=chunk)[187](index=187&type=chunk) - The financial statements are prepared in accordance with GAAP and SEC rules, and all intercompany balances and transactions have been eliminated[104](index=104&type=chunk)[128](index=128&type=chunk) [NOTE 1 - BUSINESS AND BASIS OF PRESENTATION](index=7&type=section&id=NOTE%201%20-%20BUSINESS%20AND%20BASIS%20OF%20PRESENTATION) Black Stone Minerals, L.P. (BSM) is a publicly traded Delaware limited partnership primarily owning non-cost-bearing oil and natural gas mineral and royalty interests in 41 U.S. states, operating as a single reportable segment - BSM's primary business involves owning oil and natural gas mineral and royalty interests across 41 states, which are largely non-cost-bearing[104](index=104&type=chunk)[187](index=187&type=chunk) - The Partnership operates in a single operating and reportable segment, with the CEO acting as the chief operating decision maker[106](index=106&type=chunk)[130](index=130&type=chunk) [NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES](index=8&type=section&id=NOTE%202%20-%20SUMMARY%20OF%20SIGNIFICANT%20ACCOUNTING%20POLICIES) This note states no significant changes in accounting policies during Q1 2024 and mentions a new FASB ASU 2023-07 on segment disclosures, which the Partnership does not plan to early adopt - No material changes to significant accounting policies or their application occurred during Q1 2024[131](index=131&type=chunk) - The Partnership does not plan to early adopt ASU 2023-07 (Improvements to Reportable Segments Disclosures) and expects no material impact on its financial statements[109](index=109&type=chunk) [NOTE 3 - OIL AND NATURAL GAS PROPERTIES](index=8&type=section&id=NOTE%203%20-%20OIL%20AND%20NATURAL%20GAS%20PROPERTIES) In Q1 2024, the Partnership acquired $23.0 million in unproved oil and natural gas properties, primarily in the Gulf Coast, and Aethon Energy exercised "time-out" provisions in December 2023 due to low natural gas prices - In Q1 2024, the Partnership acquired **$23.0 million** in unproved oil and natural gas properties, mainly in the Gulf Coast, funded by operating cash flows[133](index=133&type=chunk) - Aethon Energy exercised "time-out" provisions in December 2023 under Joint Exploration Agreements (JEAs) in East Texas, temporarily suspending drilling obligations for up to nine consecutive months due to low natural gas prices[1](index=1&type=chunk)[164](index=164&type=chunk) - The Partnership did not recognize any impairment of oil and natural gas properties for the three months ended March 31, 2024, or 2023[165](index=165&type=chunk) [NOTE 4 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS](index=10&type=section&id=NOTE%204%20-%20COMMODITY%20DERIVATIVE%20FINANCIAL%20INSTRUMENTS) The Partnership uses fixed-price swap contracts to mitigate commodity price risk, with changes in fair value recognized in net income, and had open derivative contracts for oil and natural gas for 2024 and 2025 as of March 31, 2024 - The Partnership uses fixed-price swap contracts to mitigate commodity price risk, with changes in fair value recognized in net income[166](index=166&type=chunk)[168](index=168&type=chunk) Open Oil Swap Contracts as of March 31, 2024 | Period | Volume (Bbl) | Weighted Average Price (Per Bbl) | Range Low (Per Bbl) | Range High (Per Bbl) | | :----- | :----------- | :------------------------------- | :------------------ | :------------------- | | 2024 First Quarter | 190,000 | $71.45 | $67.00 | $81.00 | | 2024 Second Quarter | 570,000 | $71.45 | $67.00 | $81.00 | | 2024 Third Quarter | 570,000 | $71.45 | $67.00 | $81.00 | | 2024 Fourth Quarter | 570,000 | $71.45 | $67.00 | $81.00 | | 2025 First Quarter | 555,000 | $71.22 | $70.02 | $73.15 | | 2025 Second Quarter | 555,000 | $71.22 | $70.02 | $73.15 | | 2025 Third Quarter | 555,000 | $71.22 | $70.02 | $73.15 | | 2025 Fourth Quarter | 555,000 | $71.22 | $70.02 | $73.15 | Open Natural Gas Swap Contracts as of March 31, 2024 | Period | Volume (MMBtu) | Weighted Average Price (Per MMBtu) | Range Low (Per MMBtu) | Range High (Per MMBtu) | | :----- | :------------- | :--------------------------------- | :-------------------- | :--------------------- | | 2024 Second Quarter | 10,465,000 | $3.55 | $3.00 | $3.76 | | 2024 Third Quarter | 10,580,000 | $3.55 | $3.00 | $3.76 | | 2024 Fourth Quarter | 10,580,000 | $3.55 | $3.00 | $3.76 | | 2025 First Quarter | 7,200,000 | $3.39 | $3.34 | $3.65 | | 2025 Second Quarter | 7,280,000 | $3.39 | $3.34 | $3.65 | | 2025 Third Quarter | 11,040,000 | $3.45 | $3.34 | $3.65 | | 2025 Fourth Quarter | 11,040,000 | $3.45 | $3.34 | $3.65 | [NOTE 5 - FAIR VALUE MEASUREMENTS](index=13&type=section&id=NOTE%205%20-%20FAIR%20VALUE%20MEASUREMENTS) The Partnership uses a three-level valuation hierarchy for fair value measurements, with commodity derivative instruments primarily categorized as Level 2 due to observable market inputs, and no significant changes in valuation techniques occurred in Q1 2024 - Fair value measurements are categorized into a three-level hierarchy based on input observability, with Level 2 inputs being observable for substantially the full term of the financial instrument[173](index=173&type=chunk) Fair Value Measurements (in thousands) | Category | March 31, 2024 | December 31, 2023 | | :------- | :------------- | :---------------- | | Commodity Derivative Instruments (Assets) | $30,888 | $38,645 | | Commodity Derivative Instruments (Liabilities) | $18,640 | $1,310 | - The fair value of commodity derivative instruments is estimated using the market approach with observable inputs, categorized as Level 2[152](index=152&type=chunk)[173](index=173&type=chunk) [NOTE 6 - CREDIT FACILITY](index=15&type=section&id=NOTE%206%20-%20CREDIT%20FACILITY) The Partnership maintains a senior secured revolving Credit Facility with a maximum credit amount of $1.0 billion, terminating on October 31, 2027, with the borrowing base reaffirmed at $580.0 million in April 2024 and no outstanding principal balance as of March 31, 2024 - The Credit Facility has a maximum credit amount of **$1.0 billion** and terminates on October 31, 2027[197](index=197&type=chunk) - The borrowing base was reaffirmed at **$580.0 million** in April 2024, and the Partnership maintained cash commitments at **$375.0 million**[197](index=197&type=chunk)[263](index=263&type=chunk) - As of March 31, 2024, there was no outstanding principal balance, and the Partnership was in compliance with all debt covenants[81](index=81&type=chunk)[82](index=82&type=chunk) [NOTE 7 - COMMITMENTS AND CONTINGENCIES](index=15&type=section&id=NOTE%207%20-%20COMMITMENTS%20AND%20CONTINGENCIES) The Partnership is subject to environmental regulations and routine litigation, but management believes existing legal actions and