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, 2021 ("2021 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 conflict in Ukraine and actions taken, and may in the future be taken, against Russia or otherwise as a result; • 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; • the availability of U.S. liquefied natural gas ("LNG") export capacity and the level of demand for LNG exports; • 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; 17 • the availability of pipeline capacity and transportation facilities; • the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals; • federal and state legislative and regulatory initiatives relating to hydraulic fracturing; • future operating results; • 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 2021 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 March 31, 2022, 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. 18 Recent Developments Shelby Trough Development Update Aethon has successfully turned six wells to sales (four of which came online in April 2022) and has commenced operations on four additional wells under the development agreement covering Angelina County. Aethon is currently drilling two wells and has another two wells awaiting completion operations under the separate development agreement covering San Augustine County. Additionally, XTO Energy has resumed drilling three wells on our Shelby Trough acreage in San Augustine County that were originally spud in 2019. Austin Chalk Update We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions. The results of our three well test program in the Brookeland Field demonstrates that modern completion technology can greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation. Four operators are actively engaged in redevelopment of the field, with two rigs running continuously in the play. To date, seven wells with modern completions are now producing in the area, and an additional five are currently either being drilled or completed. 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, most travel restrictions have been lifted, and many businesses have reopened. We currently offer employees the option to work remotely or, subject to compliance with our health and safety guidelines, in the office. 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"). Commodity prices have subsequently recovered, 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. In addition, Russia's military incursion into Ukraine and the subsequent sanctions imposed on Russia and other actions created significant market uncertainties about the potential for supply disruptions that further increased global commodity prices in the first quarter of 2022. The current price environment remains uncertain as responses to the COVID-19 pandemic and the conflict in Ukraine continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. 19 The following table reflects commodity prices as of the last day of each quarter presented: 2022 2021 Benchmark Prices 1 First Quarter First Quarter WTI spot oil price ($/Bbl) $ 100.53 $ 59.19 Henry Hub spot natural gas ($/MMBtu) 5.46 2.52 1 Source: EIA Natural Gas Exports Rising levels of U.S.LNG exports have been a growing source of demand and have positively impacted natural gas prices, particularly in the Gulf Coast region where the majority of our natural gas is produced. LNG prices in Europe remain high amid supply uncertainties due to Russia's further invasion of Ukraine and the need to replenish Europe's natural gas inventories, which has kept Europe's demand for LNG elevated. Net natural gas exports averaged 11.5 Bcf per day in the first quarter of 2022, an 18% increase from the 2021 average. The EIA expects high levels of U.S. LNG exports to continue, forecasting average exports of 12.4 Bcf per day for the rest of 2022 and 12.6 Bcf per day for 2023. The EIA forecast reflects the assumption that global natural gas demand remains strong and that expected additional U.S. LNG export capacity comes online. 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: 2022 2021 U.S. Rotary Rig Count 1 First Quarter First Quarter Oil 531 324 Natural gas 137 92 Other 2 1 Total 670 417 1 Source: Baker Hughes Incorporated 20 Natural Gas Storage A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook. Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA estimates that natural gas inventories will conclude the injection season in October 2022 at 3.5 Tcf, which is 4% 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: 2022 2021 Region 1 First Quarter First Quarter East 268 307 Midwest 317 401 Mountain 89 112 Pacific 161 194 South Central 581 749 Total 1,416 1,763 1 Source: EIA 21 How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following: • volumes of oil and natural gas produced; • commodity prices including the effect of derivative instruments; and • Adjusted EBITDA and Distributable cash flow. Volumes of Oil and Natural Gas Produced In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances. Commodity Prices Factors Affecting the Sales Price of Oil and Natural Gas The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the United States. • Oil . The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as West Texas Intermediate ("WTI"), is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials. The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points. • Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications. Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets. 22 Hedging We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, 2022 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 March 31, 2022, we have hedged 92% and 6% of our available oil and condensate hedge volumes for 2022 and 2023, respectively. As of March 31, 2022, we have also hedged 72% and 16% of our available natural gas hedge volumes for 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, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any. Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance. Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies. 23 The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated: Three Months Ended March 31, 2022 2021 (in thousands) Net income (loss) $ (7,002) $ 16,186 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 10,917 15,632 Interest expense 1,209 1,210 Income tax expense (benefit) 103 (157) Accretion of asset retirement obligations 202 292 Equity–based compensation 4,551 3,462 Unrealized (gain) loss on commodity derivative instruments 88,776 23,359 Adjusted EBITDA 98,756 59,984 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (9) (9) Cash interest expense (862) (953) Preferred unit distributions (5,250) (5,250) Distributable cash flow $ 92,635 $ 53,772 24 Results of Operations Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021 The following table shows our production, revenues, pricing, and expenses for the periods presented: Three Months Ended March 31, 2022 2021 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 831 829 2 0.2 % Natural gas (MMcf) 1 12,759 14,911 (2,152) (14.4) % Equivalents (MBoe) 2,958 3,314 (356) (10.7) % Equivalents/day (MBoe) 32.9 36.8 (3.9) (10.6) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 91.25 $ 53.29 $ 37.96 71.2 % Natural gas ($/Mcf) 1 5.94 2.88 3.06 106.3 % Equivalents ($/Boe) $ 51.25 $ 26.27 $ 24.98 95.1 % Revenue: Oil and condensate sales $ 75,831 $ 44,176 $ 31,655 71.7 % Natural gas and natural gas liquids sales 1 75,754 42,889 32,865 