Black Stone Minerals, L.P. 10-K

ITEM 7. 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 consolidated financial statements and notes thereto presented elsewhere in this Annual Report. 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 I, Item 1A. Risk Factors.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2023 and 2022. For the discussion of changes from 2022 to 2021 and other financial information related to 2021, refer to Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2022 Annual Report on Form 10-K, which was filed with the SEC on February 22, 2023. Overview As of December 31, 2023, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 68,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements. Recent Developments Shelby Trough Development Update In Angelina County, Texas, 24 wells are currently producing under our development agreement with Aethon, and another 20 wells are being drilled or completed. Under a separate development agreement with Aethon in San Augustine County, Texas, 13 wells are currently producing, and another four wells are either drilling or awaiting completion operations. In December 2023, we received notice that Aethon was exercising the “time-out” provisions under its joint exploration agreements with us in Angelina and San Augustine counties in East Texas. 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 agreements. The time-out provisions apply only to drilling obligations and associated development activity occurring after December 2023. Based on ongoing discussions with Aethon, we do not expect material changes for wells on which drilling operations had begun prior to the invocation of the time-out in December 2023. We continue working closely with Aethon to finalize development plans going forward and assess the effect of the temporary suspension of drilling obligations and any potential longer-term impacts. Austin Chalk Update We own a large mineral position in the Brookeland Austin Chalk play in East Texas. 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, 29 wells with modern completions are now producing in the field. 48 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. Commodity prices during 2023 decreased from the corresponding prior period due to several factors, including reduced demand for natural gas and rising global oil inventories. The U.S. Energy Information Administration ("EIA") forecasts natural gas prices to be slightly higher in 2024 because of slowing growth in natural gas production and increasing U.S. LNG exports, particularly following the addition of new export capacity expected toward the end of the year. The slowing growth reflects a drop in natural gas production associated with oil drilling in the Permian Basin. However, the EIA expects upward price pressures will be limited by relatively flat consumption of natural gas in the electric power sector and persistently high inventories. For much of 2023, oil prices were relatively flat. In September 2023, oil prices increased after Saudi Arabia extended its voluntary crude oil production cuts through the end of the year and U.S. commercial crude oil inventories fell to the lowest levels since early 2022. Despite reduced production targets by members of OPEC+, prices decreased in the fourth quarter based on ongoing concerns about global oil demand growth and on rising global oil inventories. The EIA expects that while OPEC+ production cuts will lead to global oil inventory withdrawals during the first quarter of 2024, global inventories will build over the final three quarters of 2024 as slowing demand growth once again is outpaced by rising supply growth. However, heightened tensions around the critical Red Sea shipping channel and other developments in the Middle East have added upward price pressure since early December and have the potential to disrupt global oil trade flows and drive up global oil prices further should those tensions persist or escalate. 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: 2023 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 71.89 $ 90.77 $ 70.66 $ 75.68 Henry Hub spot natural gas ($/MMBtu) 1 $ 2.58 $ 2.68 $ 2.48 $ 2.10 1 Source: EIA Rig Count As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. The following table shows the rig count at the end of each quarter presented: 2023 U.S. Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 500 502 545 592 Natural gas 120 116 124 160 Other 2 5 5 3 Total 622 623 674 755 1 Source: Baker Hughes Incorporated 49 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 forecasts that inventories will conclude the withdrawal season, which is the end of March 2024, at 1.9 Tcf, or 15% higher than the five-year average. The EIA expects inventories will rise to 4.0 Tcf at the end of October 2024, which would be 6% higher than the five-year average. The following table shows natural gas storage volumes by region at the end of each quarter presented: 2023 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 799 847 643 335 Midwest 968 991 705 421 Mountain 228 239 173 80 Pacific 280 278 216 73 South Central 1,201 1,090 1,141 921 Total 3,476 3,445 2,878 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 12.1 Bcf per day for 2024, a 2% increase from 2023 levels. In January 2024, the Biden administration announced that approvals for pending and future applications for certain new LNG facilities were being paused pending a review by the DOE that aims to assess whether climate effects should be more heavily considered in the authorization process for such LNG export projects. It is too early to know the outcome of this review and any impact the results of such review may have on LNG export growth. 50 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 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 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 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. 51 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 December 31, 2023 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual 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 up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of December 31, 2023, we had hedged 73% of our available oil and condensate hedge volumes and 66% of our available natural gas hedge volumes for 2024. 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 U.S. 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. 