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, 2022 ("2022 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; 19 • 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 2022 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 and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. 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. As of September 30, 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 over 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 Aethon continues to perform with drilling and completing wells according to our development agreements. Aethon has six rigs currently on our acreage in the Shelby Trough. As of September 30, 2023, Aethon has successfully turned 18 wells to sales and has commenced operations on 27 additional wells under the development agreement covering Angelina County. As of September 30, 2023, Aethon has successfully turned ten wells to sales and has another seven wells awaiting completion operations under the separate development agreement covering San Augustine County. Additionally, XTO Energy has two wells currently awaiting completion operations. 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 2021 three well test program in the Brookeland Field demonstrated that modern completion technology has the potential to greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation. Eight operators are actively engaged in redevelopment of the field. As of September 30, 2023, 26 wells with modern completions are now producing in the field, and an additional three wells are currently either being drilled or completed. 20 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. Average commodity prices during the nine months ended September 30, 2023 decreased from the corresponding prior period, due to several factors, including reduced demand for natural gas and rising global oil inventories. Natural gas prices decreased sharply in the fourth quarter of 2022 and the first quarter of 2023 as a result of increases in dry natural gas production, lower-than-average consumption due to mild winter weather conditions, and the resulting higher-than-average storage inventories. Natural gas prices began to recover in the next two quarters as production growth has not kept pace with the growth in LNG exports and record consumption in the electric power sector this summer. Despite lower-than-average storage injections in the third quarter, natural gas inventories remain above the five-year average, and the U.S. Energy Information Administration ("EIA") expects natural gas supplies will be sufficient to meet winter demand. For much of the nine months ended September 30, 2023, oil prices were lower than the corresponding prior period. 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. The EIA expects reduced production targets by members of the Organization of the Petroleum Exporting Countries and its broader partners ("OPEC+") to continue during 2024 with offsetting production growth from non-OPEC+ producers. Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine and the Middle East, we cannot reasonably estimate the period of time that 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 2022 Benchmark Prices 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter WTI spot oil price ($/Bbl) $ 90.77 $ 70.66 $ 75.68 $ 79.91 $ 107.76 $ 100.53 Henry Hub spot natural gas ($/MMBtu) $ 2.68 2.48 2.10 6.40 6.54 5.46 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 2022 U.S. Rotary Rig Count 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter Oil 502 545 592 604 594 531 Natural gas 116 124 160 159 157 137 Other 5 5 3 2 2 2 Total 623 674 755 765 753 670 1 Source: Baker Hughes Incorporated 21 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 estimates that natural gas inventories concluded the injection season in October 2023 at 3.9 Tcf, which is 6% higher than the previous five-year average. The following table shows natural gas storage volumes by region at the end of each quarter presented: 2023 2022 Region 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter East 847 643 335 756 461 268 Midwest 991 705 421 916 535 317 Mountain 239 173 80 184 134 89 Pacific 278 216 73 247 235 161 South Central 1,090 1,141 921 1,003 886 581 Total 3,445 2,878 1,830 3,106 2,251 1,416 1 Source: EIA Natural Gas Exports The EIA expects an increase in U.S. LNG exports resulting from three LNG export projects that are set to begin operations in 2024. Net natural gas exports averaged 11.4 Bcf per day in the third quarter of 2023, a 7% increase from the 2022 average. The EIA forecasts average exports of 11.9 Bcf per day for the remainder of 2023 and 13.1 Bcf per day for 2024. The EIA forecast reflects the assumption that production remains flat and that expected additional U.S. LNG export capacity comes online. 22 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. 23 Hedging We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of September 30, 2023 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 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 September 30, 2023, we had hedged 67% and 56% of our available oil and condensate hedge volumes for 2023 and 2024, respectively. As of September 30, 2023, we had also hedged 63% and 77% of our available natural gas hedge volumes for 2023 and 2024, 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. 