MNRL Brigham Minerals, Inc. - 10-K

Item 1A.     Risk Factors

Summary of Risk Factors

An investment in our shares of Class A common stock involves a significant degree of risk. Below is a summary of certain risk factors that you should consider in evaluating us and our Class A common stock. However, this list is not exhaustive. Before you invest in our Class A common stock, you should carefully consider the risk factors discussed or referenced below and under Item 1A. “Risk Factors” in this Annual Report on Form 10-K. If any of the risks discussed below and under Item 1A. “Risk Factors” were actually to occur, our business, financial condition, results of operations and cash flows could be adversely affected and our results could differ materially from expected and historical results, and of which may also adversely affect the holders of our Class A common stock.

Risks Related to Our Business

• The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

• Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold.

• We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests.

• Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.

• Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

• Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

• We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.

• Acquisitions and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

• Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.

• We have little to no control over the timing of future drilling with respect to our mineral and royalty interests.

• Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.

• The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

• The marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators’ control.

• Our estimated reserves are based on many assumptions that may turn out to be inaccurate.

• If oil, natural gas and NGL prices decline significantly, we could be required to record additional impairments of our proved oil, natural gas and NGL properties that would constitute a charge to earnings and reduce our stockholders’ equity.

Risks Related to Environmental and Regulatory Matters

• Conservation measures, technological advances, general concern about the environmental impact of the production and use of fossil fuels and increasing attention to environmental, social and governance (“ESG”) matters could materially reduce demand for oil, natural gas and NGLs and adversely affect our results of operations, availability of capital and the trading market for shares of our Class A common stock.

• Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.

• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.

Risks Related to Our Financial and Debt Arrangements

• Our derivative activities could result in financial losses and reduce earnings.

• Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

Risks Related to Our Class A Common Stock

• Brigham Minerals is a holding company. Brigham Minerals’ sole material asset is its equity interest in Brigham LLC and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other overhead expenses and pay any dividends on our Class A common stock.

• The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

• If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

• Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

• Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Sponsors to benefit from corporate opportunities that might otherwise be available to us.

Risk Factors

The following are certain risk factors that affect our business, financial condition, results of operations and cash flows. Many of these risks are beyond our control. These risk factors are not exhaustive and investors are encouraged to perform their own investigation with respect to our business, financial condition and prospects. You should carefully consider the following risk factors in addition to the other information included in this Annual Report, including matters addressed under “Cautionary Statement Regarding Forward-Looking Statements.” If any of the events described below were to actually occur, our business, financial condition, results of operations and cash flows could be adversely affected, and our results could differ materially from expected and historical results, any of which may also adversely affect the holders of our Class A common stock.

Risks Related to Our Business

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. For example, the continuing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a disruption to the oil and natural gas industry and to our business. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. Furthermore, the COVID-19 pandemic has affected our operations by (i) rendering our personnel unable to access company facilities for an extended period of time, (ii) contributing to a steep decline in commodities prices in 2020, which reduced activity by our operators and the amounts of royalty payments we received, (iii) causing some of the Company’s operators to shut in and curtail production from wells on the Company’s properties for a period of time, (iv) limiting our access to the capital markets on terms favorable to us and adversely affected our capital resources and (v) reducing the level of potential acquisition opportunities we have been able to identify, limiting our ability to execute on our growth strategy of acquiring additional mineral and royalty interests. Additionally, the steps taken by national, state and local governments to curb the spread of the COVID-19 pandemic, including stay-at-home orders, quarantines, travel restrictions and business shutdowns, and the implications on our operators’ workforce of a COVID-19 infection, have limited our operators’ ability to maintain production from our properties. Such orders and the other impacts of the COVID-19 pandemic may have limited the ability of our operators to access our properties and maintain their existing production and development activities, and any similar or more restrictive measures taken in the future could have similar effects.

While our business and operations have experienced certain effects of the COVID-19 pandemic as described above, the full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to operating production activities by our operators and the impact of potential governmental restrictions on travel, transportation and operations. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations, financial results and dividend policy will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the pandemic, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. For example, there has been a recent significant increase in cases of COVID-19 in the U.S. that could lead to re-implementation of certain governmental restrictions. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests are sold. Prices of oil, natural gas and NGLs are volatile due to factors beyond our control. A significant drop in the price of oil or a substantial or extended decline in commodity prices in the future may adversely affect our business, financial condition or results of operations.

Our revenues, operating results, free cash flow and the carrying value of our mineral and royalty interests depend significantly upon the quantities of oil, natural gas and NGLs produced from our properties and the prevailing prices at which such production is sold. Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

• the domestic and foreign supply of and demand for oil, natural gas and NGLs;

• market expectations about future prices of oil, natural gas and NGLs;

• the level of global oil, natural gas and NGL exploration and production;

• the cost of exploring for, developing, producing and delivering oil, natural gas and NGLs;

• the price and quantity of foreign imports and U.S. exports of oil, natural gas and NGLs;

• the level of U.S. domestic production;

• the availability of storage for hydrocarbons;

• political and economic conditions in the U.S. and other oil producing regions, including the Middle East, Africa, South America and Russia;

• the ability of members of OPEC and other countries that produce oil, natural gas, and NGLs to agree to and maintain oil price and production controls;

• trading in oil, natural gas and NGL derivative contracts;

• the level of consumer product demand;

