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, 2020 ("2020 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 scope and duration of the COVID-19 pandemic and actions taken by governmental authorities and other parties in response to the pandemic; • 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; • our ability to identify, complete, and integrate acquisitions; • 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; 19 • 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; • 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 2020 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, 2021, 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 70,000 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. 20 Recent Developments TLW Divestiture In the third quarter of 2021, we closed on the divestiture of our wholly owned subsidiary, TLW Investments, L.L.C. ("TLW"), effective September 1, 2021 for total proceeds of $0.2 million. TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas. Shelby Trough Development Update Aethon has successfully turned to sales the initial two program wells and has commenced operations on four additional wells under the development agreement covering Angelina County. In October 2021, Aethon spud the first three wells under the separate development agreement covering San Augustine County. 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. Recent drilling results have shown that advances in fracturing and other completion techniques can dramatically improve well performance in existing Austin Chalk fields. One well has been drilled and turned to sales and five additional wells are currently being drilled under these agreements. Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us. COVID-19 Pandemic and Market Conditions The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. With widespread availability of vaccines, the U.S. Centers for Disease Control and Prevention has revised its guidance, travel restrictions have started to lift, and businesses have reopened. In the wake of a rise in COVID-19 cases resulting from new variants in our area, we have returned to remote work arrangements for all employees. Employees are allowed the flexibility of going to the office when following health and safety guidelines established by the company. We do not expect these arrangements to negatively impact our ability to maintain operations. We continue to prioritize the health and safety of our workforce through frequent cleaning of common spaces, appropriate physical distancing measures, and other best practices as recommended by federal, state and local officials. 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. The impact of the COVID-19 pandemic has negatively affected the oil and natural gas business environment, primarily by causing a reduction in commercial activity and travel worldwide thereby lowering energy demand. This, in turn, resulted in periods of significantly lower market prices for oil, natural gas, and natural gas liquids ("NGLs"). The price environment in 2020 caused many of our operators to reduce their drilling and completion activity on our acreage, which negatively impacts our production volumes. Commodity prices improved in late 2020 and have fully recovered in 2021, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners. However, the current price environment remains uncertain as responses to the COVID-19 pandemic continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related 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. 21 The price environment in 2020, including the sharp decline in oil prices that began in March 2020, also caused us to determine that certain depletable units consisting of mature oil producing properties were impaired as of March 31, 2020. Therefore, we recognized impairment of oil and natural gas properties of $51.0 million in the first quarter of 2020. Additionally, the borrowing base under the Credit Facility takes into consideration the estimated loan value of our oil and natural gas properties. Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million. The April and October 2021 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next borrowing base redetermination is scheduled for April 2022. In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced. The following table reflects commodity prices as of the last day of each quarter presented: 2021 2020 Benchmark Prices 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter WTI spot oil price ($/Bbl) $ 75.22 $ 73.52 $ 59.19 $ 40.05 $ 39.27 $ 20.51 Henry Hub spot natural gas ($/MMBtu) $ 5.58 3.79 2.52 1.66 1.76 1.71 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. While the rig count has recovered significantly from 2020 levels, this recovery has lagged the recovery in commodity prices as operators focus on greater capital discipline and efficiency. The following table shows the rig count as of the last day of each quarter presented: 2021 2020 U.S. Rotary Rig Count 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter Oil 421 372 324 183 188 624 Natural gas 99 98 92 75 75 102 Other 1 — 1 3 2 2 Total 521 470 417 261 265 728 1 Source: Baker Hughes Incorporated 22 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 will conclude the injection season in October 2021 at 3.6 Tcf, which is 5% lower than the previous five-year average. The following table shows natural gas storage volumes by region as of the last day of each quarter presented: 2021 2020 Region 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter East 779 513 307 872 639 382 Midwest 934 623 401 1,033 740 476 Mountain 201 173 112 231 173 92 Pacific 243 244 194 316 304 197 South Central 1,013 1,005 749 1,304 1,222 840 Total 3,170 2,558 1,763 3,756 3,078 1,987 1 Source: EIA 23 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. 24 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, 2021 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 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, 2021, we have hedged 100% and 71% of our available oil and condensate hedge volumes for 2021 and 2022, respectively. As of September 30, 2021, we have also hedged 84%, 72%, and 17% of our available natural gas hedge volumes for 2021, 2022, and 2023, 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, 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. 