claims will not materially adversely affect its financial condition or operations - The Partnership is subject to various environmental regulations regarding air, land, and water quality[45](index=45&type=chunk) - Management believes current legal actions and claims will not materially adversely affect financial condition, cash flows, or results of operations[47](index=47&type=chunk)[48](index=48&type=chunk) - No significant provision for potential environmental remediation costs has been recorded[84](index=84&type=chunk) [NOTE 8 - INCENTIVE COMPENSATION](index=16&type=section&id=NOTE%208%20-%20INCENTIVE%20COMPENSATION) Total incentive compensation expense increased to $3,643 thousand for Q1 2024, including cash and equity-based compensation, with Aspirational Awards tied to a production target of 42 Mboe per day by Q4 2025, for which no expense was recognized as achievement was not yet probable Total Incentive Compensation Expense (in thousands) | Category | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | | :------- | :-------------------------------- | :-------------------------------- | | Cash—short and long-term incentive plans | $1,260 | $1,079 | | Equity-based compensation—restricted common units | $996 | $954 | | Equity-based compensation—restricted performance units | $738 | $633 | | Board of Directors incentive plan | $649 | $531 | | Total Incentive Compensation Expense | $3,643 | $3,197 | - Aspirational Awards, including performance cash and equity awards, are dependent on achieving an aspirational production target of at least **42 Mboe per day** by Q4 2025[63](index=63&type=chunk) - As of March 31, 2024, the performance condition for Aspirational Awards was not yet probable, and no related expense was recognized[63](index=63&type=chunk) [NOTE 9 - PREFERRED UNITS](index=16&type=section&id=NOTE%209%20-%20PREFERRED%20UNITS) The Partnership has 14,711,219 Series B cumulative convertible preferred units outstanding, issued in 2017 for $300.0 million, with a distribution rate adjusted to 9.8% on November 28, 2023, and classified as mezzanine equity due to redemption provisions - **14,711,219 Series B** cumulative convertible preferred units are outstanding, with a carrying value of **$300.5 million** as of March 31, 2024[49](index=49&type=chunk)[55](index=55&type=chunk) - The distribution rate for Series B preferred units was adjusted to **9.8%** on November 28, 2023, and readjusts every two years[22](index=22&type=chunk)[52](index=52&type=chunk)[87](index=87&type=chunk) - The Partnership has the option to redeem all or a portion of Series B preferred units at **$20.39 per unit** during a 90-day period starting on each readjustment date[22](index=22&type=chunk)[54](index=54&type=chunk) [NOTE 10 - EARNINGS PER UNIT](index=17&type=section&id=NOTE%2010%20-%20EARNINGS%20PER%20UNIT) The Partnership calculates earnings per unit (EPU) using the two-class method, with basic and diluted EPU both at $0.27 for Q1 2024, a significant decrease from the prior year due to reduced net income attributable to common unitholders Earnings Per Common Unit (in thousands, except per unit amounts) | Metric | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | | :----- | :-------------------------------- | :-------------------------------- | | Net Income (Loss) Attributable to Common Unitholders | $56,560 | $129,193 | | Basic EPU | $0.27 | $0.62 | | Diluted EPU | $0.27 | $0.60 | | Weighted Average Common Units Outstanding (Basic) | 210,654 | 209,941 | | Weighted Average Common Units Outstanding (Diluted) | 210,654 | 224,910 | - The decrease in EPU is primarily due to a significant reduction in net income attributable to common unitholders, from **$129,193 thousand** in Q1 2023 to **$56,560 thousand** in Q1 2024[70](index=70&type=chunk) - Series B cumulative convertible preferred units are assessed on an as-converted basis for diluted EPU, but their inclusion was anti-dilutive in Q1 2023[68](index=68&type=chunk)[70](index=70&type=chunk) [NOTE 11 - COMMON UNITS](index=18&type=section&id=NOTE%2011%20-%20COMMON%20UNITS) Common unitholders are entitled to distributions after preferred unitholders, with a $0.4750 per common unit distribution declared for Q1 2024, and a new $150.0 million unit repurchase program authorized, though no repurchases were made under it in Q1 2024 - Common unitholders receive distributions after Series B preferred unitholders, with a quarterly distribution of **$0.4750 per common unit** declared and paid for Q1 2024 and Q1 2023[73](index=73&type=chunk)[74](index=74&type=chunk) - A new **$150.0 million** unit repurchase program was authorized on October 30, 2023, but no repurchases were made under it in Q1 2024[75](index=75&type=chunk) - **286,761 common units** were repurchased in Q1 2024 at a weighted average price of **$15.28 per unit** to satisfy tax withholding obligations for incentive awards[86](index=86&type=chunk) [NOTE 12 - SUBSEQUENT EVENTS](index=19&type=section&id=NOTE%2012%20-%20SUBSEQUENT%20EVENTS) Subsequent to March 31, 2024, the Board approved a distribution of $0.375 per common unit for Q1 2024, payable on May 17, 2024, and the Partnership acquired mineral and royalty interests for $12.3 million in cash - On April 17, 2024, a distribution of **$0.375 per common unit** for Q1 2024 was approved, payable on May 17, 2024[76](index=76&type=chunk) - Subsequent to March 31, 2024, the Partnership acquired mineral and royalty interests for **$12.3 million** in cash, funded by operating activities[77](index=77&type=chunk) [Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations](index=20&type=section&id=Item%202.%20Management%27s%20Discussion%20and%20Analysis%20of%20Financial%20Condition%20and%20Results%20of%20Operations) This section provides a detailed discussion of the Partnership's financial condition, results of operations, and liquidity for the three months ended March 31, 2024, compared to the same period in 2023 - The discussion analyzes financial performance for Q1 2024 versus Q1 2023, covering revenue, operating expenses, and cash flow drivers[65](index=65&type=chunk)[79](index=79&type=chunk) - Key factors affecting the business include volatile oil and natural gas prices, drilling activity by operators, and the impact of derivative instruments[66](index=66&type=chunk)[190](index=190&type=chunk)[240](index=240&type=chunk) [Cautionary Note Regarding Forward-Looking Statements](index=20&type=section&id=Cautionary%20Note%20Regarding%20Forward-Looking%20Statements) This section highlights that the report contains forward-looking statements, which are not historical in nature and are subject to significant risks and uncertainties, advising readers not to place undue reliance on them - The report contains forward-looking statements identified