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, 2019 ("2019 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, including the sharp decline in oil prices that occurred in March and April of 2020; • 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; 21 • 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; 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 2019 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 relatively stable production and reserves over time with minimal operating costs or capital requirements, allowing the majority of generated cash flow to be distributed to unitholders. As of September 30, 2020, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 69,000 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. 22 Recent Developments Asset Sales In July 2020, we closed our two previously announced transactions to sell certain mineral and royalty properties in the Permian Basin for total proceeds, after closing adjustments, of $150.2 million. The proceeds were used to reduce outstanding borrowings under our Credit Facility. One of these transactions, effective May 1, 2020, involved the sale of our mineral and royalty interests in specific tracts in Midland County, Texas for net proceeds of approximately $54.5 million. The other transaction, effective July 1, 2020, involved the sale of an undivided interest across parts of our Delaware Basin and Midland Basin positions for net proceeds of approximately $95.7 million. We estimate the production associated with the properties sold, in total, to be approximately 1,800 Boe per day at the time of the sale. COVID-19 Pandemic and Commodity Prices The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. To protect the health and well-being of our workforce in the wake of COVID-19, we have implemented remote work arrangements for all employees. We do not expect these arrangements to impact our ability to maintain operations. We will continue to prioritize the health and safety of our workforce when employees return to the office through frequent cleaning of common spaces, appropriate social distancing measures, and other best practices as recommended by state and local officials. 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, has resulted in significantly lower market prices for oil, natural gas, and natural gas liquids ("NGLs"). 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 current price environment has caused many of our operators to reduce their drilling and completion activity on our acreage, and caused some of our operators to temporarily shut-in production from existing wells, both of which negatively impact our production volumes. While we believe most of the shut-in production has been brought back on-line, drilling and completion activity remains depressed relative to pre-pandemic levels. The current price environment, 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, which takes into consideration the estimated loan value of our oil and natural gas properties, was reduced from $650.0 million to $460.0 million, effective May 1, 2020. Effective July 21, 2020, in connection with the closing of our two asset sales in the Permian Basin, the borrowing base was further reduced to $430.0 million. Effective November 3, 2020, the most recent borrowing base redetermination reduced the borrowing base to $400.0 million. 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. In light of the challenging business environment and uncertainty caused by the pandemic, the board of directors of our general partner (the "Board") also approved a reduction in the quarterly distribution for the first quarter of 2020 to increase the amount of retained free cash flow for debt reduction and balance sheet protection. The Board approved an increase in the quarterly distribution for the second quarter of 2020 and maintained that distribution for the third quarter of 2020, but the distribution remains below 2019 levels. Shelby Trough Update On May 4, 2020, we entered into a development agreement with affiliates of Aethon Energy ("Aethon") with respect to our undeveloped Shelby Trough Haynesville and Bossier shale acreage in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to our mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, increasing to a minimum of 15 wells per year beginning with the third program year. On June 10, 2020, we entered into a new incentive agreement with XTO Energy Inc. ("XTO") with respect to certain drilled but uncompleted wells ("DUCs") in our Shelby Trough acreage in San Augustine County, Texas. The agreement allows for royalty relief on 13 existing DUCs if XTO completes and turns the wells to sales by March 31, 2021, and complements the 23 recent development agreement with Aethon covering our Shelby Trough acreage in Angelina County towards our goal of reviving volume growth from the area. 