• weather conditions and natural disasters;

• technological advances affecting energy consumption, energy storage and energy supply;

• domestic and foreign governmental regulations and taxes;

• the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran;

• global or national health concerns, including health epidemics such as the ongoing COVID-19 pandemic;

• the proximity, cost, availability and capacity of oil, natural gas and NGL pipelines and other transportation facilities;

• the price and availability of alternative fuels; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, during the past five years, the posted price for WTI light sweet crude oil has ranged from a historic, record low price of negative $36.98 per barrel in April 2020 to a high of $85.64 per barrel in October 2021. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Certain actions by OPEC+ in the first half of 2020, combined with the impact of the continued outbreak of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the U.S., contributed to the historic low price for oil in April 2020. While the prices for oil have generally stabilized and also increased, such prices have historically remained volatile, which may adversely affect the prices at which production from our properties is sold as well as the production activities of operators on our properties. This, in turn, may materially affect the amount of royalty payments that we receive from such operators.

Any substantial decline in the price of oil, natural gas and NGLs or a prolonged period of low commodity prices will also materially adversely affect our business, financial condition, results of operations and free cash flow. In addition, the quantities of oil, natural gas and NGLs produced from our properties has a significant impact on our operating results and financial condition. Lower oil, natural gas and NGL prices may reduce the amount of oil, natural gas and NGLs that can be produced economically by our operators, which may reduce our operators’ willingness to develop and/or continue to produce our properties. For example, partially due to the decrease in prices for oil in 2020, many operators on our properties substantially reduced their development activities and capital expenditures in 2021. Additionally, lower commodity prices resulted in some of the Company's operators temporarily shutting in or curtailing production from wells on its properties during the second quarter of 2020.

A deterioration in commodity prices, decrease in production levels, or reduction in operator production activities may result in our having to make substantial downward adjustments to our estimated proved, probable or possible reserves. If this occurs or if production estimates change or exploration or development results deteriorate, the full cost method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. In addition, the borrowing base under our revolving credit facility is determined based on our estimated proved reserves, and any negative revisions to our estimated proved reserves would in turn reduce our borrowing base, reducing the amount available to fund our operations through borrowings under our revolving credit facility.

We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in 2020, many of our operators substantially reduced their development activities and capital expenditures in 2021. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may occur again in the future.

Our assets consist of mineral and royalty interests. Because we depend on third-party operators for all of the exploration, development and production on our properties, we have little to no control over the operations related to our properties. For the year ended December 31, 2021, we received revenues from over 178 operators with approximately 67% of our royalty revenues coming from the top ten operators on our properties, four of which each accounted for more than 10% of such royalty revenues. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Furthermore, in response to the significant decrease in prices for oil in 2020, many of our operators substantially reduced their development activities, capital expenditures, rig count and completion crews in 2021. Additionally, certain investors have requested operators adopt initiatives to return capital to investors, which could also reduce the capital available to our operators for investment in exploration, development and production activities. Our operators may further reduce capital expenditures devoted to exploration, development and production on our properties in the future, which could negatively impact revenues we receive. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may continue in the future, especially as a consequence of any reductions in operators’ capital expenditures. Moreover, over the last two years, many of our operators have announced that they plan to drill fewer wells per section than previously anticipated, due in part to greater well-interference between parent and child wells than previously anticipated and an increased focus on overall capital efficiency.

If production on our mineral and royalty interests decreases due to decreased development activities, as a result of the low commodity price environment, limited availability of development capital, production-related difficulties or otherwise, our results of operations may be adversely affected. For example, in 2020, the amount of royalty payments we received from our operators decreased due to the lower prices at which our operators were able to sell production from our properties and reduced production activities by our operators. Further, depressed commodity prices caused some of our operators to voluntarily shut in and curtail production from wells on our properties earlier in 2020. Although most of these have come back online, an additional or extended period of depressed commodity prices may cause additional operators to take similar action or even to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions, both of which would decrease the amount of royalty payments we receive from our operators. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states). Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that are largely outside of our control, including:

• the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;

• the ability of our operators to access capital;

• prevailing commodity prices;

• the operators' expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

• the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

• the availability of storage for hydrocarbons;

• the operators’ expertise, operating efficiency and financial resources;

• approval of other participants in drilling wells;

• the selection of technology;

• the selection of counterparties for the marketing and sale of production; and

• the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and free cash flow. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and free cash flow. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on our cash flows.

Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.

We depend partly on acquisitions to grow our reserves, production and free cash flow. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil, natural gas and NGL prices and their applicable differentials;

• development plans;

• the operating costs our operators would incur to develop and operate the properties; and

• potential environmental and other liabilities that operators of the properties may incur.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time as volatile commodity prices drive ever changing market dynamics, which can constrain our ability to capture these opportunities Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing. In addition, these acquisitions may be in geographic regions in which we do not currently hold properties, which could subject us to additional and unfamiliar legal and regulatory requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and free cash flow. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and free cash flow.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, any acquisition involves potential risks, including, among other things:

• the validity of our assumptions about estimated proved, probable and possible reserves, future production, prices, revenues, capital expenditures, the operating expenses and costs our operators would incur to develop the minerals;

• a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

• mistaken assumptions about the overall cost of equity or debt;

• our ability to obtain satisfactory title to the assets we acquire;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

• the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, inclement weather, regulatory changes and approvals, oil, natural gas and NGL prices, costs, drilling results and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Additionally, actual production from wells may be less than expected. For example, a number of operators have previously announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation and free cash flow.

Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our interpretation of such data. As a result, our operators may have reached different conclusions about the potential drilling locations on our properties, and our operators control the ultimate decision as to where and when a well is drilled.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. For example, certain of our operators have recently commenced bankruptcy proceedings under the Bankruptcy Code and their future operations and ability to make royalty payments to us may be adversely affected by such proceedings. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced. Additionally, in low commodity price environments, such as that experienced in 2020, some operators have attempted to make improper deductions by netting negative gas price realizations against positive oil royalties and other operators may attempt to do so in the future. We have taken action and will continue to take action to protect our rights; however, we cannot predict whether we will ultimately be successful.

Acquisitions and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures primarily with funding from capital contributions, cash generated by operations, proceeds from our IPO and from the December 2019 Offering and borrowings under our debt arrangements.

In the future, we may need capital in excess of the amounts we retain in our business or borrow under our revolving credit facility. The level of borrowing base available under our revolving credit facility is largely based on our estimated proved reserves and our lenders' price decks and will be reduced to the extent commodity prices decrease. Furthermore, we cannot assure you that we will be able to access other external capital on terms favorable to us or at all. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and free cash flow.

Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests may decline.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties. Unless we replace the oil, natural gas and NGLs produced from our properties, our results of operations and financial position could be adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil, natural gas and NGL reserves and our operators’ production thereof and our free cash flow are highly dependent on the successful development and exploitation of our current reserves and our ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire or develop additional reserves to replace the current and future production of our properties at economically acceptable terms. Aside from acquisitions, we have little to no control over the exploration and development of our properties. If we are not able to replace or grow our oil, natural gas and NGL reserves, our business, financial condition and results of operations would be adversely affected.

We have little to no control over the timing of future drilling with respect to our mineral and royalty interests.

As of December 31, 2021, only 28,911 MBoe of our total estimated reserves were proved developed reserves. The remaining 6,894 MBoe, 48,394 MBoe and 25,996 MBoe of our total estimated reserves as of December 31, 2021 were PUDs, probable undeveloped reserves and possible undeveloped reserves, respectively, and may not ultimately be developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of an undeveloped drilling location will be made by the operator and not by us. We generally do not have access to the estimated costs of development of these reserves or the scheduled development plans of our operators. The reserve data included in the reserve report audited by CG&A assumes that our operators must incur substantial capital expenditures to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved undeveloped reserves as unproved reserves.

Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and free cash flow may be adversely affected.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. In addition, the economy has begun to experience elevated inflation levels as a result of global supply and demand imbalances resulting from the ongoing COVID-19 pandemic, resulting in increased costs of the goods, services and labor used by our operators, which has increased their operating costs. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of, or an increase in costs for, drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.

The marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators' control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities, and the shipment of our or our operators’ oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and free cash flow. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation-including regulation of oil, natural gas and NGL production, transportation and pipeline safety-

as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil, natural gas and NGL reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGL prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved, probable and possible reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our estimates of proved, probable and possible reserves and related valuations as of December 31, 2021, 2020 and 2019 were audited by CG&A. CG&A conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. For example, due to the deterioration in commodity prices and operator activity in 2020 as a result of the COVID-19 pandemic and other factors, the commodity price assumptions used to calculate our reserves estimates declined, which in turn lowered our proved reserve estimates. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs that are ultimately recovered being different from our reserve estimates.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board, we base the estimated discounted future net cash flows from our proved reserves on the trailing twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our operators. Although we believe that our approach in making such determinations is conservative, the accuracy of any such determination is inherently uncertain and subject to a number of assumptions and factors outside of our control, including but not limited to those described under “We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in 2020, many of our operators substantially reduced their development activities and capital expenditures in 2021. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may occur again in the future.” Any significant variance between our estimates and the actual drilling schedules of our operators may require us to write down our proved undeveloped reserves.

If oil, natural gas and NGL prices decline significantly, we could be required to record additional impairments of our proved oil, natural gas and NGL properties that would constitute a charge to earnings and reduce our stockholders’ equity.

Accounting rules require that we review the carrying value of our oil, natural gas and NGL properties for possible impairment at the end of each quarter. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development activities, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of our proved oil, natural gas and NGL properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of our proved oil, natural gas and NGL reserves, the excess capitalized costs are charged to expense. Impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. The risk that we will be required to recognize impairments of our oil, natural gas and NGL properties increases during periods of low commodity prices, such as those experienced in 2020. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil, natural gas and NGL prices increase the cost center ceiling applicable to the subsequent period. If we incur impairment charges in the future, our results of operations for the periods in which such charges are taken may be materially and adversely affected.

The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and free cash flow could be adversely affected.

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities. In addition, our ORRIs may be lost if the underlying acreage is not drilled before the expiration of the applicable lease or if the lease otherwise terminates.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.

Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of our mineral interests expires or terminates, all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. If the lease underlying any of our ORRIs expires or terminates, our ORRIs that are derived from such lease will also

terminate. Any such expirations or terminations of our leases or our ORRIs could materially and adversely affect the growth of our financial condition, results of operations and free cash flow.

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition and results of operations.