by words like "believe," "expect," "anticipate," and "plan," which are subject to significant risks and uncertainties[66](index=66&type=chunk) - Important factors that could cause actual results to differ include volatility of oil and natural gas prices, production levels, general economic conditions, and regulatory initiatives[66](index=66&type=chunk)[80](index=80&type=chunk)[184](index=184&type=chunk)[185](index=185&type=chunk)[204](index=204&type=chunk) - Readers are cautioned not to place undue reliance on forward-looking statements, and the company undertakes no obligation to update or revise them[205](index=205&type=chunk) [Overview](index=21&type=section&id=Overview) The Partnership is one of the largest owners and managers of oil and natural gas mineral interests in the U.S., focusing on maximizing value through active management, leasing, and creative structuring to encourage drilling, while also exploring energy transition opportunities - The Partnership is a major owner and manager of oil and natural gas mineral interests in the U.S., aiming to maximize value through active management and lease structuring[206](index=206&type=chunk) - Its business model relies on a large, diversified asset base of long-lived, non-cost-bearing mineral and royalty interests to provide stable production and cash flow for distributions[206](index=206&type=chunk) - The company is exploring energy transition opportunities, such as renewable energy and carbon sequestration[206](index=206&type=chunk) [Recent Developments](index=21&type=section&id=Recent%20Developments) Recent developments include significant Shelby Trough development by Aethon Energy under Joint Exploration Agreements (JEAs) in San Augustine and Angelina counties, which outline Aethon's drilling obligations and BSM's core mineral positions - Shelby Trough development is significantly driven by Aethon Energy under Joint Exploration Agreements (JEAs) in San Augustine and Angelina counties[207](index=207&type=chunk) - JEAs define Aethon's development obligations and BSM's rights related to core mineral positions[207](index=207&type=chunk) [Shelby Trough Development Update](index=21&type=section&id=Shelby%20Trough%20Development%20Update) In April 2024, Aethon began curtailing production volumes on a small number of producing wells, expecting a temporary decrease of approximately 800 Boe/d, and plans to delay initial production of an additional 10 wells until the second half of the year - Aethon began curtailing production volumes in April 2024, expecting a temporary decrease of approximately **800 Boe/d**[188](index=188&type=chunk) - Aethon intends to delay initial production of **10 wells** until H2 2024, anticipating improved natural gas prices[208](index=208&type=chunk) [Aethon Time-Out](index=21&type=section&id=Aethon%20Time-Out) In December 2023, Aethon exercised "time-out" provisions under its JEAs in East Texas, temporarily suspending drilling obligations for up to nine consecutive months due to low natural gas prices, marking the first time these provisions have been invoked - Aethon exercised "time-out" provisions in December 2023 under JEAs in East Texas, allowing temporary suspension of drilling obligations[1](index=1&type=chunk)[164](index=164&type=chunk) - The suspension can last up to **nine consecutive months** and a maximum of **18 total months** in any 48-month period, triggered by natural gas prices falling below specified thresholds[1](index=1&type=chunk)[164](index=164&type=chunk) - This is the first time Aethon has invoked these time-out provisions[1](index=1&type=chunk)[164](index=164&type=chunk) [Austin Chalk Update](index=22&type=section&id=Austin%20Chalk%20Update) The Partnership has agreements with multiple operators to drill wells in the Austin Chalk area of East Texas, where modern completion technology has improved production rates and increased reserves, with 30 wells currently producing - The Partnership has agreements with operators for drilling in the Austin Chalk area of East Texas[189](index=189&type=chunk) - Modern completion technology in the Brookeland Field has demonstrated potential for improved production rates and increased reserves[189](index=189&type=chunk) - **30 wells** with modern completions are currently producing in the Austin Chalk field[189](index=189&type=chunk) [Business Environment](index=22&type=section&id=Business%20Environment) The business environment is characterized by volatile oil and natural gas prices, with oil prices increasing due to geopolitical risks and OPEC+ cuts, while natural gas prices decreased significantly due to a large storage surplus - Oil prices increased due to heightened geopolitical risks and OPEC+ voluntary production cuts[240](index=240&type=chunk) - Natural gas prices decreased significantly due to a large surplus of storage inventory, resulting from a mild winter and below-average consumption[240](index=240&type=chunk) [Commodity Prices and Demand](index=22&type=section&id=Commodity%20Prices%20and%20Demand) Oil prices increased in Q1 2024 due to geopolitical risks and OPEC+ production cuts, while natural gas prices significantly decreased due to a large storage surplus, with the company using derivative instruments to mitigate volatility Benchmark Commodity Prices | Benchmark Price | 2024 First Quarter | 2023 First Quarter | | :-------------- | :----------------- | :----------------- | | WTI spot oil price ($/Bbl) | $83.96 | $75.68 | | Henry Hub spot natural gas ($/MMBtu) | $1.54 | $2.10 | - Oil prices increased due to geopolitical risks and OPEC+ production cuts, while natural gas prices decreased due to a storage surplus[240](index=240&type=chunk) - The company uses derivative instruments to partially mitigate commodity price volatility, but revenues and operating results are significantly dependent on prevailing prices[190](index=190&type=chunk)[240](index=240&type=chunk) [Rig Count](index=22&type=section&id=Rig%20Count) The U.S. rotary rig count decreased in Q1 2024 compared to Q1 2023, with declines in both oil and natural gas rigs, which the Partnership monitors to identify drilling activity on its acreage U.S. Rotary Rig Count | Category | 2024 First Quarter | 2023 First Quarter | | :------- | :----------------- | :----------------- | | Oil | 506 | 592 | | Natural gas | 112 | 160 | | Other | 3 | 3 | | Total | 621 | 755 | - Total U.S. rotary rig count decreased from **755** in Q1 2023 to **621** in Q1 2024, with declines in both oil and natural gas rigs[241](index=241&type=chunk) - The Partnership monitors rig counts to track drilling activity on its acreage, which is dependent on exploration and production companies[191](index=191&type=chunk) [Natural Gas Storage](index=23&type=section&id=Natural%20Gas%20Storage) Natural gas storage