76.6 % Lease bonus and other income 4,859 2,385 2,474 103.7 % Revenue from contracts with customers 156,444 89,450 66,994 74.9 % Gain (loss) on commodity derivative instruments (120,020) (27,882) (92,138) 330.5 % Total revenue $ 36,424 $ 61,568 $ (25,144) (40.8) % Operating expenses: Lease operating expense $ 3,161 $ 2,664 $ 497 18.7 % Production costs and ad valorem taxes 13,949 11,842 2,107 17.8 % Exploration expense 180 1,073 (893) (83.2) % Depreciation, depletion, and amortization 10,917 15,632 (4,715) (30.2) % General and administrative 13,763 12,852 911 7.1 % Other expense: Interest expense 1,209 1,210 (1) (0.1) % 1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas. Revenue Total revenue for the quarter ended March 31, 2022 decreased compared to the quarter ended March 31, 2021. The decrease in total revenue from the corresponding period is primarily due to an increase in unrealized losses from our commodity derivative instruments and was partially offset by an increase in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income. Oil and condensate sales. Oil and condensate sales increased for the quarter ended March 31, 2022 as compared to the corresponding period in 2021 primarily due to higher realized commodity prices while production volumes remained flat. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 92% of total oil and condensate volumes for quarters ended March 31, 2022 and 2021, respectively. 25 Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2022 as compared to the corresponding prior period. The increase was primarily due to higher realized commodity prices between the comparative periods partially offset by lower production volumes due to the timing of new development. The decrease in natural gas and NGL production was primarily driven by the natural decline in producing wells in the Shelby Trough outpacing new activity from the Aethon development program, which has not yet fully ramped up. Mineral and royalty interest production accounted for 89% and 82% of our natural gas volumes for the quarters ended March 31, 2022 and 2021, respectively. Gain (loss) on commodity derivative instruments. During the first quarter of 2022, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2021. 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 March 31, 2022, we recognized $31.2 million of realized losses and $88.8 million of unrealized losses from our oil and natural gas commodity contracts, compared to $4.5 million of realized losses and $23.4 million of unrealized losses in the same period in 2021. The unrealized losses on our commodity contracts during the first quarter of 2022 were primarily driven by changes in the forward commodity price curves for oil and natural gas. The unrealized losses for the same period in 2021 were primarily driven by changes in the forward commodity price curves for oil. Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of 2022 was higher than the same period in 2021. Leasing activity in the Wolfcamp play made up the majority of lease bonus and other income for the first quarter of 2022, while a substantial portion of the first quarter 2021 activity came from leasing activity in the Austin Chalk 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 March 31, 2022 as compared to the same period in 2021, 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 March 31, 2022, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2021, 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 March 31, 2022 and in the corresponding prior period in 2021. 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 March 31, 2022 as compared to the same period in 2021, 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. 26 General and administrative . General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2022, general and administrative expenses increased slightly as compared to the same period in 2021, primarily due to a $1.1 million increase in equity compensation. 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 . The change in interest expense was minimal in the first quarter of 2022 relative to the corresponding period in 2021, due to lower average outstanding borrowings under our Credit Facility almost completely offset by higher interest rates. 27 Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties. As of March 31, 2022, we had outstanding borrowings of $69.0 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: Three Months Ended March 31, 2022 2021 Change (in thousands) Cash flows provided by operating activities $ 82,576 $ 55,686 $ 26,890 Cash flows provided by (used in) investing activities (96) (214) 118 Cash flows used in financing activities (84,703) (53,479) (31,224) Operating Activities . Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities increased for the three months ended March 31, 2022 as compared to the same period of 2021. The increase was primarily due to higher oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices in the three months ended March 31, 2022 compared to the same period of 2021. The overall increase was partially offset by higher cash settlements paid on our commodity derivative instruments. Investing Activities . Net cash used in investing activities in the three months ended March 31, 2022 decreased as compared to the same period of 2021. The decrease was primarily due to cash received from the farmout of oil and natural gas properties in the three months ended March 31, 2022 compared to no cash received from the farmout of oil and natural gas properties in the same period of 2021. Financing Activities . Cash flows used in financing activities increased for the three months ended March 31, 2022 as compared to the same period of 2021. The increase was primarily due to higher distributions to unitholders and additional repayments on our line of credit in the three months ended March 31, 2022 as compared to the corresponding prior period. Development Capital Expenditures Our 2022 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.5 million, net of farmout reimbursements, of which $0.1 million has been invested in the three months ended March 31, 2022. The majority of this capital is anticipated to be spent for workovers and recompletions on existing wells in which we own a working interest. 28 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 March 31, 2022, we had outstanding borrowings of $69.0 million at a weighted-average interest rate of 2.94%. 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 October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million. The next semi-annual redetermination is scheduled for October 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, 2021 and March 31, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable margin for LIBOR ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base. 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 March 31, 2022, we were in compliance with all debt covenants. The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after June 30, 2023. Our Credit Facility uses the 1-month LIBOR setting and 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. 29 Contractual Obligations As of March 31, 2022, there have been no material changes to our contractual obligations previously disclosed in our 2021 Annual Report on Form 10-K. Critical Accounting Policies and Related Estimates As of March 31, 2022, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2021 Annual Report on Form 10-K.