Black Stone Minerals, L.P. 10-Q

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.” Cautionary Note Regarding Forward-Looking Statements Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below: • our ability to execute our business strategies; • the volatility of realized oil and natural gas prices; • the level of production on our properties; • the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production; • our ability to replace our oil and natural gas reserves; • general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets; • competition in the oil and natural gas industry; • the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions; • the ability of our operators to obtain capital or financing needed for development and exploration operations; • title defects in the properties in which we invest; • the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel; • restrictions on the use of water for hydraulic fracturing; • the availability of pipeline capacity and transportation facilities; • the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals; • federal and state legislative and regulatory initiatives relating to hydraulic fracturing; • future operating results; 18 • 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 March 31, 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 A significant portion of Shelby Trough development in recent years has been performed by Aethon Energy (“Aethon”) under the two Joint Exploration Agreements (“JEAs”) between us and Aethon. The JEAs outline Aethon’s development obligations and other rights and obligations of each party related to our core mineral positions in San Augustine and Angelina counties in East Texas. In December 2023, we received notice that Aethon was exercising the “time-out” provisions under these JEAs. When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period. Aethon has not previously invoked the time-out provisions under the JEAs. We continue working closely with Aethon to finalize development plans going forward and assess the effect of the temporary suspension of drilling obligations, and we are analyzing the potential impacts to us on an ongoing basis. In April 2024, Aethon began curtailing production volumes on a small number of producing wells. This temporary decrease is expected to amount to approximately 800 Boe/d. Additionally, Aethon has indicated that it intends to curtail these 19 wells and delay the initial production of an additional 10 wells until the second half of the year, when natural gas prices are forecast to improve. Austin Chalk Update We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions. The results of the test program in the Brookeland Field demonstrated that modern completion technology has the potential to improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation. To date, 30 wells with modern completions are being produced in the field. Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us. Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts. Oil prices increased from the prior period ended March 31, 2023 as a result of heightened geopolitical risk related to the attacks targeting commercial ships transiting the Red Sea shipping channel and general elevated tensions around the region. In addition, the recent extension of OPEC+ voluntary production cuts add to upward price pressure at a time of the year when oil demand typically increases because of the spring and summer driving seasons in the Northern Hemisphere. Natural gas prices decreased from the prior period ended March 31, 2023 as a result of a large surplus of storage inventory. The United States started the winter heating season with a surplus and a mild winter led to below average consumption further increasing the surplus of storage inventory. Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine, 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 Prices 1 First Quarter First Quarter WTI spot oil price ($/Bbl) $ 83.96 $ 75.68 Henry Hub spot natural gas ($/MMBtu) 1.54 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 Count 1 First Quarter First Quarter Oil 506 592 Natural gas 112 160 Other 3 3 Total 621 755 1 Source: Baker Hughes Incorporated 20 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 EIA expects inventories will rise to 4.1 Tcf at the end of October 2024, which would be 10% higher than the five-year average. The following table shows natural gas storage volumes by region at the end of each quarter presented: 2024 2023 Region 1 First Quarter First Quarter East 363 335 Midwest 510 421 Mountain 162 80 Pacific 227 73 South Central 996 921 Total 2,258 1,830 1 Source: EIA Natural Gas Exports The EIA expects exports of natural gas, both by pipeline and as LNG, will increase in 2024. The EIA forecasts average exports of 12.2 Bcf per day for 2024, a 2% increase from 2023 levels. In 2025, the EIA expects LNG exports to increase because three of the five LNG export projects currently under construction are expected to start operations and ramp up to full production. The EIA also expects natural gas exports by pipeline to grow because of increased natural gas exports to Mexico. 21 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. 22 Hedging We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, 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 collars and swaps with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, 2024, we had hedged 72% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively. As of March 31, 2024, we had also hedged 69% and 60% 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. 23 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 March 31, 2024 2023 (in thousands) Net income (loss) $ 63,927 $ 134,443 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 11,639 11,147 Interest expense 629 814 Income tax expense (benefit) 135 147 Accretion of asset retirement obligations 317 245 Equity–based compensation 2,383 2,118 Unrealized (gain) loss on commodity derivative instruments 25,087 (38,986) Adjusted EBITDA 104,117 109,928 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (1) (5) Cash interest expense (361) (559) Preferred unit distributions (7,367) (5,250) Distributable cash flow $ 96,388 $ 104,114 24 Results of Operations Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023 The following table shows our production, revenue, and operating expenses for the periods presented: Three Months Ended March 31, 2024 2023 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 923 793 130 16.4 % Natural gas (MMcf) 1 16,470 16,452 18 0.1 % Equivalents (MBoe) 3,668 3,535 133 3.8 % Equivalents/day (MBoe) 40.3 39.3 1.0 2.5 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 