levels fluctuate seasonally, typically increasing from April to October, with the EIA forecasting inventories to reach 4.1 Tcf by October 2024, indicating a significant surplus that influences prices - Natural gas storage levels typically increase in warmer months (April-October) and decline in colder months (November-March) due to seasonal demand fluctuations[212](index=212&type=chunk) - The EIA forecasts natural gas inventories to reach **4.1 Tcf** by October 2024, **10% higher** than the five-year average, indicating a surplus[212](index=212&type=chunk) - Natural gas prices are significantly influenced by storage levels, which the Partnership monitors regularly[242](index=242&type=chunk) [Natural Gas Exports](index=23&type=section&id=Natural%20Gas%20Exports) The EIA projects a 2% increase in natural gas exports, both by pipeline and as LNG, in 2024, with continued growth expected into 2025 as new LNG export projects become operational and pipeline exports to Mexico increase - EIA forecasts a **2% increase** in natural gas exports (pipeline and LNG) to an average of **12.2 Bcf per day** in 2024[213](index=213&type=chunk) - LNG exports are expected to increase in 2025 due to three new LNG export projects starting operations[6](index=6&type=chunk) - Natural gas exports by pipeline to Mexico are also expected to grow[6](index=6&type=chunk) [How We Evaluate Our Operations](index=24&type=section&id=How%20We%20Evaluate%20Our%20Operations) The Partnership evaluates its operations by monitoring and analyzing production volumes from its diverse asset base, comparing projected to actual volumes, and assessing performance based on commodity prices and derivative instruments - The Partnership monitors and analyzes production volumes from its asset base and compares them to projections to assess performance[245](index=245&type=chunk) - Performance is evaluated based on commodity prices (WTI for oil, Henry Hub for natural gas), considering quality and location differentials[214](index=214&type=chunk)[215](index=215&type=chunk)[246](index=246&type=chunk) [Volumes of Oil and Natural Gas Produced](index=24&type=section&id=Volumes%20of%20Oil%20and%20Natural%20Gas%20Produced) The Partnership tracks and assesses its performance by monitoring and analyzing production volumes from various basins and plays, regularly comparing projected volumes to actual reported volumes and investigating unexpected variances - The Partnership monitors and analyzes production volumes from its extensive asset base to track and assess performance[245](index=245&type=chunk) - Projected volumes are regularly compared to actual reported volumes, and unexpected variances are investigated[245](index=245&type=chunk) [Commodity Prices](index=24&type=section&id=Commodity%20Prices) The majority of the Partnership's oil production is sold at prevailing market prices, primarily benchmarked against West Texas Intermediate (WTI), while natural gas is benchmarked against Henry Hub, with both affected by quality and location differentials - Oil production is primarily priced at prevailing market prices, benchmarked against WTI, with quality and location differentials affecting the final realized price[214](index=214&type=chunk)[246](index=246&type=chunk) - Natural gas is benchmarked against Henry Hub, with realized prices differing due to quality and location differentials[215](index=215&type=chunk)[246](index=246&type=chunk) [Factors Affecting the Sales Price of Oil and Natural Gas](index=24&type=section&id=Factors%20Affecting%20the%20Sales%20Price%20of%20Oil%20and%20Natural%20Gas) The sales price of oil is affected by its chemical composition (API gravity, impurities) relative to WTI, while natural gas prices are influenced by heating value and impurity concentration, with location differentials also playing a role due to transportation costs and local supply/demand - Oil quality differentials are influenced by density (API gravity) and impurities (sulfur) relative to WTI[9](index=9&type=chunk) - Natural gas quality differentials depend on Btu value (higher for ethane/heavier hydrocarbons) and impurity concentration (lower price for higher impurities)[10](index=10&type=chunk) - Location differentials for both oil and natural gas result from transportation costs and regional supply/demand dynamics[247](index=247&type=chunk)[248](index=248&type=chunk) [Hedging](index=25&type=section&id=Hedging) The Partnership uses commodity derivative financial instruments, such as fixed-price swaps and costless collars, to mitigate the impact of price fluctuations on future revenue, having hedged significant percentages of available oil and natural gas volumes for 2024 and 2025 - The Partnership uses commodity derivative instruments (fixed-price swaps, costless collars) to mitigate price volatility and is not for speculative purposes[12](index=12&type=chunk)[13](index=13&type=chunk)[249](index=249&type=chunk) - As of March 31, 2024, the Partnership had hedged **72%** of 2024 and **71%** of 2025 available oil/condensate volumes[218](index=218&type=chunk) - As of March 31, 2024, the Partnership had hedged **69%** of 2024 and **60%** of 2025 available natural gas volumes[218](index=218&type=chunk) [Non-GAAP Financial Measures](index=25&type=section&id=Non-GAAP%20Financial%20Measures) Adjusted EBITDA and Distributable cash flow are non-GAAP financial measures used by management and external users to assess financial performance and ability to sustain distributions, with specific adjustments from net income (loss) - Adjusted EBITDA and Distributable cash flow are non-GAAP measures used to assess financial performance and ability to sustain distributions[219](index=219&type=chunk) - Adjusted EBITDA is net income (loss) adjusted for interest, taxes, DDA, impairment, ARO accretion, unrealized derivative gains/losses, non-cash equity compensation, and asset sales[219](index=219&type=chunk) - Distributable cash flow is Adjusted EBITDA further adjusted for non-cash operating activities, cash interest, preferred unit distributions, and restructuring charges[219](index=219&type=chunk) Adjusted EBITDA and Distributable Cash Flow (in thousands) | Metric | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | | :----- | :-------------------------------- | :-------------------------------- | | Net Income (Loss) | $63,927 | $134,443 | | Unrealized (gain) loss on commodity derivative instruments | $25,087 | $(38,986) | | Adjusted EBITDA | $104,117 | $109,928 | | Distributable Cash Flow | $96,388 | $104,114 | [Results of Operations](index=27&type=section&id=Results%20of%20Operations) Total revenue for Q1 2024 decreased by 39.6% year-over-year, primarily due to a loss on commodity derivative instruments and lower natural gas and NGL sales, while operating