The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our stockholders that wells drilled by the operators of our properties will be productive. Drilling for oil, natural gas and NGLs often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil, natural gas or NGLs to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil, natural gas or NGL is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

• unusual or unexpected geological formations;

• loss of drilling fluid circulation;

• title problems;

• facility or equipment malfunctions;

• unexpected operational events;

• shortages or delivery delays of equipment and services;

• compliance with environmental and other governmental requirements; and

• adverse weather conditions, including the prior winter storms in February 2021 that adversely affected operator activity and production volumes in the southern United States, including in the Permian Basin.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and free cash flow may be materially adversely affected.

Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and free cash flow.

The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of oil, natural gas and NGLs, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of oil, natural gas, NGLs and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators’ ability to succeed.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil, natural gas and NGLs, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and

NGL market prices. Our operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Furthermore, the oil and gas industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against our operators or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties. In addition, we face competition in identifying and acquiring additional properties and reserves. See “Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.”

Title to the properties in which we have an interest may be impaired by title defects.

We are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to examine the title to our royalty and mineral interests. In such cases, we would rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a specific royalty or mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and free cash flow. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. If there are any title defects in properties in which we hold an interest, we may suffer a financial loss.

We rely on a few key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Loss of our or our operators’ information and computer systems, including as a result of cyber attacks, could materially and adversely affect our business.

We and our operators rely on electronic systems and networks to control and manage our respective businesses. If any of such programs or systems were to fail for any reason, including as a result of a cyber attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences could be significant, including loss of communication links and inability to automatically process commercial transaction or engage in similar automated or computerized business activities. Although we have multiple layers of security to mitigate risks of cyber attacks, cyber attacks on business have escalated in recent years. Moreover, our operators are becoming increasingly dependent on digital technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating reserves. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. If our operators become the target of cyber attacks of information security breaches, their business operations may be substantially disrupted, which could have an adverse effect on our results of operations. In addition, our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring. Additionally, we regularly enter into transactions directly with individual mineral and royalty interest owners, who may have less sophisticated electronic systems or networks and may be more vulnerable to cyber-attacks. For example, in August 2021, an individual mineral owner’s email account was compromised, which resulted in a fraudulent payment of approximately $165,000 in connection with an acquisition. As a result of this incident, we have implemented formal procedures and controls to mitigate future occurrences of such incidents, but there can be no assurance that these efforts will be sufficient to prevent similar attacks or breaches from occurring in the future.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.

If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil, natural gas and NGLs, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil, natural gas and NGL related facilities could be direct targets of terrorist attacks, and, if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

A deterioration in general economic, business, political or industry conditions, such as those experienced in 2020, could materially adversely affect our results of operations, financial condition and free cash flow.

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to significantly reduced economic activity and diminished expectations for the global economy. Additionally, recent acts of protest and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply of crude oil in 2020 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of our operators to continue operations and ultimately materially adversely impact our results of operations, financial condition and free cash flow.

Risks Related to Environmental and Regulatory Matters

Conservation measures, technological advances and increasing attention to ESG matters could materially reduce demand for oil, natural gas and NGLs, availability of capital and adversely affect our results of operations and the trading market for shares of our Class A common stock.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGLs, technological advances in fuel economy and energy-generation devices could reduce demand for oil, natural gas and NGLs. The impact of the changing demand for oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and free cash flow.

It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own shares of our Class A common stock, adversely affecting the market price of our Class A common stock. For example, certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to divest from, or not provide funding to, the oil and gas sector based on their social and environmental considerations. Furthermore, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors and other financial institutions to inform their investment, financing and voting decisions, and unfavorable ESG ratings may lead to increased negative sentiment toward us from such institutions. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours and also adversely affect our availability of capital. Additionally, to the extent ESG matters negatively impact our or our operators’ reputation, we or our operators may not be able to compete as effectively to recruit or retain employees, which may adversely affect our or our operators’ operations.

Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.

Our operators’ operations on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and

pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil, natural gas and NGLs. In addition, the production, handling, storage and transportation of oil, natural gas and NGLs, as well as the remediation, emission and disposal of oil, natural gas and NGL wastes, by-products thereof and other substances and materials produced or used in connection with oil, natural gas and NGL operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker health and safety, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our operators, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operators’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control and waste management.

Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including, but not limited to:

• provisions related to the unitization or pooling of the oil and natural gas properties;

• the establishment of maximum rates of production from wells;

• the spacing of wells;

• the plugging and abandonment of wells; and

• the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations. For example, in November 2021, the Pipeline and Hazardous Materials Safety Administration issued a final rule significantly expanding reporting and safety requirements for operators of gas gathering pipelines, including previously unregulated pipelines. Compliance with such regulations may require increased capital costs for third-party oil, natural gas and NGL transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on our properties.

Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

Our operators may be required to make significant expenditures to comply with the laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. For example, following the election of President Biden and a Democratic majority in both houses of Congress, it is possible that our operators may continue to be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and GHG emissions. Please read “Item 1—Business—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production and may ultimately impact our operators’ ability and willingness to develop our properties.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.