24 The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (in thousands) Net income (loss) $ 62,067 $ 168,475 $ 274,902 $ 293,261 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 12,367 12,208 33,935 35,018 Interest expense 621 1,693 2,080 4,264 Income tax expense (benefit) (109) 140 177 229 Accretion of asset retirement obligations 254 209 749 616 Equity–based compensation 3,777 4,534 8,412 11,809 Unrealized (gain) loss on commodity derivative instruments 51,111 (64,145) 29,006 (10,472) (Gain) loss on sale of assets, net (73) — (73) (17) Adjusted EBITDA 130,015 123,114 349,188 334,708 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (1) (8) (8) (23) Cash interest expense (359) (1,346) (1,305) (3,223) Preferred unit distributions (5,250) (5,250) (15,750) (15,750) Distributable cash flow $ 124,405 $ 116,510 $ 332,125 $ 315,712 25 Results of Operations Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022 The following table shows our production, revenue, and operating expenses for the periods presented: Three Months Ended September 30, 2023 2022 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 1,092 844 248 29.4 % Natural gas (MMcf) 1 16,980 16,994 (14) (0.1) % Equivalents (MBoe) 3,922 3,676 246 6.7 % Equivalents/day (MBoe) 42.6 40.0 2.6 6.5 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 78.50 $ 95.07 $ (16.57) (17.4) % Natural gas ($/Mcf) 1 2.87 8.11 (5.24) (64.6) % Equivalents ($/Boe) $ 34.30 $ 59.30 $ (25.00) (42.2) % Revenue: Oil and condensate sales $ 85,724 $ 80,240 $ 5,484 6.8 % Natural gas and natural gas liquids sales 1 48,815 137,756 (88,941) (64.6) % Lease bonus and other income 2,180 3,159 (979) (31.0) % Revenue from contracts with customers 136,719 221,155 (84,436) (38.2) % Gain (loss) on commodity derivative instruments (26,922) (4,726) (22,196) 469.7 % Total revenue $ 109,797 $ 216,429 $ (106,632) (49.3) % Operating expenses: Lease operating expense $ 2,615 $ 2,896 $ (281) (9.7) % Production costs and ad valorem taxes 16,441 17,856 (1,415) (7.9) % Exploration expense 1,711 10 1,701 17,010.0 % Depreciation, depletion, and amortization 12,367 12,208 159 1.3 % General and administrative 14,448 13,044 1,404 10.8 % Other expense: Interest expense 621 1,693 (1,072) (63.3) % 1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas. Revenue Total revenue for the quarter ended September 30, 2023 decreased compared to the quarter ended September 30, 2022. The decrease in total revenue from the corresponding period is primarily due to a decrease in natural gas and NGL sales and a larger loss from our commodity derivative instruments, and was partially offset by a small increase in oil and condensate sales. Oil and condensate sales. Oil and condensate sales increased for the quarter ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to higher production volumes partially offset by lower realized commodity prices. The increase in oil and condensate production was driven by increases in mineral and royalty production in the Permian Basin, the Bakken Shale, and the Eagle Ford. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 94% of total oil and condensate volumes for quarters ended September 30, 2023 and 2022, respectively. 26 Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended September 30, 2023 as compared to the corresponding prior period. The decrease was primarily due to lower realized commodity prices between the comparative periods. Mineral and royalty interest production accounted for 94% and 93% of our natural gas volumes for the quarters ended September 30, 2023 and 2022, respectively. Gain (loss) on commodity derivative instruments. During the third quarter of 2023, we recognized a larger loss from our commodity derivative instruments compared to the same period in 2022. 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. For the three months ended September 30, 2023, we recognized $24.2 million of realized gains and $51.1 million of unrealized losses from our oil and natural gas commodity contracts, compared to $68.9 million of realized losses and $64.1 million of unrealized gains in the same period in 2022. The unrealized losses on our commodity contracts during the third quarter of 2023 and the unrealized gains in the same period in 2022 were primarily driven by changes in the forward commodity price curves for oil. Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the third quarter of 2023 was lower than the same period in 2022. Leasing activity in the Haynesville/Bossier and Bakken/Three Forks plays made up the majority of lease bonus and other income for the third quarter of 2023, while the majority of the third quarter 2022 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 September 30, 2023 as compared to the same period in 2022, primarily due to lower nonrecurring service-related expenses, including workovers. Production costs and ad valorem taxes . Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended September 30, 2023, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2022, primarily due to lower commodity prices and ad valorem tax estimates. 