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. 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. 25 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, 2021 2020 2021 2020 (in thousands) Net income (loss) $ 16,178 $ 23,733 $ 47,793 $ 91,474 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 14,925 19,823 46,353 62,198 Impairment of oil and natural gas properties — — — 51,031 Interest expense 1,359 1,664 4,197 9,055 Income tax expense (benefit) 20 (155) (131) 7 Accretion of asset retirement obligations 273 286 863 836 Equity–based compensation 3,172 1,825 9,705 1,405 Unrealized (gain) loss on commodity derivative instruments 43,421 42,374 108,915 17,043 (Gain) loss on sale of assets, net (2,850) (24,045) (2,850) (24,045) Adjusted EBITDA 76,498 65,505 214,845 209,004 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (2) (6) (16) (315) Cash interest expense (1,011) (1,401) (2,965) (8,273) Preferred unit distributions (5,250) (5,250) (15,750) (15,750) Restructuring charges 1 — — — 4,815 Distributable cash flow $ 70,235 $ 58,848 $ 196,114 $ 189,481 1 Restructuring charges include non-recurring costs associated with broad workforce reductions in the first quarter of 2020. 26 Results of Operations Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020 The following table shows our production, revenues, pricing, and expenses for the periods presented: Three Months Ended September 30, 2021 2020 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 922 953 (31) (3.3) % Natural gas (MMcf) 1 15,467 15,220 247 1.6 % Equivalents (MBoe) 3,500 3,490 10 0.3 % Equivalents/day (MBoe) 38.0 37.9 0.1 0.3 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 67.15 $ 36.03 $ 31.12 86.4 % Natural gas ($/Mcf) 1 4.73 1.91 2.82 147.6 % Equivalents ($/Boe) $ 38.60 $ 18.18 $ 20.42 112.3 % Revenue: Oil and condensate sales $ 61,916 $ 34,335 $ 27,581 80.3 % Natural gas and natural gas liquids sales 1 73,167 29,107 44,060 151.4 % Lease bonus and other income 2,305 1,386 919 66.3 % Revenue from contracts with customers 137,388 64,828 72,560 111.9 % Gain (loss) on commodity derivative instruments (77,561) (21,086) (56,475) 267.8 % Total revenue $ 59,827 $ 43,742 $ 16,085 36.8 % Operating expenses: Lease operating expense $ 3,303 $ 3,160 $ 143 4.5 % Production costs and ad valorem taxes 14,331 9,905 4,426 44.7 % Exploration expense 5 4 1 25.0 % Depreciation, depletion, and amortization 14,925 19,823 (4,898) (24.7) % General and administrative 12,320 9,381 2,939 31.3 % Other expense: Interest expense 1,359 1,664 (305) (18.3) % 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, 2021 increased compared to the quarter ended September 30, 2020. The increase in total revenue from the corresponding period is due to an increase in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income. The overall increase in total revenue was partially offset by an increase in losses from our commodity derivative instruments. Oil and condensate sales. Oil and condensate sales increased for the quarter ended September 30, 2021 as compared to the corresponding period in 2020 due to higher realized commodity prices partially offset by lower production volumes. Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both quarters ended September 30, 2021 and 2020. 27 Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended September 30, 2021 as compared to the corresponding prior period. The increase was primarily due to higher realized commodity prices between the comparative periods. Mineral and royalty interest production accounted for 85% and 78% of our natural gas volumes for the quarters ended September 30, 2021 and 2020, respectively. Gain (loss) on commodity derivative instruments. During the third quarter of 2021, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2020. 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, 2021, we recognized $34.1 million of realized losses and $43.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $21.3 million of realized gains and $42.4 million of unrealized losses in the same period in 2020. The unrealized losses on our commodity contracts during the third quarter of 2021 were primarily driven by changes in the forward commodity price curves for natural gas. The unrealized losses for the same period in 2020 were primarily driven by changes in the forward commodity price curves for 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 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 2021 was higher than the same period in 2020. Leasing activity in the Wolfcamp play and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas made up the majority of lease bonus and other income for the third quarter of 2021, while a substantial portion of third quarter 2020 activity came from leasing activity in the Haynesville/Bossier play. 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 increased for the quarter ended September 30, 2021 as compared to the same period in 2020, primarily due to higher 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, 2021, production costs and ad valorem taxes increased as compared to the quarter ended September 30, 2020, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower 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 was minimal for the quarter ended September 30, 2021 and in the corresponding prior period in 2020. 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 decreased for the quarter ended September 30, 2021 as compared to the same period in 2020, 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. 28 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, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $1.7 million increase in cash compensation and a $1.4 million increase in equity compensation. The increase in cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan, and the increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards due to upward movements in our common unit price period over period. Interest expense . Interest expense was lower in the third quarter of 2021 relative to the corresponding period in 2020, due to lower average outstanding borrowings under our Credit Facility. 