Our operators engage in hydraulic fracturing, which is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the SDWA Underground Injection Control program and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to

require disclosure of the chemicals used in the hydraulic fracturing process. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though we cannot predict the extent of any such legislation at this time.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. In April 2019, Colorado adopted Senate Bill 19-181, which made sweeping changes in Colorado oil and gas law, including among other matters, requiring the COGCC to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. In keeping with SB 19-181, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions established more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminated routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. Additionally, on December 17, 2021, the Colorado Air Quality Control Commission adopted regulations aimed at curbing methane emissions from oil and gas operations to include setting methane emission limits per 1,000 Boe produced, more frequent inspections and limits on emissions during maintenance.

Separately, several state and federal agencies have examined a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. The United States Geological Survey has identified eight states, including Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. To that end, states in which some of our operators operate have introduced protocols or guidance regarding saltwater disposal wells. For example, in September 2021, the RRC issued a notice to operators in the Midland area to reduce saltwater disposal well actions and provide certain data to the commission. Subsequently, the RRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021. Separately, New Mexico has implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. As a result of these developments, our operators may be required to curtail operations or adjust development plans, which may adversely affect our business.

In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. In some instances, regulators may also order that disposal wells be shut in.

Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques in areas where we own mineral and royalty interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for our operators in the production of oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult for our operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in our operators’ completion of new oil and natural gas wells on our properties and an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations.

Restrictions on the ability of our operators to obtain water may have an adverse effect on our financial condition, results of operations and free cash flow.

Water is an essential component of deep shale oil, natural gas and NGL production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country, and in particular the western United States, have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be

exacerbated by climate change. If our operators are unable to obtain water to use in their operations from local sources, or if our operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil, natural gas and NGLs from our properties, which could have an adverse effect on our financial condition, results of operations and free cash flow.

A series of risks arising out of the threat of climate change could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the oil, natural gas and NGLs that our operators produce.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a result, our operations as well as the operations of our operators and our operators’ suppliers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirements, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule, and anticipates the issuance of a final rule by the end of the year. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement" requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions (“NDCs”) every five years after 2020. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at COP26, the United States and the European Union jointly announced the launch of a Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and our operators’ operations.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including action taken by President Biden with respect to his climate change related pledges. On January 27, 2021, President Biden issued an executive order that called for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also called for restrictions on leasing on federal land, including the Department of Interior’s publication of a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. Substantially all of our mineral interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of parties have sought to bring suit against

certain oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patters, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes.

Changes to applicable tax laws and regulations or exposure to additional income tax liabilities, including any future legislation that generally affects the taxation of natural gas and oil exploration and development companies such as our operators, could adversely affect our results of operation and free cash flow.

We are subject to various complex and evolving U.S. federal, state and local taxes. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us or our operators, in each case, possibly with retroactive effect, and may have an adverse effect on our business and future profitability. For example, several tax proposals have been set forth that would, if enacted, make significant changes to U.S. tax laws. Such proposals have included an increase in the U.S. federal income tax rate applicable to corporations (such as Brigham Minerals) from 21%, the imposition of a minimum tax on book income for certain corporations, the imposition of an excise tax on certain corporate stock repurchases that would be borne by the corporation repurchasing such stock, and the elimination of certain tax subsidies for fossil fuels. Congress could consider, and could include, some or all of these proposals in connection with tax reform that may be undertaken. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws could adversely affect us or our operators’ operations on the properties in which we hold interests, which, in turn, could adversely affect our results of operation and free cash flow.

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our operators’ ability to conduct drilling activities.

In the United States, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where our operators operate, our operators’ abilities to conduct or expand operations could be limited, or our operators could be forced to incur material additional costs. Moreover, our operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

In addition, as a result of one or more settlements approved by the FWS, the agency was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The FWS did not make that deadline; however, review is reportedly ongoing. The designation of previously unidentified endangered or threatened species-such as the dunes sagebrush lizard or greater sage grouse-could cause our operators’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. In June 2021, the FWS proposed to list two distinct population segments of the lesser prairie chicken, whose range extend to areas where we may hold mineral interests, under the ESA. The FWS and similar state agencies may also designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands, which may reduce the profitability of our interests to the extent they are associated with such designations.

Risks Related to Our Financial and Debt Arrangements

Our derivative activities could result in financial losses and reduce earnings.

From time to time in the past we have used, and in the future we may use, derivative instruments for a portion of our future oil, natural gas and NGL production, including fixed price swaps, collars and basis swaps, to mitigate the risk and resulting impact of commodity price volatility. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in oil, natural gas and NGL prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract. Further, our hedging activities are not likely to mitigate the entire exposure of our operations to commodity price volatility. We had no natural gas or oil derivative contracts in place as of December 31, 2021 and 2020. For the year ended December 31, 2019, we recorded a loss on commodity derivative instruments, net of $(0.6) million. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

The operating and financial restrictions and covenants in our revolving credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business activities or pay dividends. Our revolving credit facility restricts, and any future financing agreements likely will restrict, our ability to, among other things:

• incur indebtedness;

• issue certain equity securities, including preferred equity securities;

• incur certain liens or permit them to exist;

• engage in certain fundamental changes, including mergers or consolidations;

• make certain investments, loans, advances, guarantees and acquisitions;

• sell or transfer assets;

• enter into sale and leaseback transactions;

• pay dividends to or redeem or repurchase shares from our stockholders;

• make certain payments of junior indebtedness;

• enter into transactions with our affiliates;

• enter into certain restrictive agreements; and

• enter into swap agreements and hedging arrangements.