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 September 30, 2023 primarily related to costs incurred to acquire seismic information related to our mineral and royalty interests. Exploration expense in the corresponding prior period of 2022 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 was unchanged for the quarter ended September 30, 2023 as compared to the same period in 2022. 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 September 30, 2023, general and administrative expenses increased as compared to the same period in 2022, primarily due to a $1.3 million increase in consulting costs related to internal projects. Interest expense . Interest expense was lower in the third quarter of 2023 relative to the corresponding period in 2022, due to no borrowings under our Credit Facility. Interest expense for the third quarter of 2023 consisted of commitment fees and amortization of debt issuance costs. 27 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 The following table shows our production, revenues, pricing, and expenses for the periods presented: Nine Months Ended September 30, 2023 2022 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 2,731 2,574 157 6.1 % Natural gas (MMcf) 1 48,101 42,648 5,453 12.8 % Equivalents (MBoe) 10,748 9,682 1,066 11.0 % Equivalents/day (MBoe) 39.4 35.5 3.9 11.0 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 76.23 $ 97.27 $ (21.04) (21.6) % Natural gas ($/Mcf) 1 3.07 7.61 (4.54) (59.7) % Equivalents ($/Boe) $ 33.13 $ 59.39 $ (26.26) (44.2) % Revenue: Oil and condensate sales $ 208,184 $ 250,367 $ (42,183) (16.8) % Natural gas and natural gas liquids sales 1 147,857 324,691 (176,834) (54.5) % Lease bonus and other income 8,682 10,262 (1,580) (15.4) % Revenue from contracts with customers 364,723 585,320 (220,597) (37.7) % Gain (loss) on commodity derivative instruments 36,652 (152,095) 188,747 124.1 % Total revenue $ 401,375 $ 433,225 $ (31,850) (7.4) % Operating expenses: Lease operating expense $ 8,149 $ 9,256 $ (1,107) (12.0) % Production costs and ad valorem taxes 41,952 51,309 (9,357) (18.2) % Exploration expense 1,719 192 1,527 795.3 % Depreciation, depletion, and amortization 33,935 35,018 (1,083) (3.1) % General and administrative 38,950 39,326 (376) (1.0) % Other expense: Interest expense 2,080 4,264 (2,184) (51.2) % 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 nine months ended September 30, 2023 decreased compared to the corresponding prior period. The decrease in total revenue is due to decreases in natural gas and NGL sales, oil and condensate sales, and lease bonus and other income which were partially offset by a gain from our commodity derivative instruments for the nine months ended September 30, 2023 compared to a loss in the same period in 2022. Oil and condensate sales. Oil and condensate sales during the nine months ended September 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices that were partially offset by an increase in production. The increase in oil and condensate production was driven by mineral and royalty production in the Bakken Shale, the Permian Basin and the Eagle Ford. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for the nine months ended September 30, 2023 and 2022, respectively. 28 Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices partially offset by higher production volumes. The increase in natural gas and NGL production was driven by increases in royalty interest production volumes, primarily within the Haynesville/Bossier play, including new activity from the Aethon development program in the Shelby Trough. Mineral and royalty interest production accounted for 94% and 91% of our natural gas volumes for the nine months ended September 30, 2023 and 2022, respectively. Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2023, we recognized a gain from our commodity derivative instruments compared to a loss for the same period in 2022. In the nine months ended September 30, 2023, we recognized $65.7 million of realized gains and $29.0 million of unrealized losses from our oil and natural gas commodity contracts, compared to $162.6 million of realized losses and $10.5 million of unrealized gains in the same period in 2022. The unrealized losses on our commodity contracts during the nine months ended September 30, 2023 and the unrealized gains in the corresponding period in 2022 were primarily driven by changes in the forward commodity price curves for oil. Lease bonus and other income. Lease bonus and other income for the nine months ended September 30, 2023 was lower than the same period in 2022. Leasing activity in the Haynesville/Bossier and Bakken/Three Forks plays made up the majority of lease bonus and other income for the nine months ended September 30, 2023, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Haynesville/Bossier play and the Permian Basin. Operating and Other Expenses Lease operating expense . Lease operating expense decreased for the nine months ended September 30, 2023 as compared to the same period in 2022, primarily due to lower nonrecurring service-related expenses, including workovers. Production costs and ad valorem taxes . For the nine months ended September 30, 2023, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2022, primarily