29 Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 The following table shows our production, revenues, pricing, and expenses for the periods presented: Nine Months Ended September 30, 2021 2020 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 2,610 2,980 (370) (12.4) % Natural gas (MMcf) 1 46,053 51,922 (5,869) (11.3) % Equivalents (MBoe) 10,286 11,634 (1,348) (11.6) % Equivalents/day (MBoe) 37.7 42.5 (4.8) (11.3) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 61.31 $ 37.53 $ 23.78 63.4 % Natural gas ($/Mcf) 1 3.75 1.85 1.90 102.7 % Equivalents ($/Boe) $ 32.33 $ 17.87 $ 14.46 80.9 % Revenue: Oil and condensate sales $ 160,028 $ 111,845 $ 48,183 43.1 % Natural gas and natural gas liquids sales 1 172,537 96,060 76,477 79.6 % Lease bonus and other income 12,195 7,669 4,526 59.0 % Revenue from contracts with customers 344,760 215,574 129,186 59.9 % Gain (loss) on commodity derivative instruments (164,923) 49,751 (214,674) NM 2 Total revenue $ 179,837 $ 265,325 $ (85,488) (32.2) % Operating expenses: Lease operating expense $ 9,804 $ 10,280 $ (476) (4.6) % Production costs and ad valorem taxes 35,469 31,836 3,633 11.4 % Exploration expense 1,080 28 1,052 3,757.1 % Depreciation, depletion, and amortization 46,353 62,198 (15,845) (25.5) % Impairment of oil and natural gas properties — 51,031 (51,031) NM 2 General and administrative 37,359 32,738 4,621 14.1 % Other expense: Interest expense 4,197 9,055 (4,858) (53.6) % 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. 2 Not meaningful. Revenue Total revenue for the nine months ended September 30, 2021 decreased compared to the corresponding prior period. The decrease in total revenue is due to a loss from our commodity derivative instruments for the nine months ended September 30, 2021 compared to a gain in the same period in 2020. The overall decrease in total revenue was partially offset by increases in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income. 30 Oil and condensate sales. Oil and condensate sales during the nine months ended September 30, 2021 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes. The decrease in oil and condensate production, primarily within the Permian Basin, was driven by divestitures of certain Permian Basin mineral and royalty properties in the third quarter of 2020. Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both the nine months ended September 30, 2021 and 2020. Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 30, 2021 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes. The decrease in natural gas and NGL production was driven by decreases in working interest production volumes, primarily within the Haynesville/Bossier play. Mineral and royalty interest production accounted for 83% and 76% of our natural gas volumes for the nine months ended September 30, 2021 and 2020, respectively. Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2021, we recognized a loss from our commodity derivative instruments compared to a gain for the same period in 2020. In the nine months ended September 30, 2021, we recognized $56.0 million of realized losses and $108.9 million of unrealized losses from our oil and natural gas commodity contracts, compared to $66.8 million of realized gains and $17.0 million of unrealized losses in the same period in 2020. The unrealized losses on our commodity contracts during the nine months ended September 30, 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas. The unrealized losses on our commodity contracts during the corresponding period in 2020 were primarily driven by changes in the forward commodity price curves for natural gas. Lease bonus and other income. Lease bonus and other income for the nine months ended September 30, 2021 was higher than the same period in 2020. Leasing activity in the Austin Chalk and Wolfcamp plays and proceeds from surface use waivers on our mineral acreage supporting solar development in Mississippi and Texas made up the majority of lease bonus and other income for the nine months ended September 30, 2021, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Permian Basin, Green River Basin, and Bakken/Three Forks. Operating and Other Expenses Lease operating expense . Lease operating expense decreased for the nine months ended September 30, 2021 as compared to the same period in 2020, primarily due to a decrease in variable costs as a result of lower production from our non-operating working interest properties. Production costs and ad valorem taxes . For the nine months ended September 30, 2021, production costs and ad valorem taxes increased as compared to the nine months ended September 30, 2020, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower ad valorem tax estimates. Exploration expense . Exploration expense for the nine months ended September 30, 2021 primarily related to a dry hole drilled in the first quarter of 2021. Exploration expense for the nine months ended September 30, 2020 was minimal. Depreciation, depletion, and amortization . Depreciation, depletion, and amortization decreased for the nine months ended September 30, 2021 as compared to the same period in 2020, primarily due to lower production volumes and 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. Impairment of oil and natural gas properties . Individual categories of oil and natural gas properties are assessed periodically to determine if the net book value for these properties has been impaired. Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activity, unproved leasehold, and mineral interests to identify impairments. Impairments totaled $51.0 million for the nine months ended September 30, 2020, primarily due to declines in future expected realizable net cash flows as a result of lower commodity prices as of the measurement date of March 31, 2020. There were no impairments for the nine months ended September 30, 2021. 