Our revolving credit facility restricts our ability to pay dividends to our stockholders or to repurchase shares of our Class A common stock. We also are required under our revolving credit facility to comply with, as of the most recently completed fiscal quarter, (i) a ratio of total net funded debt to consolidated EBITDA not to exceed 3.50 to 1.00, and (ii) a current ratio of not less than 1.00 to 1.00 and (iii) leverage (maximum 3.00x) and liquidity (minimum 10% of total revolving commitments) conditions with respect to the ability to pay dividends or distributions (other than permitted tax distributions). Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. If we violate any of the restrictions, covenants, ratios or tests in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to pay dividends to our stockholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders can seek to foreclose on our assets.

The borrowings under our revolving credit facility expose us to interest rate risk.

We are exposed to interest rate risk associated with borrowings under the our revolving credit facility. Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted London Inter-Bank Offered Rate ("LIBOR") rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. If interest rates increase, so will our interest costs, which may have a material adverse effect on our business, financial conditions and results of operations.

In 2017, the U.K. Financial Conduct Authority announced that it will no longer persuade or compel banks to submit LIBOR rates after 2021. At the end of 2021, the ICE Benchmark Administration (the current LIBOR administrator) ceased publishing one-week and two-month U.S. dollar LIBOR tenors and announced that it will cease publishing all remaining U.S. dollar LIBOR tenors in June 2023. The Federal Reserve Bank of New York, in conjunction with the Alternative Reference Rates Committee, has recommended that U.S. dollar LIBOR be replaced by the Secured Overnight Financing Rate (“SOFR”) SOFR is an overnight rate backed by U.S. Treasury, rather than a term rate, making it an inexact replacement for LIBOR. Whether or not SOFR or any other potential alternative reference rate attains market traction as a LIBOR replacement rate remains in question.

The current provisions in our revolving credit facility to change the benchmark rate for LIBOR loans from LIBOR to SOFR require calculations of a spread. Industry organizations are attempting to structure the spread calculation in a manner that

minimizes the possibility of value transfer between borrowers, lenders and contractual counterparties as a result of the switch to

SOFR, but there can be no assurance that the calculated spread will be fair and accurate. We cannot predict the effect of any such changes, any establishment of alternative reference rates or any other reforms that may be required and/or implemented given the developments with respect to LIBOR. The potential effect of the cessation of LIBOR or our future borrowing costs for any borrowings under our revolving credit facility cannot yet be determined

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our existing and future indebtedness could have important consequences to us, including:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us;

• covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

• our access to the capital markets may be limited;

• our borrowing costs may increase;

• we will need a substantial portion of our free cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payment of dividends to our stockholders; and

• our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Risks Related to Our Class A Common Stock

Brigham Minerals is a holding company. Brigham Minerals’ sole material asset is its equity interest in Brigham LLC and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other overhead expenses and pay any dividends on our Class A common stock.

Brigham Minerals is a holding company and has no material assets other than its equity interest in Brigham LLC. Please see “Item 1—Business—Overview—Our Corporate Structure.” Brigham Minerals has no independent means of generating revenue. To the extent Brigham LLC has available cash, Brigham LLC is required to make (i) pro rata distributions to all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities and (ii) non-pro rata payments to Brigham Minerals in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Brigham LLC, we will cause Brigham LLC to make pro rata distributions to all of its unitholders, including to Brigham Minerals, in an amount sufficient to allow us to fund dividends to our stockholders in accordance with our dividend policy, to the extent our Board of Directors declares such dividends. Therefore, although we have paid dividends to our stockholders in the past and expect to pay dividends on our Class A common stock in amounts determined from time to time by our Board of Directors in the future, our ability to do so may be limited to the extent Brigham LLC and its subsidiaries are limited in their ability to make these and other distributions to us, including due to the restrictions under our revolving credit facility. To the extent that we need funds and Brigham LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the New York Stock Exchange (the "NYSE"), with which we were not required to comply as a private company. Complying with these requirements occupies a significant amount of time of our Board of Directors and management and significantly increases our costs and expenses. We

are required to, among other things, institute a more comprehensive compliance function, comply with rules promulgated by the NYSE; prepare and distribute periodic public reports in compliance with federal securities laws; establish new internal policies, such as those relating to insider trading, and involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, we are required to comply with the provisions of Section 404 of the Sarbanes Oxley Act, including the requirement to have our independent registered public accounting firm attest to the effectiveness of our internal controls. Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, being a public company subject to these rules and regulations makes it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock .

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future, that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act, or that we will not identify material weaknesses related to our financial reporting. If one or more material weaknesses emerge related to financial reporting in the future, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our operating results and ability to meet our reporting obligations may be adversely affected and we may be subject to adverse regulatory consequences. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. See "Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures.”

Our Sponsors have the ability to direct the voting of a substantial portion of the voting power of our common stock, and their interests may conflict with those of our other stockholders.

Holders of shares of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation. As of December 31, 2021, our Sponsors beneficially own, on a combined basis, none of our outstanding shares of Class A common stock and approximately 45.5% of our shares of Class B common stock, representing 8.7% of our combined economic interest and voting power. As a result, this concentration of ownership allows our Sponsors to have significant influence over matters requiring stockholder approval, may deter hostile takeovers and may make it less likely that other holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of our Sponsors with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders.