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 and related economic repercussions have resulted in a significant reduction in demand for and prices of oil, natural gas and NGLs. In the first quarter of 2020 and into the second quarter of 2020, oil prices fell sharply, due in part to significantly decreased demand as a result of the COVID-19 pandemic and the announcement by Saudi Arabia of a significant increase in its maximum oil production capacity as well as the announcement by Russia that previously agreed upon oil production cuts between members of the Organization of the Petroleum Exporting Countries and its broader partners (“OPEC+”) would expire on April 1, 2020, and the ensuing expiration thereof. Agreed-upon production cuts by OPEC+ along with declining U.S. production have helped to correct the supply and demand imbalance; however, these reductions are not expected to be enough in the near-term to offset the significant inventory build caused by demand destruction from the COVID-19 pandemic. These market conditions have resulted in a decline in drilling activity as operators revise their capital budgets downward and adjust their operations in response to lower commodity prices. While oil prices have remained depressed, both natural gas spot prices and contract future prices for the fourth quarter of 2020 and for the full year 2021 have improved significantly from levels seen in the second quarter of 2020. 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. 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 following table reflects commodity prices as of the last day of each quarter presented: 2020 2019 Benchmark Prices 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter WTI spot oil price ($/Bbl) $ 40.05 $ 39.27 $ 20.51 $ 54.09 $ 58.20 $ 60.19 Henry Hub spot natural gas ($/MMBtu) $ 1.66 $ 1.76 $ 1.71 $ 2.37 $ 2.42 $ 2.73 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 as of the last day of each quarter presented: 2020 2019 U.S. Rotary Rig Count 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter Oil 183 188 624 713 793 816 Natural gas 75 75 102 146 173 190 Other 3 2 2 1 1 — Total 261 265 728 860 967 1,006 1 Source: Baker Hughes Incorporated 24 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 on October 31, 2020 at 4.0 Tcf, or 8% higher than the previous five-year average. However, because expected natural gas production will be lower this winter than last winter, the EIA forecasts inventory draws will outpace the five-year average during the heating season and end March 2021 at 1.7 Tcf, which would be 6% lower than the five-year average. The following table shows natural gas storage volumes by region as of the last day of each quarter presented: 2020 2019 Region 1 Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter East 872 639 382 826 526 210 Midwest 1,033 740 476 973 568 241 Mountain 231 173 92 199 134 64 Pacific 316 304 197 291 255 113 South Central 1,304 1,222 840 1,029 907 502 Total 3,756 3,078 1,987 3,318 2,390 1,130 1 Source: EIA 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 25 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. 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 and costless collar 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. Our costless collar contracts contain a fixed floor price and a fixed ceiling price. If the market price exceeds the fixed ceiling price, we pay the difference between the fixed ceiling price and the market settlement price. If the market price is below the fixed floor price, we receive the difference between the market settlement price and the fixed floor price. If the market price is between the fixed floor and fixed ceiling price, no payments are due from either party. 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 and costless collar 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, 2020 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, 2020, we have hedged all of our available oil and condensate hedge volumes and 81% of our available natural gas hedge volumes for 2020. As of September 30, 2020, we have also hedged 69% of our available oil and condensate hedge volumes and 73% of our available natural gas hedge volumes for 2021. 26 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 for the following 12 to 30 months. 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, estimated replacement capital expenditures during the subordination period, cash interest expense, distributions to preferred unitholders, and restructuring charges. Gains and losses on sales of assets were previously included in Adjusted EBITDA and excluded from Distributable cash flows. We believe this change to remove gains and losses on sales of assets from the definition of Adjusted EBITDA more closely conforms with peer company practice. 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. 