52 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: Year Ended December 31, 2023 2022 (in thousands) Net income (loss) $ 422,549 $ 476,480 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 45,683 47,804 Interest expense 2,754 6,286 Income tax expense (benefit) 320 58 Accretion of asset retirement obligations 1,042 861 Equity-based compensation 10,829 17,388 Unrealized (gain) loss on commodity derivative instruments (8,394) (82,486) (Gain) loss on sale of assets, net (73) (17) Adjusted EBITDA 474,710 466,374 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (9) (30) Cash interest expense (1,715) (4,282) Preferred unit distributions (21,776) (21,000) Distributable cash flow $ 451,210 $ 441,062 53 Results of Operations Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2023 2022 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,757 3,591 166 4.6 % Natural gas (MMcf) 1 64,647 59,778 4,869 8.1 % Equivalents (MBoe) 14,532 13,554 978 7.2 % Equivalents/day (MBoe) 39.8 37.1 2.7 7.3 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 76.74 $ 93.65 $ (16.91) (18.1) % Natural gas ($/Mcf) 1 3.10 7.28 (4.18) (57.4) % Equivalents ($/Boe) $ 33.62 $ 56.90 $ (23.28) (40.9) % Revenue: Oil and condensate sales $ 288,296 $ 336,287 $ (47,991) (14.3) % Natural gas and natural gas liquids sales 1 200,297 434,945 (234,648) (53.9) % Lease bonus and other income 12,506 13,052 (546) (4.2) % Revenue from contracts with customers 501,099 784,284 (283,185) (36.1) % Gain (loss) on commodity derivative instruments 91,117 (120,680) 211,797 (175.5) % Total revenue $ 592,216 $ 663,604 $ (71,388) (10.8) % Operating expenses: Lease operating expense $ 11,386 $ 12,380 $ (994) (8.0) % Production costs and ad valorem taxes 56,979 66,233 (9,254) (14.0) % Exploration expense 2,148 193 1,955 1013.0 % Depreciation, depletion, and amortization 45,683 47,804 (2,121) (4.4) % General and administrative 51,455 53,652 (2,197) (4.1) % Other expense: Interest expense 2,754 6,286 (3,532) (56.2) % 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 year ended December 31, 2023 decreased compared to the year ended December 31, 2022. The decrease in total revenue from the corresponding period is primarily due to lower realized commodity prices partially offset by an increase in production volumes and a gain on commodity derivative instruments in 2023 compared to a loss in 2022. Oil and condensate sales. Oil and condensate sales for the year ended December 31, 2023 were lower than the corresponding period in 2022 due to lower realized commodity prices partially offset by higher production volumes. The increase in oil and condensate production was primarily due to increased production volumes in the Permian Basin. Our mineral 54 and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for each of the years ended December 31, 2023 and 2022, respectively. Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the year ended December 31, 2023 as compared to the year ended December 31, 2022 due to lower realized commodity prices offset by higher production volumes. The increase in natural gas and NGL production was driven by new development in the Haynesville/Bossier play trend, including new activity from the Aethon development program in the Shelby Trough. Mineral and royalty interest production accounted for 94% and 92% of our natural gas volumes for the years ended December 31, 2023 and 2022, 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 2023, we recognized $82.7 million of realized gains and $8.4 million of unrealized gains from our commodity derivatives, compared to $203.2 million of realized losses and $82.5 million of unrealized gains in 2022. The unrealized gains on our commodity contracts in 2023 were primarily driven by changes in the forward commodity price curves for natural gas and in 2022 by changes in the forward commodity price curves for both oil and natural gas. Lease bonus and other income . When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus income 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 was slightly lower for the year ended December 31, 2023, as compared to the same period in 2022. Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income in 2023 and 2022. 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 in 2023 as compared to 2022, primarily due to a reduction in variable costs as a result of lower production from our non-operated working interest properties. 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 year ended December 31, 2023, production and ad valorem taxes decreased as compared to the year ended December 31, 2022, as a result of lower commodity prices. 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 2023 significantly increased due to costs incurred to acquire seismic information related to our mineral and royalty interests. 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 such 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 the 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 expense decreased for the year ended December 31, 2023 as compared to 2022, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities. The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months. General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the year ended December 31, 2023, general and administrative expenses decreased compared to 2022, primarily due to a $6.6 million decrease in equity-based compensation from lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2023 compared to upward movements in our 55 common unit price during 2022. The overall decrease was partially offset by increases in consulting costs of $2.6 million related to internal projects and a non-recurring $2.1 million recovery in allowance against an outstanding long-term receivable in 2022. Other Expense Interest expense. For the year ended December 31, 2023, interest expense decreased compared to 2022, primarily due to lower average outstanding borrowings resulting from fully paying down our Credit Facility in the first quarter of 2023. Interest expense in 2023 consisted primarily of commitment fees and amortization of debt issuance costs. 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 as applicable, and for investing in our business. 