Black Stone Minerals(US:BSM)2026-02-24 21:59Drilling Commitments and Production - Aethon expects to drill a total of 14 wells in the current program year, with 6 wells already spud and 5 wells from the previous year expected to be turned to sales in early 2026[90]. - Revenant's drilling commitments include a total of 175,000 gross lateral feet by 2030 and beyond, with a minimum of 105,000 feet in Program Year 5[94]. - Caturus has minimum net lateral-foot commitments escalating to 25,200 feet by 2031 and beyond, starting with 6,000 feet in 2026[96]. - The company has entered into multiple Joint Exploration Agreements (JEAs) with Aethon, Revenant, and Caturus, focusing on expanding drilling commitments and development rights[89][91][95]. - The company’s total gross well count as of December 31, 2025, was 4,610 for Bakken/Three Forks and 1,588 for Haynesville/Bossier[3]. Production and Reserves - Average daily production for mineral and royalty interests in 2025 was 33,256 Boe/d, a decrease from 36,577 Boe/d in 2024[101]. - The Bakken/Three Forks, Haynesville/Bossier, and Permian plays accounted for 73% of the company's aggregate production for the year ended December 31, 2025[102]. - As of December 31, 2025, estimated proved reserves include 16,636 MBbls of oil and 229,257 MMcf of natural gas, totaling 54,845 MBoe[114]. - Estimated proved undeveloped reserves (PUDs) as of December 31, 2025, comprise 395 MBbls of oil and 37,625 MMcf of natural gas, or 6,666 MBoe[115]. - New PUD reserves totaling 5,064 MBoe were added during the year ended December 31, 2025, primarily from development activities in the Haynesville/Bossier play and the Permian Basin[116]. Production Metrics - The company’s average daily production for the Haynesville/Bossier resource play was 15,571 Boe/d in 2025, down from 18,476 Boe/d in 2024[3]. - The average daily production for the Bakken/Three Forks resource play was 3,074 Boe/d in 2025, compared to 3,282 Boe/d in 2024[3]. - Oil and condensate production decreased to 3,259 MBbls in 2025 from 3,606 MBbls in 2024, a decline of 9.6%[121]. - Natural gas production fell to 56,237 MMcf in 2025, down 10.5% from 62,984 MMcf in 2024[121]. - Average daily production decreased to 34.6 MBoe/d in 2025, compared to 38.5 MBoe/d in 2024, reflecting a 10.1% decline[121]. Financial Performance - Realized prices for oil and condensate dropped to $64.24 per Bbl in 2025, down 13.4% from $74.61 per Bbl in 2024[121]. - Unit cost per Boe for production costs and ad valorem taxes decreased to $3.09 in 2025 from $3.52 in 2024, a reduction of 12.2%[121]. - The percentage of proved developed reserves was 87.8% as of December 31, 2025, down from 94.6% in 2024[114]. - The company incurred $0.6 million in drilling, completing, and recompleting wells that were not classified as PUDs as of December 31, 2024[118]. Acreage and Ownership - The total acreage as of December 31, 2025, is 16,931,851 gross acres, with a mineral interest ownership average of 43.4%[99]. - The Gulf Coast region has a total of 8,049,498 gross acres, with a mineral interest ownership average of 51.7%[99]. - The Southwestern U.S. region has 2,773,819 gross acres, with a mineral interest ownership average of 25.4%[99]. - The Rocky Mountains region has 2,123,454 gross acres, with a mineral interest ownership average of 15.4%[99]. - Total acreage for mineral and royalty interests amounted to 20,326,612 acres as of December 31, 2025, with 2,635,046 acres developed[125]. Regulatory and Environmental Considerations - The company is subject to stringent environmental regulations that could materially affect production and operational costs[131]. - Colorado regulations require operators to phase in the use of recycled produced water for hydraulic fracturing, starting with a minimum of 2% in 2026 and potentially increasing to 35% by 2038[149]. - The company faces potential litigation risks from local governments alleging public nuisances related to climate change[144]. Workforce and Operations - The company had 122 full-time employees and 7 contractors as of December 31, 2025[161]. - The company has a hybrid work environment allowing employees to work outside the office on Mondays and Fridays[165]. - The principal office location is in Houston, Texas, consisting of 55,862 square feet of leased space[166]. Financial Instruments and Risk Management - The company utilizes commodity derivative financial instruments to mitigate the impact of fluctuations in oil and natural gas prices on revenues[390]. - The prices for oil, natural gas, and NGLs have been volatile, and this unpredictability is expected to continue in the future[390]. - A hypothetical $1 per barrel increase or decrease in the NYMEX WTI strip price would result in an increase or decrease of approximately $3.4 million in the fair value of oil derivative contracts[391]. - A hypothetical $0.10 per MMBtu increase or decrease in the NYMEX Henry Hub natural gas strip price would result in an increase or decrease of approximately $7.7 million in the fair value of natural gas derivative contracts[391]. - The credit risk associated with operators and customers is considered acceptable by the company[394]. Debt and Interest Rate Exposure - The company had $95.8 million weighted average outstanding borrowings under its Credit Facility, with a weighted-average interest rate of 7.03%[395]. - A 1% increase in the interest rate on the outstanding debt would result in an increase in interest expense of $1.0 million for the year ended December 31, 2025[395]. - The company does not currently have any interest rate hedges in place but may use derivative instruments to hedge exposure to variable interest rates in the future[395]. - The company evaluates the credit standing of counterparties to derivative contracts, including reviewing credit ratings and financial information[393]. - The inability of significant operators to meet obligations may adversely affect financial results, but the company believes the associated credit risk is manageable[394].