27 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, 2020 2019 2020 2019 (in thousands) Net income (loss) $ 23,733 $ 70,247 $ 91,474 $ 174,351 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 19,823 27,375 62,198 84,933 Impairment of oil and natural gas properties — — 51,031 — Interest expense 1,664 5,395 9,055 16,572 Income tax expense (benefit) (155) (353) 7 (187) Accretion of asset retirement obligations 286 275 836 829 Equity–based compensation 1,825 3,867 1,405 16,906 Unrealized (gain) loss on commodity derivative instruments 42,374 (10,644) 17,043 6,026 (Gain) loss on sale of assets, net (24,045) — (24,045) — Adjusted EBITDA 65,505 96,162 209,004 299,430 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (6) 37 (315) 27 Cash interest expense (1,401) (5,132) (8,273) (15,793) Estimated replacement capital expenditures 1 — — — (2,750) Preferred unit distributions (5,250) (5,250) (15,750) (15,750) Restructuring charges 2 — — 4,815 — Distributable cash flow $ 58,848 $ 85,817 $ 189,481 $ 265,164 1 The Board established a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019. Due to the expiration of the subordination period, we do not intend to establish a replacement capital expenditure estimate for periods subsequent to March 31, 2019. 2 Restructuring charges include non-recurring costs associated with broad workforce reductions in the first quarter of 2020. 28 Results of Operations Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019 The following table shows our production, revenues, pricing, and expenses for the periods presented: Three Months Ended September 30, 2020 2019 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 953 1,207 (254) (21.0) % Natural gas (MMcf) 1 15,220 19,816 (4,596) (23.2) % Equivalents (MBoe) 3,490 4,510 (1,020) (22.6) % Equivalents/day (MBoe) 37.9 49.0 (11.1) (22.7) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 36.03 $ 56.55 $ (20.52) (36.3) % Natural gas ($/Mcf) 1 1.91 2.09 (0.18) (8.6) % Equivalents ($/Boe) $ 18.18 $ 24.30 $ (6.12) (25.2) % Revenue: Oil and condensate sales $ 34,335 $ 68,255 $ (33,920) (49.7) % Natural gas and natural gas liquids sales 1 29,107 41,340 (12,233) (29.6) % Lease bonus and other income 1,386 3,484 (2,098) (60.2) % Revenue from contracts with customers 64,828 113,079 (48,251) (42.7) % Gain (loss) on commodity derivative instruments (21,086) 24,290 (45,376) NM 2 Total revenue $ 43,742 $ 137,369 $ (93,627) (68.2) % Operating expenses: Lease operating expense $ 3,160 $ 4,356 $ (1,196) (27.5) % Production costs and ad valorem taxes 9,905 15,877 (5,972) (37.6) % Exploration expense 4 64 (60) (93.8) % Depreciation, depletion, and amortization 19,823 27,375 (7,552) (27.6) % General and administrative 9,381 14,189 (4,808) (33.9) % Other expense: Interest expense 1,664 5,395 (3,731) (69.2) % 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. 2 Not meaningful. Revenue Total revenue for the quarter ended September 30, 2020 decreased compared to the quarter ended September 30, 2019. The decrease in total revenue from the corresponding period is due to a loss on our commodity derivative instruments in the third quarter of 2020 compared to a gain in the third quarter of 2019, a decrease in oil and condensate sales and natural gas and NGL sales as a result of lower realized commodity prices and lower production volumes, and a decrease in lease bonus and other income. Oil and condensate sales. Oil and condensate sales decreased for the quarter ended September 30, 2020 as compared to the corresponding period in 2019 due to lower realized commodity prices and lower production volumes. The decrease in oil and condensate production was primarily driven by production volume decreases in the Permian Basin. Our mineral and royalty 29 interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both quarters ended September 30, 2020 and 2019. Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended September 30, 2020 as compared to the corresponding prior period due to lower realized commodity prices and lower production volumes. The decrease in natural gas and NGL production was driven by production volume decreases in the Haynesville/Bossier play primarily due to reduced drilling activity and shut-in production volumes associated with the completion of certain DUCs on our Shelby Trough acreage. Mineral and royalty interest production accounted for 78% and 71% of our natural gas volumes for the quarters ended September 30, 2020 and 2019, respectively. Gain (loss) on commodity derivative instruments. During the third quarter of 2020, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2019. 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, 2020, we recognized $21.3 million of realized gains and $42.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.6 million of realized gains and $10.6 million of unrealized gains in the same period in 2019. The unrealized losses on our commodity contracts during the third quarter of 2020 was primarily driven by changes in the forward commodity price curves for oil and natural gas. The unrealized gains in the same period in 2019 were primarily driven by changes in the forward commodity price curve 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 2020 was lower than the same period in 2019. Leasing activity in the Haynesville/Bossier play as well as certain surface leases in Polk County, Texas made up the majority of lease bonus revenue in the third quarter of 2020, while a substantial portion of third quarter 2019 activity came from the Permian Basin and the Bakken/Three Forks trend. 