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 until February 26, 2024 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value. Thereafter, we may redeem the preferred units at par value, equal to $20.39, within a 90-day period on each second anniversary following November 28, 2023. See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report 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 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information. Cash Flows Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 The following table shows our cash flows for the periods presented: Year Ended December 31, 2023 2022 Change (in thousands) Cash flows provided by operating activities $ 521,251 $ 424,983 $ 96,268 Cash flows provided by (used in) investing activities (19,740) (1,215) (18,525) Cash flows provided by (used in) financing activities (435,536) (428,337) (7,199) 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 provided by operating activities for 2023 increased as compared to 2022. The increase was primarily due to an increase in net cash received on settlements of commodity derivative instruments in 2023 compared to net cash paid in the same period of 2022. The overall increase was partially offset by a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue due to lower realized commodity prices. 56 Investing Activities . Net cash used in investing activities for 2023 increased as compared to 2022. The change was primarily due to increased acquisition activity and higher net oil and natural gas capital expenditures in 2023 compared to the same period in 2022. Financing Activities . Cash flows used in financing activities for 2023 increased as compared to 2022. The increase was primarily due to higher distributions paid to common unitholders partially offset by lower net repayments under our Credit Facility in 2023 compared with 2022. Development Capital Expenditures In the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budget is created based upon our estimate of internally generated cash flows and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part, based on actual cash generated, the economics of wells proposed by our operators for our participation, and the successful closing of acquisitions. The timing, size, and nature of acquisitions are unpredictable. Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest. We spent approximately $4.8 million and $0.6 million associated with our non-operated working interests, net of farmout reimbursements during 2023 and 2022, respectively. Acquisitions During the year ended December 31, 2023, we acquired mineral and royalty interests for cash consideration of $14.6 million, including capitalized direct transaction costs. The acquisitions were funded with cash from operating activities and were primarily located in the Gulf Coast land region. Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions. We had no material acquisition activity during 2022. During 2021 we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units. The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil and natural gas properties, and $0.3 million of net working capital. See "Note 4 – Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report 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. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in October and April. In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027, increased the borrowing base to $550.0 million and elected to lower commitments under the Credit Facility to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million and the October 2023 borrowing base redetermination increased the borrowing base to $580.0 million. After both redeterminations we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 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 December 31, 2023, we were in compliance with all debt covenants. See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information. 57 Contractual Obligations The following table summarizes our minimum payments as of December 31, 2023 (in thousands): Payments due by period Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years Operating lease obligations $ 2,463 $ 655 $ 1,764 $ 44 $ — Purchase commitments 660 450 205 5 — Total $ 3,123 $ 1,105 $ 1,969 $ 49 $ — Critical Accounting Policies and Related Estimates The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. We have provided expanded discussion of our more significant accounting estimates below. See "Note 2 – Summary of Significant Accounting Policies" within the consolidated financial statements included elsewhere in this Annual Report for additional information. Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those estimates. Our consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm. We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates. Oil and Natural Gas Properties We follow the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost. 58 The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board Accounting Standards Codification. The basis for grouping is a reasonable aggregation of properties with a common geographic location, which we also refer to as a depletable unit. As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. DD&A expense related to our producing oil and natural gas properties was $45.0 million, $47.2 million, and $60.4 million for the years ended December 31, 2023, 2022, and 2021, respectively. We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable unit basis. We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. There was no impairment of proved oil and natural gas properties for the years ended December 31, 2023, 2022, and 2021. Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data. There was no impairment of unproved properties for the years ended December 31, 2023, 2022, and 2021. Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded. We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2023 reserve report. Applying this discount results in an approximate 2.0% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2023 reserve report prepared by NSAI. Revenues from Contracts with Customers Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. 59 Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price we receive for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. Allocation of transaction price to remaining performance obligations Oil and natural gas sales We have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As we have determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Prior-period performance obligations We record oil and natural gas revenue in the month production is delivered to the purchaser. As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2023 and 2022, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial. New and Revised Financial Accounting Standards The effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidated financial statements included elsewhere in this Annual Report.