expenses increased slightly due to higher production costs and general and administrative expenses Key Financial Results (Three Months Ended March 31) | Metric | 2024 (in thousands) | 2023 (in thousands) | Change (%) | | :----- | :------------------ | :------------------ | :--------- | | Total Revenue | $105,493 | $174,578 | (39.6)% | | Income (Loss) from Operations | $63,974 | $135,199 | (52.7)% | | Total Operating Expense | $41,519 | $39,379 | 5.4% | - The significant decrease in total revenue was driven by a **$63.6 million** swing from a gain to a loss on commodity derivative instruments[253](index=253&type=chunk) [Revenue](index=27&type=section&id=Revenue) Oil and condensate sales increased by 16.9% in Q1 2024, while natural gas and NGL sales decreased by 26.8% due to lower prices, and a significant shift from a $52.3 million gain to an $11.3 million loss on commodity derivative instruments led to a substantial overall revenue decline Revenue Breakdown (Three Months Ended March 31, in thousands) | Revenue Source | 2024 | 2023 | Change | Change (%) | | :------------- | :--- | :--- | :----- | :--------- | | Oil and condensate sales | $71,224 | $60,909 | $10,315 | 16.9% | | Natural gas and NGL sales | $42,011 | $57,423 | $(15,412) | (26.8)% | | Lease bonus and other income | $3,548 | $3,975 | $(427) | (10.7)% | | Gain (loss) on commodity derivative instruments | $(11,290) | $52,271 | $(63,561) | (121.6)% | | Total Revenue | $105,493 | $174,578 | $(69,085) | (39.6)% | - Oil and condensate production volumes increased, driven by higher mineral and royalty production in the Permian Basin[223](index=223&type=chunk) - Unrealized losses on commodity contracts in Q1 2024 were primarily due to changes in forward oil price curves, while Q1 2023 gains were from natural gas curves[224](index=224&type=chunk) [Operating Expenses](index=28&type=section&id=Operating%20Expenses) Total operating expenses increased by 5.4% in Q1 2024, driven by higher production costs and general and administrative expenses, partially offset by decreased lease operating expense Operating Expenses (Three Months Ended March 31, in thousands) | Expense Category | 2024 | 2023 | Change | Change (%) | | :--------------- | :--- | :--- | :----- | :--------- | | Lease operating expense | $2,432 | $2,668 | $(236) | (8.8)% | | Production costs and ad valorem taxes | $13,038 | $12,667 | $371 | 2.9% | | Depreciation, depletion, and amortization | $11,639 | $11,147 | $492 | 4.4% | | General and administrative | $14,090 | $12,648 | $1,442 | 11.4% | - Production costs and ad valorem taxes increased primarily due to severance tax refunds received in Q1 2023 with no similar activity in Q1 2024[19](index=19&type=chunk) - General and administrative expenses increased due to higher professional costs, including outside legal fees and consulting for internal projects[20](index=20&type=chunk) [Interest Expense](index=29&type=section&id=Interest%20Expense) Interest expense decreased by 22.7% in Q1 2024 compared to Q1 2023, primarily due to lower average outstanding borrowings under the Credit Facility, consisting mainly of commitment fees and amortization of debt issuance costs Interest Expense (Three Months Ended March 31, in thousands) | Metric | 2024 | 2023 | Change | Change (%) | | :----- | :--- | :--- | :----- | :--------- | | Interest expense | $629 | $814 | $(185) | (22.7)% | - The decrease in interest expense was driven by lower average outstanding borrowings under the Credit Facility[227](index=227&type=chunk) [Liquidity and Capital Resources](index=30&type=section&id=Liquidity%20and%20Capital%20Resources) The Partnership's primary liquidity sources are cash from operations and Credit Facility borrowings, used for unitholder distributions, debt reduction, and business investments, with operating cash flows decreasing and investing activities increasing cash usage in Q1 2024 - Primary liquidity sources are cash from operations and Credit Facility borrowings, used for distributions, debt reduction, and investments[22](index=22&type=chunk) - Operating cash flows decreased in Q1 2024 due to reduced natural gas and NGL sales from lower commodity prices[229](index=229&type=chunk) - Investing activities increased cash usage due to **$23.0 million** in oil and natural gas property acquisitions in Q1 2024[24](index=24&type=chunk)[231](index=231&type=chunk) [Overview](index=30&type=section&id=Overview) The Partnership plans to finance future acquisitions with cash from operations, Credit Facility borrowings, and future equity/debt issuances, with long-term working interest capital needs funded by farmout agreements and internally generated cash flows - Future acquisitions will be financed by cash from operations, Credit Facility borrowings, and future equity/debt issuances[228](index=228&type=chunk) - Working interest capital needs are primarily funded by farmout agreements and internally generated cash flows[228](index=228&type=chunk) - The Board's distribution policy aims for quarterly common unit distributions from operating cash, but there is no legal or contractual obligation[259](index=259&type=chunk) [Cash Flows](index=30&type=section&id=Cash%20Flows) Cash flows from operating activities decreased by $32.7 million in Q1 2024 due to lower natural gas and NGL sales, while net cash used in investing activities increased significantly by $22.0 million due to property acquisitions, and net cash used in financing activities decreased by $10.0 million Cash Flow Summary (Three Months Ended March 31, in thousands) | Activity | 2024 | 2023 | Change | | :------- | :--- | :--- | :----- | | Operating Activities | $104,460 | $137,155 | $(32,695) | | Investing Activities | $(23,964) | $(1,954) | $(22,010) | | Financing Activities | $(110,322) | $(120,358) | $10,036 | - The decrease in operating cash flows was mainly due to reduced natural gas and NGL sales from lower realized commodity prices[229](index=229&type=chunk) - The increase in cash used in investing activities was primarily due to **$22.97 million** in acquisitions of oil and natural gas properties in Q1 2024[24](index=24&type=chunk)[125](index=125&type=chunk) [Development Capital Expenditures](index=31&type=section&id=Development%20Capital%20Expenditures) The 2024 capital expenditure budget for non-operated working interests is approximately $2.3 million, net of farmout reimbursements, with $0.3 million invested in Q1 2024 primarily for workovers and recompletions, and an additional $0.7 million spent on acquiring leases - The 2024 capital expenditure budget for non-operated working interests is approximately **$2.3 million**, net of farmout reimbursements[262](index=262&type=chunk) - **$0.3 million** of the capital budget was invested in Q1 2024, primarily for workovers and