31 General and administrative . For the nine months ended September 30, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $2.4 million increase in cash compensation and a $8.4 million increase in equity incentive compensation. The increase in cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan, and the increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during the nine months ended September 30, 2021 compared to downward movements in our common unit price in the corresponding prior period. The overall increase was partially offset by charges recognized for the nine months ended September 30, 2020 that did not recur. This included $4.8 million of restructuring costs associated with workforce reductions in the first quarter of 2020 and a $1.1 million increase in allowance against an outstanding long-term receivable. Interest expense . Interest expense was lower in the nine months ended September 30, 2021 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility. 32 Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, proceeds from the issuance of equity and debt, and proceeds from asset sales. 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, 2021, we had outstanding borrowings of $99.0 million under the Credit Facility. 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 our 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, 2021 2020 Change (in thousands) Cash flows provided by operating activities $ 183,426 $ 221,414 $ (37,988) Cash flows provided by (used in) investing activities (13,891) 150,640 (164,531) Cash flows used in financing activities (168,067) (377,116) 209,049 Operating Activities . Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities decreased for the nine months ended September 30, 2021 as compared to the same period of 2020. The decrease was primarily due to net cash paid on settlements of commodity derivative instruments in the nine months ended September 30, 2021 compared to net cash received in the same period of 2020. The overall decrease was partially offset by increases in oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices. Investing Activities . Net cash was used in investing activities in the nine months ended September 30, 2021 as compared to net cash provided by investing activities in the same period of 2020. The change was primarily due to cash paid for acquisitions of oil and natural gas properties in the nine months ended September 30, 2021 compared to cash received from the sale of oil and natural gas properties in the same period of 2020. Financing Activities . Cash flows used in financing activities decreased for the nine months ended September 30, 2021 as compared to the same period of 2020. The decrease was primarily due to lower net repayments under our Credit Facility in the nine months ended September 30, 2021 as compared to the corresponding prior period. Development Capital Expenditures Our 2021 capital expenditure budget associated with our non-operated working interests is expected to be approximately $5.0 million, net of farmout reimbursements, of which $4.1 million has been invested in the nine months ended September 30, 2021. The majority of this capital is anticipated to be spent for working interest participation on test wells in the Austin Chalk play and the remaining will be spent for workovers on existing wells in which we own a working interest. 33 Credit Facility Pursuant to our $1.0 billion senior secured revolving credit agreement, as amended (the “Credit Facility”), the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. Borrowings under the Credit Facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our Credit Facility terminates on November 1, 2024. As of September 30, 2021, we had outstanding borrowings of $99.0 million at a weighted-average interest rate of 2.59%. The borrowing base is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds of the lenders to maintain or decrease our existing borrowing base. In addition, we and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. We also have the right to request a redetermination following acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base. In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base. Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million. The April and October 2021 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next semi-annual redetermination is scheduled for April 2022. Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. As of December 31, 2020, the applicable margin for the alternative base rate ranged from 1.00% to 2.00% and the applicable margin for LIBOR ranged from 2.00% to 3.00%, depending on the borrowings outstanding in relation to the borrowing base. As of September 30, 2021, the alternative base rate margin ranged from 1.50% to 2.50% and the LIBOR margin ranged from 2.50% to 3.50%. We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. Our Credit Facility is secured by substantially all of our oil and natural gas production and assets. Our credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certain derivative agreements, as well as require the maintenance of certain financial ratios. The credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less and a current ratio of 1.0:1.0 or greater as defined in the credit agreement. Distributions are not permitted if there is a default under the credit agreement (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0. The lenders have the right to accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default, and the credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of September 30, 2021, we were in compliance with all debt covenants. On March 5, 2021, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S. dollar settings and after June 30, 2023 for the remaining U.S. dollar settings. Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR"). We currently do not expect the transition from LIBOR to have a material impact on us. 34 Contractual Obligations As of September 30, 2021, there have been no material changes to our contractual obligations previously disclosed in our 2020 Annual Report on Form 10-K. Off-Balance Sheet Arrangements As of September 30, 2021, we did not have any material off-balance sheet arrangements. Critical Accounting Policies and Related Estimates As of September 30, 2021, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2020 Annual Report on Form 10-K.