Furthermore, we are party to a stockholders’ agreement with our Sponsors. The stockholders’ agreement provides each of our Sponsors with the right to designate a certain number of nominees to our Board of Directors, subject to certain ownership requirements in our common stock. Our Sponsors’ concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

Furthermore, while we believe that our Sponsor’s ownership interests in us provide them with an economic incentive to assist us to be successful, our Sponsors are not subject to any obligation to maintain their ownership interest in us. Our

Sponsors may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce their ownership interest in us, such as in the case of certain sales of our stock by our Sponsors in 2020 and 2021. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our business, financial condition and results of operations.

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including Pine Brook-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, one of our directors (Mr. Stoneburner) is a Managing Director of Pine Brook, which is in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. In addition, Mr. Brigham, our executive chairman, is involved with certain other entities involved in the oil and gas industry, including Brigham Exploration Company, Atlas Permian Water, Atlas Permian Sand, Brigham Development, Anthem Ventures, Langford Energy Partners I, LLC and Brigham Oil & Gas, L.P., and Mr. Langford, one of our directors, is also involved with entities involved in the oil and gas industry, including Langford Energy Partners I, LLC and Brigham Oil & Gas, L.P. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Item 13—Certain Relationships and Related Transactions, and Director Independence.”

Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Sponsors to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents provide that our Sponsors and their affiliates (including portfolio investments of our Sponsors and their affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and that we renounce any interest or expectancy in any business opportunity that may be from time to time presented to our Sponsors or their respective affiliates. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things:

• permits our Sponsors and their affiliates and our directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

• provides that if our Sponsors or their affiliates or any director or officer of one of our affiliates, our Sponsors or their affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our Sponsors or their affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our Sponsors and their affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Sponsors and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please see Exhibit 4.7 to this Annual Report on Form 10-K “Description of Brigham Minerals, Inc.’s Class A common stock.”

Each of our Sponsors is an established participant in the oil and natural gas industry and has resources greater than ours, which may make it more difficult for us to compete with our Sponsors with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand,

and our Sponsors, on the other hand, will be resolved in our favor. As a result, competition from our Sponsors and their affiliates could adversely impact our results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders;

• provide that the authorized number of directors constituting our Board of Directors may be changed only by resolution of the Board of Directors;

• provide that all vacancies, including newly created directorships, may, except as otherwise required by law, the terms of the stockholders’ agreement or, if applicable, the rights of holders of a series of our preferred stock, be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum;

• provide that our bylaws can be amended by the Board of Directors;

• provide that any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of our preferred stock with respect to such series;

• provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of not less than 66 2/3% of our then outstanding shares of common stock;

• provide that special meetings of our stockholders may only be called by our Board of Directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the Board of Directors serving at the time of such vote;

• provide for our Board of Directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms, other than directors that may be elected by holders of our preferred stock, if any;

• provide that the affirmative vote of the holders of not less than 66 2/3% in voting power of all then outstanding shares of common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office, and such removal may only be for “cause”; and

• prohibit cumulative voting on all matters.

Furthermore, the terms of our amended and restated certificate of incorporation and amended and restated bylaws are subject to the terms of the stockholders’ agreement. See “Item 13—Certain Relationships and Related Transactions, and Director Independence.”

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our amended and restated certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Our ability to pay dividends to our stockholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.

Brigham Minerals is a holding company and has no material assets other than its ownership of Brigham LLC Units, and Brigham Minerals does not have any independent means of generating revenue. To the extent Brigham LLC has available cash, Brigham LLC is required to make (i) pro rata distributions to all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities and (ii) non-pro rata payments to Brigham Minerals in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Brigham LLC, Brigham Minerals will cause Brigham LLC to make pro rata distributions to all of its unitholders, including to Brigham Minerals, in an amount sufficient to allow it to fund dividends to its stockholders in accordance with its dividend policy, to the extent its Board of Directors declares such dividends. Brigham LLC is a distinct legal entity and may be subject to legal or contractual restrictions that, under certain circumstances, may limit Brigham Minerals ability to obtain cash from it. If Brigham LLC is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect our free cash flow and financial position and our ability to fund any dividends.

Although we have paid dividends on our Class A common stock and expect to pay dividends on our Class A common stock in the future, our Board of Directors will take into account general economic and business conditions, including our financial condition and results of operations, capital requirements, contractual restrictions, including restrictions and covenants contained in our debt agreements, business prospects and other factors that our Board of Directors considers relevant in determining whether, and in what amounts, to pay such dividends. In addition, our revolving credit facility limits the amount of distributions that Brigham LLC can make to us and the purposes for which distributions could be made. Accordingly, we may not be able to pay dividends even if our Board of Directors would otherwise deem it appropriate. See “Item 5—Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy,” “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity” and Exhibit 4.7 to this Annual Report on Form 10-K, “Description of Brigham Minerals, Inc.’s Class A common stock.”

In certain circumstances, Brigham LLC will be required to make tax distributions to the Brigham Unit Holders, including Brigham Minerals, and such tax distributions may be substantial. To the extent Brigham Minerals receives tax distributions in excess of its actual tax liabilities and retains such excess cash, the Original Owners that hold Brigham LLC Units would benefit from such accumulated cash balances if they exercise their Redemption Right.