recompletions on existing wells[262](index=262&type=chunk) - **$0.7 million** was spent on acquiring leases around drilling programs through March 31, 2024[262](index=262&type=chunk) [Acquisitions](index=31&type=section&id=Acquisitions) In Q1 2024, the Partnership acquired $23.0 million in unproved oil and natural gas properties, primarily in the Gulf Coast, funded by operating activities, as part of its ongoing commercial strategy for targeted mineral and royalty acquisitions - In Q1 2024, the Partnership acquired **$23.0 million** in unproved oil and natural gas properties, primarily in the Gulf Coast[231](index=231&type=chunk) - These acquisitions were funded with cash from operating activities[231](index=231&type=chunk) - The commercial strategy includes ongoing targeted mineral and royalty acquisitions to complement existing positions[231](index=231&type=chunk) [Credit Facility](index=31&type=section&id=Credit%20Facility) The Partnership's senior secured revolving Credit Facility has a maximum credit amount of $1.0 billion and matures on October 31, 2027, with the borrowing base reaffirmed at $580.0 million in April 2024 and cash commitments maintained at $375.0 million - The Credit Facility has a maximum credit amount of **$1.0 billion** and terminates on October 31, 2027[263](index=263&type=chunk) - The borrowing base was reaffirmed at **$580.0 million** in April 2024, with cash commitments maintained at **$375.0 million**[263](index=263&type=chunk) - The next semi-annual redetermination of the borrowing base is scheduled for October 2024[263](index=263&type=chunk) [Contractual Obligations](index=31&type=section&id=Contractual%20Obligations) As of March 31, 2024, there have been no material changes to the Partnership's contractual obligations previously disclosed in its 2023 Annual Report on Form 10-K - No material changes to contractual obligations were reported as of March 31, 2024, compared to the 2023 Annual Report on Form 10-K[27](index=27&type=chunk)[276](index=276&type=chunk) [Critical Accounting Policies and Related Estimates](index=31&type=section&id=Critical%20Accounting%20Policies%20and%20Related%20Estimates) As of March 31, 2024, there have been no significant changes to the Partnership's critical accounting policies and related estimates previously disclosed in its 2023 Annual Report on Form 10-K - No significant changes to critical accounting policies and related estimates were reported as of March 31, 2024[44](index=44&type=chunk)[264](index=264&type=chunk) [Item 3. Quantitative and Qualitative Disclosures about Market Risk](index=31&type=section&id=Item%203.%20Quantitative%20and%20Qualitative%20Disclosures%20about%20Market%20Risk) This section details the Partnership's exposure to market risks, primarily commodity price risk for oil, natural gas, and NGLs, and interest rate risk on its indebtedness, while also addressing counterparty and customer credit risk - The Partnership's major market risk exposure is the pricing of oil, natural gas, and NGLs, which are historically volatile[28](index=28&type=chunk)[277](index=277&type=chunk) - Derivative financial instruments are used to reduce exposure to commodity price volatility[28](index=28&type=chunk)[277](index=277&type=chunk) - The Partnership also has exposure to changes in interest rates on its indebtedness and counterparty credit risk[29](index=29&type=chunk)[30](index=30&type=chunk)[279](index=279&type=chunk) [Commodity Price Risk](index=31&type=section&id=Commodity%20Price%20Risk) The Partnership's primary market risk is the volatile pricing of oil, natural gas, and NGLs, which it mitigates using commodity derivative financial instruments, and a hypothetical 10% discount to SEC commodity pricing would reduce proved reserve volumes by approximately 2.2% - The Partnership's major market risk is the volatile pricing of oil, natural gas, and NGLs, driven by global and U.S. market dynamics[28](index=28&type=chunk)[277](index=277&type=chunk) - Commodity derivative financial instruments (fixed-price swaps) are used to reduce exposure to price volatility, settling monthly based on NYMEX benchmarks[28](index=28&type=chunk)[217](index=217&type=chunk)[234](index=234&type=chunk) - A hypothetical **10% discount** to SEC commodity pricing would reduce proved reserve volumes by approximately **2.2%**[278](index=278&type=chunk) [Counterparty and Customer Credit Risk](index=32&type=section&id=Counterparty%20and%20Customer%20Credit%20Risk) The Partnership faces credit risk from receivables generated by its operators' production activities, but believes its credit risk associated with operators and customers is acceptable, and evaluates the credit standing of its seven derivative contract counterparties, all rated Baa2 or better by Moody's - Principal credit risk arises from receivables generated by operators' production activities[29](index=29&type=chunk)[235](index=235&type=chunk) - The Partnership believes its credit risk with operators and customers is acceptable[235](index=235&type=chunk) - All seven derivative contract counterparties are rated **Baa2 or better** by Moody's[143](index=143&type=chunk)[265](index=265&type=chunk) [Interest Rate Risk](index=32&type=section&id=Interest%20Rate%20Risk) The Partnership has exposure to changes in interest rates on its indebtedness, with weighted average outstanding borrowings of $0.3 million at a 7.92% weighted average interest rate for Q1 2024, and a 1% increase would have a de minimis impact on interest expense - The Partnership is exposed to interest rate risk on its indebtedness[30](index=30&type=chunk)[279](index=279&type=chunk) - For Q1 2024, weighted average outstanding borrowings were **$0.3 million** at a **7.92%** weighted average interest rate[30](index=30&type=chunk) - A **1% interest rate increase** would have a de minimis impact on interest expense for Q1 2024[30](index=30&type=chunk) [Item 4. Controls and Procedures](index=32&type=section&id=Item%204.