77.17 $ 76.81 $ 0.36 0.5 % Natural gas ($/Mcf) 1 2.55 3.49 (0.94) (26.9) % Equivalents ($/Boe) $ 30.87 $ 33.47 $ (2.60) (7.8) % Revenue: Oil and condensate sales $ 71,224 $ 60,909 $ 10,315 16.9 % Natural gas and natural gas liquids sales 1 42,011 57,423 (15,412) (26.8) % Lease bonus and other income 3,548 3,975 (427) (10.7) % Revenue from contracts with customers 116,783 122,307 (5,524) (4.5) % Gain (loss) on commodity derivative instruments (11,290) 52,271 (63,561) (121.6) % Total revenue $ 105,493 $ 174,578 $ (69,085) (39.6) % Operating expenses: Lease operating expense $ 2,432 $ 2,668 $ (236) (8.8) % Production costs and ad valorem taxes 13,038 12,667 371 2.9 % Exploration expense 3 4 (1) (25.0) % Depreciation, depletion, and amortization 11,639 11,147 492 4.4 % General and administrative 14,090 12,648 1,442 11.4 % Other expense: Interest expense 629 814 (185) (22.7) % 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 March 31, 2024 decreased compared to the quarter ended March 31, 2023. The decrease in total revenue in the first quarter of 2024 is primarily due to a loss on our commodity derivative instruments compared to a gain in the corresponding prior period and a decrease in natural gas and NGL sales which was partially offset by an increase in oil and condensate sales. Oil and condensate sales. Oil and condensate sales increased for the quarter ended March 31, 2024 as compared to the corresponding period in 2023 primarily due to higher production volumes. The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 92% of total oil and condensate volumes for quarters ended March 31, 2024 and 2023, respectively. 25 Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended March 31, 2024 as compared to the corresponding prior period. The decrease was due to lower realized commodity prices between the comparative periods. Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the quarters ended March 31, 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 first quarter of 2024, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2023. For the three months ended March 31, 2024, we recognized $13.8 million of realized gains and $25.1 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.3 million of realized gains and $39.0 million of unrealized gains in the same period in 2023. The unrealized losses on our commodity contracts during the first quarter of 2024 were primarily driven by changes in the forward commodity price curves for oil and the unrealized gains in the same period in 2023 were driven by changes in the forward commodity price curves for natural gas. Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of 2024 was lower than the same period in 2023. Leasing activity in the Austin Chalk play and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas made up the majority of lease bonus and other income for the first quarter of 2024, while the majority of the first quarter 2023 activity came from leasing activity in the Haynesville/Bossier play and the Permian Basin. Operating Expenses Lease operating expense . Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 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 March 31, 2024, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2023, primarily due to severance tax refunds received in the first quarter of 2023 with no similar activity recorded in the first quarter of 2024. Exploration expense . Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for the quarter ended March 31, 2024 and the corresponding prior period of 2023 was minimal. 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 increased for the quarter ended March 31, 2024 as compared to the same period in 2023 due to higher production volumes. General and administrative . General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to higher professional costs related to outside legal fees, consulting costs for internal projects, and the timing of annual tax services performed. 26 Interest expense . Interest expense was lower in the first quarter of 2024 relative to the corresponding period in 2023, due to lower average outstanding borrowings under our Credit Facility. Interest expense for both periods primarily consisted of commitment fees and amortization of debt issuance costs. 27 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: Three Months Ended March 31, 2024 2023 Change (in thousands) Cash flows provided by operating activities $ 104,460 $ 137,155 $ (32,695) Cash flows provided by (used in) investing activities (23,964) (1,954) (22,010) Cash flows provided by (used in) financing activities (110,322) (120,358) 10,036 Operating Activities . Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities decreased for the three months ended March 31, 2024 as compared to the same period of 2023. The decrease was primarily due to reduced natural gas and NGL sales due to lower realized commodity prices in the three months ended March 31, 2024 compared to the same period of 2023. Investing Activities . Net cash used in investing activities in the three months ended March 31, 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 three months ended March 31, 2024 as compared to no acquisition activity in the corresponding prior period. Financing Activities . Cash flows used in financing activities decreased for the three months ended March 31, 2024 as compared to the same period of 2023. The decrease was primarily due to net repayments on our Credit Facility for the three months ended March 31, 2023 compared to no net repayments for the three months ended March 31, 2024. 28 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 $0.3 million has been invested in the three months ended March 31, 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 March 31, 2024, we have also spent $0.7 million acquiring leases in areas around our drilling programs. Acquisitions During the three months ended March 31, 2024, we acquired mineral and royalty interests that consisted of substantially all unproved oil and natural gas properties from various sellers for cash consideration of $23.0 million, including capitalized direct transaction costs. These acquisitions were primarily located in the Gulf Coast land region and were funded with cash from operating activities. 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. 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. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October 2024. We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets. As of March 31, 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 March 31, 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 March 31, 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.