due to lower commodity prices and lower ad valorem tax estimates. Exploration expense . Exploration expense for the nine months ended September 30, 2023 primarily related to costs incurred to acquire seismic information related to our mineral and royalty interests. Exploration expense in the corresponding prior period of 2022 was minimal. Depreciation, depletion, and amortization . Depreciation, depletion, and amortization decreased slightly for the nine months ended September 30, 2023 as compared to the same period in 2022, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities partially offset by increased production. The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months. General and administrative . For the nine months ended September 30, 2023, general and administrative expenses decreased as compared to the same period in 2022, primarily due to a $3.4 million decrease in equity compensation which was partially offset by a $1.4 million increase in cash compensation and a $1.4 million increase in consulting costs related to internal projects. The decrease in equity incentive compensation was due to lower costs recognized for performance-based incentive awards resulting from upward movements in our common unit price in the corresponding prior period. The increase in cash compensation was driven by an increase in salaries and a separation payment related to the departure of a senior executive in the first quarter of 2023. This increase was partially offset by lower costs recognized under our short-term cash incentive plan due to projected outperformance relative to performance targets in the prior period. Interest expense . Interest expense was lower in the nine months ended September 30, 2023 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility. 29 Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties. As of September 30, 2023, no balance was outstanding under the Credit Facility. Beginning on November 28, 2023, we have the option to redeem Series B cumulative convertible preferred units. Also effective November 28, 2023, and every two years thereafter (each, a "Readjustment Date"), the distribution rate for the Series B cumulative convertible preferred units will be adjusted 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. 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, proceeds from any future issuances of equity and debt, and proceeds from asset sales. 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. Cash Flows The following table shows our cash flows for the periods presented: Nine Months Ended September 30, 2023 2022 Change (in thousands) Cash flows provided by operating activities $ 387,135 $ 268,550 $ 118,585 Cash flows used in investing activities (4,946) (677) (4,269) Cash flows used in financing activities (330,466) (275,911) (54,555) 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 increased for the nine months ended September 30, 2023 as compared to the same period of 2022. The increase was primarily due to higher cash settlements received on our commodity derivative instruments as compared to cash settlements paid in the same period of 2022. Investing Activities . Net cash used in investing activities in the nine months ended September 30, 2023 increased as compared to the same period of 2022. The increase was primarily due to increased additions to oil and natural gas properties, net of farmout reimbursements in the nine months ended September 30, 2023 as compared to the corresponding prior period. Financing Activities . Cash flows used in financing activities increased for the nine months ended September 30, 2023 as compared to the same period of 2022. The increase was primarily due to higher distributions to unitholders in the nine months ended September 30, 2023 as compared to the corresponding prior period. Development Capital Expenditures Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.1 million, net of farmout reimbursements, of which $3.7 million has been invested in the nine months ended September 30, 2023. The majority of this capital is for our participation in a single well drilled on our mineral acreage in the Austin Chalk play 30 trend as part of our organic initiatives in the area. The remaining capital is for workovers and recompletions on existing wells in which we own a working interest. 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 April and October. In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and we elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million. The October 2023 borrowing base redetermination increased the borrowing base to $580.0 million with no change to the cash commitments. 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, among other things. As of September 30, 2023, we were in compliance with all debt covenants. See Note 6 – Credit Facility to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. Contractual Obligations As of September 30, 2023, there have been no material changes to our contractual obligations previously disclosed in our 2022 Annual Report on Form 10-K. Critical Accounting Policies and Related Estimates As of September 30, 2023, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2022 Annual Report on Form 10-K.