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, 2020 as compared to the same period in 2019, primarily due to lower nonrecurring service-related expenses, including workovers, as well as a decrease in variable costs as a result of lower production from our non-operating working interest properties. Production costs and ad valorem taxes . Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended September 30, 2020, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2019, primarily as a result of lower commodity prices and lower production volumes. 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 each of the three months ended September 30, 2020 and 2019. 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, 2020 as compared to the same period in 2019, 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 as well as oil and natural gas property impairments recorded in the first quarter of 2020. 30 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, 2020, general and administrative expenses decreased as compared to the same period in 2019, primarily due to a $2.1 million decrease in cash compensation and a $1.9 million decrease in equity-based compensation resulting from the broad workforce reduction in the first quarter of 2020. Interest expense . Interest expense was lower in the third quarter of 2020 relative to the corresponding period in 2019, due to lower interest rates and lower average outstanding borrowings under our Credit Facility. Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 The following table shows our production, revenues, pricing, and expenses for the periods presented: Nine Months Ended September 30, 2020 2019 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 2,980 3,631 (651) (17.9) % Natural gas (MMcf) 1 51,922 59,025 (7,103) (12.0) % Equivalents (MBoe) 11,634 13,469 (1,835) (13.6) % Equivalents/day (MBoe) 42.5 49.3 (6.8) (13.8) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 37.53 $ 55.09 $ (17.56) (31.9) % Natural gas ($/Mcf) 1 1.85 2.65 (0.80) (30.2) % Equivalents ($/Boe) $ 17.87 $ 26.48 $ (8.61) (32.5) % Revenue: Oil and condensate sales $ 111,845 $ 200,031 $ (88,186) (44.1) % Natural gas and natural gas liquids sales 1 96,060 156,622 (60,562) (38.7) % Lease bonus and other income 7,669 15,846 (8,177) (51.6) % Revenue from contracts with customers 215,574 372,499 (156,925) (42.1) % Gain (loss) on commodity derivative instruments 49,751 12,294 37,457 304.7 % Total revenue $ 265,325 $ 384,793 $ (119,468) (31.0) % Operating expenses: Lease operating expense $ 10,280 $ 13,497 $ (3,217) (23.8) % Production costs and ad valorem taxes 31,836 44,919 (13,083) (29.1) % Exploration expense 28 372 (344) (92.5) % Depreciation, depletion, and amortization 62,198 84,933 (22,735) (26.8) % Impairment of oil and natural gas properties 51,031 — 51,031 NM 2 General and administrative 32,738 49,750 (17,012) (34.2) % Other expense: Interest expense 9,055 16,572 (7,517) (45.4) % 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. 31 Revenue Total revenue for the nine months ended September 30, 2020 decreased compared to the corresponding prior period. The decrease in total revenue is primarily due to a decrease in oil and condensate sales and natural gas and NGL sales as a result of lower realized commodity prices and lower production volumes, and a decrease in lease bonus and other income. The overall decrease in total revenue was partially offset by an increase in the gain from our commodity derivative instruments for the nine months ended September 30, 2020, compared to the same period in 2019. Oil and condensate sales. Oil and condensate sales during the nine months ended September 30, 2020 decreased compared to the corresponding prior period due to lower realized commodity prices and lower production volumes. The decrease in oil and condensate production was primarily driven by lower production volumes in the Bakken/Three Forks. Our mineral and royalty interest oil and condensate volumes accounted for 92% and 92% of total oil and condensate volumes for the nine months ended September 30, 2020 and 2019, respectively. Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 30, 2020 decreased compared to the corresponding prior period due to lower realized commodity prices and lower production volumes. The decrease in natural gas and NGL production was driven by lower volumes in the Haynesville/Bossier play primarily due to reduced drilling activity and shut-in production volumes associated with the completion of certain DUCs on our Shelby Trough acreage. Mineral and royalty interest production accounted for 76% and 68% of our natural gas volumes for the nine months ended September 30, 2020 and 2019, respectively. Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2020, we recognized an increase in the gain from our commodity derivative instruments compared to the same period in 2019. In the nine months ended September 30, 2020, we recognized $66.8 million of realized gains and $17.0 million of unrealized losses from our oil and natural gas commodity contracts, compared to $18.3 million of realized gains and $6.0 million of unrealized losses in the same period in 2019. The unrealized losses on our commodity contracts during the nine months ended September 30, 2020 were primarily driven by changes in the forward commodity price curves for gas. The unrealized losses on our commodity contracts during the corresponding period in 2019 were primarily driven by changes in the forward commodity price curves for oil, partially offset 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, 2020 was lower than the same period in 2019. Leasing activity in the Permian Basin, Green River Basin, and Bakken/Three Forks as well as certain surface leases in Polk County, Texas made up the majority of lease bonus revenue in the nine months ended September 30, 2020, while a substantial portion of the activity in the corresponding prior period came from the Permian Basin, as well as the Bakken/Three Forks, Wilcox, and Woodbine trends. Operating and Other Expenses Lease operating expense . Lease operating expense decreased for the nine months ended September 30, 2020 as compared to the same period in 2019, primarily due to lower nonrecurring service-related expenses, including workovers, as well as 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, 2020, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2019, primarily as a result of lower commodity prices and lower production volumes. Exploration expense . Exploration expense for the nine months ended September 30, 2020 was minimal. Exploration expense for the nine months ended September 30, 2019 primarily related to costs incurred to acquire 3-D seismic information related to our mineral and royalty interests from a third-party service provider. Depreciation, depletion, and amortization . Depreciation, depletion, and amortization decreased for the nine months ended September 30, 2020 as compared to the same period in 2019, 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 as well as oil and natural gas property impairments recorded in the first quarter of 2020. 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, 32 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, 2019. General and administrative . For the nine months ended September 30, 2020, general and administrative expenses decreased as compared to the same period in 2019, primarily due to a $6.9 million decrease in cash compensation and a $14.9 million decrease in equity-based compensation. The decrease in cash compensation is primarily resulting from the broad workforce reductions in the first quarter of 2020. The decrease in equity-based compensation is due in part to these same workforce reductions but also due to downward cost revisions recognized in the nine months ended September 30, 2020 for performance-based incentive awards due to the decrease in our common unit price period over period. The overall decrease was partially offset by $4.8 million of restructuring charges in the first quarter of 2020 associated with the workforce reductions and a $1.1 million increase in allowance, recorded in the second quarter of 2020, against an outstanding long-term receivable. Interest expense . Interest expense was lower in the nine months ended September 30, 2020 than in the prior period primarily due to lower interest rates and lower average outstanding borrowings under our Credit Facility. 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, 2020, we had outstanding borrowings of $ 147.0 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. In light of the challenging business environment and uncertainty caused by the pandemic, the Board approved a reduction in the quarterly distribution for the first quarter of 2020 to increase the amount of retained free cash flow for debt reduction and balance sheet protection. The Board approved an increase in the quarterly distribution for the second quarter of 2020 and maintained that distribution for the third quarter of 2020 but the distribution remains below 2019 levels. If our borrowings exceed our borrowing base, our ability to pay cash distributions to our unitholders will be limited. 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. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. The Board established a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019. Due to the expiration of the subordination period, we do not intend to establish a replacement capital expenditure estimate for periods subsequent to March 31, 2019. Cash Flows The following table shows our cash flows for the periods presented: Nine Months Ended September 30, 2020 2019 Change (in thousands) Cash flows provided by operating activities $ 221,414 $ 306,310 $ (84,896) Cash flows provided by (used in) investing activities 150,640 (48,833) 199,473 Cash flows used in financing activities (377,116) (260,925) (116,191) 33 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, 2020 as compared to the same period of 2019. The decrease was primarily due to decreased oil and condensate sales and natural gas and NGL sales driven by lower realized commodity prices and lower production for the nine months ended September 30, 2020 compared to the same period of 2019. The overall decrease was partially offset by higher net cash received on settlement of commodity derivative instruments. Investing Activities . Net cash was provided by investing activities in the nine months ended September 30, 2020 as compared to net cash used in investing activities in the same period of 2019. The change was primarily due to proceeds from the sale of oil and natural gas properties as well as a decrease in the additions to oil and natural gas properties in the nine months ended September 30, 2020. Financing Activities . Cash flows used in financing activities increased for the nine months ended September 30, 2020 as compared to the same period of 2019. The increase was primarily due to net repayments under our Credit Facility in the nine months ended September 30, 2020 as compared to net borrowings in the corresponding prior period. The overall increase was partially offset by lower distributions to common and subordinated unitholders and decreased repurchases of common units. Development Capital Expenditures Our 2020 total development capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.0 million, net of farmout reimbursements, of which $0.8 million has been invested in the nine months ended September 30, 2020. The majority of this capital will be spent for workovers on existing wells in which we own a working interest. 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, 2022. As of September 30, 2020, we had outstanding borrowings of $ 147.0 million at a weighted-average interest rate of 2.15 %. 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 October 23, 2019 the borrowing base redetermination reduced the borrowing base from $ 675.0 million to $ 650.0 million, effective May 1, 2020, the borrowing base was reduced to $ 460.0 million. Effective July 21, 2020, in connection with the closing of our two asset sales in the Permian Basin, the borrowing base was further reduced to $ 430.0 million. Effective November 3, 2020, the most recent borrowing base redetermination reduced the borrowing base to $ 400.0 million. The next borrowing base redetermination is expected in the spring of 2021. If operators continue to shut-in production and commodity prices remain at current levels, our borrowing base could be further reduced. 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. The applicable margin for the alternative base rate ranges from 0.75 % to 1.75 % and the applicable margin for LIBOR ranges from 1.75 % to 2.75 %, depending on the borrowings outstanding in relation to the borrowing base. Effective November 3, 2020, the LIBOR margin was increased to between 2.00 % and 3.00 % and the alternative base rate margin was increased to between 1.00 % and 2.00 %. 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. 34 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) or during any time that our borrowing base is lower than the loans outstanding under the credit agreement. 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, 2020, we were in compliance with all debt covenants. On July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which require that we and our lenders agree upon a replacement rate based on the then-prevailing market convention for similar agreements. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty reaching agreement on acceptable replacement rates under our Credit Facility. In the event that we do not reach agreement on an acceptable replacement rate for LIBOR, outstanding borrowings under the Credit Facility would revert to a floating rate equal to the alternative base rate (which, as of the time that LIBOR becomes unavailable, is equal to the greater of the Prime Rate and the Federal Funds effective rate plus 0.50 %) plus the applicable margin for the alternative base rate which ranges between 1.00 % to 2.00 %. If we are unable to negotiate replacement rates on favorable terms, it could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. Contractual Obligations As of September 30, 2020, there have been no material changes to our contractual obligations previously disclosed in our 2019 Annual Report on Form 10-K. Off-Balance Sheet Arrangements As of September 30, 2020, we did not have any material off-balance sheet arrangements. Critical Accounting Policies and Related Estimates As of September 30, 2020, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2019 Annual Report on Form 10-K. New and Revised Financial Accounting Standards The effects of new accounting pronouncements are discussed in the notes to our unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.