%20Controls%20and%20Procedures) This section confirms the effectiveness of the Partnership's disclosure controls and procedures and reports no material changes in internal control over financial reporting during Q1 2024 - Management concluded that disclosure controls and procedures were effective as of March 31, 2024, providing reasonable assurance[280](index=280&type=chunk) [Evaluation of Disclosure Controls and Procedures](index=32&type=section&id=Evaluation%20of%20Disclosure%20Controls%20and%20Procedures) As of March 31, 2024, management concluded that the Partnership's disclosure controls and procedures were effective in providing reasonable assurance that required information is accumulated, communicated, recorded, processed, summarized, and reported timely - Disclosure controls and procedures were evaluated and deemed effective as of March 31, 2024[280](index=280&type=chunk) - These controls are designed to ensure timely accumulation, communication, recording, processing, summarization, and reporting of required information[280](index=280&type=chunk) [Changes in Internal Control over Financial Reporting](index=32&type=section&id=Changes%20in%20Internal%20Control%20over%20Financial%20Reporting) There were no changes in the Partnership's internal control over financial reporting during the quarter ended March 31, 2024, that materially affected, or are reasonably likely to materially affect, its internal control over financial reporting - No material changes in internal control over financial reporting occurred during Q1 2024[31](index=31&type=chunk)[267](index=267&type=chunk) [PART II – OTHER INFORMATION](index=33&type=section&id=PART%20II%20%E2%80%93%20OTHER%20INFORMATION) [Item 1. Legal Proceedings](index=33&type=section&id=Item%201.%20Legal%20Proceedings) The Partnership is involved in routine litigation, disputes, or claims arising from its business activities, and management believes none of these will have a material adverse effect on its financial condition, cash flows, or results of operations - The Partnership is involved in routine litigation and claims in the ordinary course of business[48](index=48&type=chunk) - Management believes pending litigation will not have a material adverse effect on financial condition, cash flows, or results of operations[48](index=48&type=chunk) [Item 1A. Risk Factors](index=33&type=section&id=Item%201A.%20Risk%20Factors) This section directs readers to consider the risk factors outlined in the 2023 Annual Report on Form 10-K, stating no material changes except as updated in this report, and noting that additional unknown or currently immaterial risks could adversely affect the business - Readers should consider risk factors from the 2023 Annual Report on Form 10-K[268](index=268&type=chunk) - No material changes to risk factors were reported, except as updated in this quarterly report[268](index=268&type=chunk) - Additional unknown or immaterial risks could adversely affect the business[268](index=268&type=chunk) [Item 2. Unregistered Sales of Equity Securities and Use of Proceeds](index=33&type=section&id=Item%202.%20Unregistered%20Sales%20of%20Equity%20Securities%20and%20Use%20of%20Proceeds) This section reports no unregistered sales of equity securities and details the common unit repurchase program, which authorized up to $150.0 million in repurchases, though no repurchases were made under this program in Q1 2024 - No unregistered sales of equity securities occurred[33](index=33&type=chunk) [Recent Sales of Unregistered Securities](index=33&type=section&id=Recent%20Sales%20of%20Unregistered%20Securities) The Partnership reported no unregistered sales of equity securities during the period - No unregistered sales of equity securities were reported[33](index=33&type=chunk) [Purchases of Equity Securities by the Issuer and Affiliated Purchasers](index=33&type=section&id=Purchases%20of%20Equity%20Securities%20by%20the%20Issuer%20and%20Affiliated%20Purchasers) The Board authorized a $150.0 million common unit repurchase program on October 30, 2023, but no repurchases were made under this specific program in Q1 2024; instead, 286,761 common units were purchased to satisfy tax withholding obligations for incentive awards Common Units Purchased (Three Months Ended March 31, 2024) | Period | Total Number of Common Units Purchased | Average Price Paid Per Unit | Maximum Dollar Value Remaining | | :----- | :------------------------------------- | :-------------------------- | :----------------------------- | | January 1 - January 31, 2024 | 92,614 | $16.04 | $150,000,000 | | February 1 - February 29, 2024 | 193,914 | $14.91 | $150,000,000 | | March 1 - March 31, 2024 | 233 | $15.05 | $150,000,000 | | Total for Q1 2024 | 286,761 | $15.28 (weighted average) | $150,000,000 | - The **$150.0 million** unit repurchase program, authorized on October 30, 2023, allows discretionary repurchases but none were made under this specific program in Q1 2024[34](index=34&type=chunk)[75](index=75&type=chunk) - Common units were purchased to satisfy tax withholding obligations for vested long-term incentive equity awards[86](index=86&type=chunk)[269](index=269&type=chunk) [Item 5. Other Information](index=33&type=section&id=Item%205.%20Other%20Information) This section states that during the three months ended March 31, 2024, none of the Partnership's directors or executive officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" - No directors or executive officers adopted or terminated Rule 10b5-1 or non-Rule 10b5-1 trading arrangements during Q1 2024[53](index=53&type=chunk) [Item 6. Exhibits](index=34&type=section&id=Item%206.%20Exhibits) This section lists the exhibits filed with the Quarterly Report on Form 10-Q, including organizational documents, registration rights agreements, long-term incentive award forms, certifications from the CEO and CFO, and Inline XBRL documents - Exhibits include organizational documents (Certificate of Limited Partnership, Amended Partnership Agreement), Registration Rights Agreement, and forms for Long-Term Incentive (LTI) Award Grant Notices[36](index=36&type=chunk) - Certifications from the CEO and CFO pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are included[36](index=36&type=chunk) - Inline XBRL documents (Instance, Schema, Calculation, Label, Presentation, Definition Linkbase Documents) are also filed[36](index=36&type=chunk) [SIGNATURES](index=35&type=section&id=SIGNATURES) [SIGNATURES](index=35&type=section&id=SIGNATURES) The report is duly signed on behalf of Black Stone Minerals, L.P. by its general partner, Black Stone Minerals GP, L.L.C., with signatures from Thomas L. Carter, Jr. (President, CEO, and Chairman) and Evan M. Kiefer (Senior Vice President, CFO, and Treasurer), dated May 7, 2024 - The report is signed by Thomas L. Carter, Jr., President, CEO, and Chairman (Principal Executive Officer)[38](index=38&type=chunk) - The report is also signed by Evan M. Kiefer, Senior Vice President, CFO, and Treasurer (Principal Financial Officer)[38](index=38&type=chunk) - The signing date is May 7, 2024[57](index=57&type=chunk)[273](index=273&type=chunk)

Financial Data and Key Metrics Changes - The company reported a net income of $63.9 million and adjusted EBITDA of $104.1 million for Q1 2024 [10][22] - Total production volumes decreased by 2% from the previous quarter to 40.3 MBoe/d, with royalty volumes at 38.9 MBoe/d [10][22] - Distributable cash flow for the quarter was $96.4 million, representing a coverage ratio of 1.22x [24] Business Line Data and Key Metrics Changes - Oil volumes decreased in the Midland and Delaware Basins, but there was an increase in the Bakken area [10] - Natural gas volumes increased in several regions, including Fayetteville and Gulf Coast, despite ongoing challenges [11] Market Data and Key Metrics Changes - The company lowered its 2024 production guidance by approximately 4% to a range of 38,500 to 40,500 Boe per day due to production curtailments and delays [27] - The average price at Henry Hub for Q1 was $2.24 per MMbtu, while the company's 2024 natural gas hedge position is at approximately $3.55 per MMbtu [28] Company Strategy and Development Direction - The company aims to grow distributions back to previous high levels by 2026 through production growth and capitalizing on LNG demand [19] - A focus on organic initiatives and targeted grassroots acquisition programs has been emphasized to supplement existing assets [18] Management's Comments on Operating Environment and Future Outlook - Management remains optimistic about the long-term natural gas outlook despite current commodity price challenges [20] - The company does not anticipate a material impact on volumes in Haynesville through 2024 and 2025, even with operators slowing down [15] Other Important Information - The company has acquired approximately $50 million of non-producing mineral and royalty interests since September 2023 [25] - The borrowing base for the revolving credit facility was reaffirmed at $580 million, with commitments held at $375 million [26] Q&A Session Summary Question: 2024 guidance and production cadence - Management indicated that production curtailments are expected through the second quarter, with a potential recovery in the third quarter as prices improve [33] Question: Acquisition activity and competitive environment - The company is focusing on less expensive mineral acquisitions in areas contiguous to existing positions, expecting higher returns compared to more competitive regions like the Permian [34][35] Question: Future distribution levels - Management expressed a desire to maintain the current distribution level of $0.375 per unit, but future coverage will depend on the continuation of low gas prices [39][40]

As previously announced, the Board approved a cash distribution of $0.375 for each common unit attributable to the first quarter of 2024. The quarterly distribution coverage ratio attributable to the first quarter of 2024 was approximately 1.22x. The distribution will be paid on May 17, 2024 to unitholders of record as of the close of business on May 10, 2024. The Company reported a loss on commodity derivative instruments of $11.3 million for the first quarter of 2024, composed of a $13.8 million gain from ...

With the geopolitical winds churning, the concept of cheap energy stocks has become even more critical. Basically, the window of opportunity may be fading.One major problem of course is the situation in the Middle East. While tensions have cooled relative to Iran and Israel launching missiles against each other, there’s always a chance of a miscalculation. Not too far away, Russia’s invasion of Ukraine shows no sign of abatement. With Russia also owning vast energy resources, a global supply chain disruptio ...

Phra yor Jitonnom Black Stone Minerals, L.P. (NYSE:BSM) provided 2024 guidance including expectations of approximately 41,000 BOEPD (24% oil) in average production. This was higher than what I had previously expected for Black Stone in terms of 2024 production, although the oil cut is lower than what I had modeled in December 2023. Based on guidance, Black Stone is projected to generate $391 million in distributable cash flow (or $1.86 per common unit) during 2024 at current strip prices. This results i ...

Financial Data and Key Metrics Changes - The company reported adjusted EBITDA of $125.5 million for Q4 2023, totaling $474.7 million for the full year [2] - Total production volumes for Q4 were 41,400 BOE per day, exceeding the upper end of the full year guidance by 2% [2] - Royalty volumes for the quarter were 38,900 BOE, with a noted decline in oil volumes in Bakken and Eagle Ford, offset by increases in Mid/Del [2][3] - The distribution for the last quarter was maintained at $0.475 per unit, representing a 1.19x coverage for the quarter [3] Business Line Data and Key Metrics Changes - The Permian position is expected to remain stable, while a decline is anticipated in the Bakken due to maturation [5] - A modest decrease in natural gas volumes was observed, particularly in Louisiana Haynesville, aligning with industry trends [19] - Lease bonus and other income for Q4 was $3.8 million, with a total of $12.5 million for the full year [41] Market Data and Key Metrics Changes - Henry Hub averaged $2.74 per MMBtu in 2023, with natural gas hedges providing over $80 million in realized gains [6] - The company expects natural gas prices to average $3.55 per MMBtu in 2024, with oil hedges above $71 per barrel [6] Company Strategy and Development Direction - The company plans to continue targeted mineral and royalty acquisitions to support long-term growth, having acquired $15 million in non-producing minerals in 2023 [39] - The strategy includes expanding growth into buying minerals in the Gulf Coast, with expectations to significantly increase acquisition amounts [30] Management's Comments on Operating Environment and Future Outlook - Management acknowledged a general slowdown in drilling due to lower natural gas prices, but remains optimistic about long-term gas exposure and unit price [7][20] - The company is adjusting its commercial efforts to be proactive in a down cycle, focusing on strategic initiatives for 2024 and beyond [39][25] Other Important Information - The preferred units' rate reset in November 2023 to 9.8%, and a $150 million unit repurchase program was initiated [7] - The company maintains a zero debt balance and has $103 million in cash ahead of the fourth quarter distribution [42] Q&A Session Summary Question: Expansion of growth strategy into Gulf Coast - Management indicated that the $15 million acquisition is small compared to peers, but they expect to expand this significantly [30] Question: Thoughts on repurchase program versus maintaining distribution - Management expressed a preference for repurchasing shares at current prices rather than maintaining a distribution that exceeds cash flow coverage [31][47] Question: 2024 guidance and Aethon DUCs conversion to production - Management expects a lumpy production increase with some wells coming online in the first half of the year and more towards the end [51] Question: Impact of E&P consolidation on business - Management believes operator consolidation could be beneficial, leading to efficiencies that may positively impact mineral owners [57]