Pursuant to the Brigham LLC Agreement, to the extent Brigham LLC has available cash (taking into account existing and projected capital expenditures), Brigham LLC is required to make generally pro rata distributions (which we refer to as “tax distributions”), to all its unitholders, including Brigham Minerals, in an amount generally intended to allow the Brigham Unit

Holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that tax distributions will be made sufficient to allow Brigham Minerals to satisfy its actual tax liabilities. The amount of such tax distributions will be determined based on certain assumptions, including an assumed individual income tax rate, and will be calculated after taking into account other distributions (including other tax distributions) made by Brigham LLC. Because tax distributions will be made pro rata based on ownership and due to, among other items, differences between the tax rates applicable to Brigham Minerals and the assumed individual income tax rate used in the calculation and requirements under the applicable tax rules that Brigham LLC’s net taxable income be allocated disproportionately to its unitholders in certain circumstances, tax distributions may significantly exceed the actual tax liability for many of the Brigham Unit Holders, including Brigham Minerals. If Brigham Minerals retains the excess cash it receives, the Original Owners that hold Brigham LLC Units would benefit from any value attributable to such accumulated cash balances upon their exercise of the Redemption Right. However, we expect to use such accumulated cash balances to pay dividends in respect of our Class A common stock or to take other steps to eliminate any material cash balances. In addition, the tax distributions Brigham LLC will be required to make may be substantial and may exceed the tax liabilities that would be owed by a similarly situated corporate taxpayer. Funds used by Brigham LLC to satisfy its tax distribution obligations will not be available for reinvestment in our business, except to the extent Brigham Minerals uses the excess cash it receives to reinvest in Brigham LLC for additional units.

The U.S. federal income tax treatment of distributions on our Class A common stock to a holder will depend upon our tax attributes and the holder’s tax basis in our stock, which are not necessarily predictable and can change over time.

Distributions of cash or other property on our Class A common stock, if any, will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the holder’s tax basis in our Class A common stock and thereafter as capital gain from the sale or exchange of such common stock. Also, if any holder sells our Class A common stock, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A common stock.

To the extent that the amount of our distributions is treated as a non-taxable return of capital as described above, such distribution will reduce a holder’s tax basis in the Class A common stock. Consequently, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A common stock or subsequent distributions with respect to such stock. Additionally, with regard to U.S. corporate holders of our Class A shares, to the extent that a distribution on our Class A shares exceeds both our current and accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the corporate dividends-received deduction (to the extent it would otherwise be applicable to such holder) with respect to the gain resulting from such excess distribution.

Investors in our Class A common stock are encouraged to consult their tax advisors as to the tax consequences of receiving distributions on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.

Future sales of shares of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Certain of our Original Owners own shares of our Class A common stock and, subject to certain limitations and exceptions, the Original Owners that hold Brigham LLC Units may require Brigham LLC to redeem their Brigham LLC Units for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions), and our Original Owners may sell any of such shares of Class A common stock. As of February 18, 2022, we had outstanding 48,360,253 shares of Class A common stock and 11,371,517 shares of Class B common stock, representing approximately 19.0% of our total outstanding shares. The Sponsors are party to a registration rights agreement, which requires us to effect the registration of their shares in certain circumstances. See “Item1—Business—Overview—Our Corporate Structure” and “Item 13—Certain Relationships and Related Transactions, and Director Independence.”

We have previously filed a registration statement with the SEC on Form S-8 providing for the registration of 5,999,600 shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

Our organizational structure confers certain benefits upon the Original Owners that hold Brigham LLC Units that will not benefit the holders of our Class A common stock to the same extent as it will benefit those Original Owners.

Our organizational structure confers certain benefits upon the Original Owners that hold Brigham LLC Units that do not benefit the holders of our Class A common stock to the same extent as it will benefit those Original Owners. Brigham Minerals is a holding company and has no material assets other than its ownership of Brigham LLC Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock is subject to the ability of Brigham LLC to provide distributions to us. If Brigham LLC makes such distributions, the Original Owners that hold Brigham LLC Units will be entitled to receive equivalent distributions from Brigham LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Brigham LLC to the Original Owners on a per unit basis. This and other aspects of our organizational structure may adversely impact the future trading market for our Class A common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our Board of Directors to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our Class A common stock.

If securities or industry analysts adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

Item 7.     Management's Discussion and Analysis of Financial Condition and Results of Operations

Brigham Minerals, Inc. (the "Company," "we," "us," or "our") is the managing member of Brigham Minerals Holdings, LLC (“Brigham LLC”) and is responsible for all operational, management and administrative decisions related to Brigham LLC and its operating subsidiaries’ business. The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved, probable and possible reserves, mineral acquisition capital, economic and competitive conditions, including those resulting from the ongoing COVID-19 pandemic, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Item 1A—Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

Brigham Minerals was formed to acquire and actively manage a portfolio of mineral and royalty interests in the core of what we view as the most active, highly economic, liquids-rich resource plays across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our stockholders through (i) the growth of our free cash flow generated from our existing mineral portfolio and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. As of December 31, 2021, we owned 92,375 net royalty acres across 36 counties within the Delaware and Midland Basins in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota.

Financial and Operational Overview:

• Our production volumes decreased 5%, to 9,040 Boe/d (70% liquids, 51% oil), for the year ended December 31, 2021 as compared to the prior year.

• Our mineral and royalty revenues composed of crude oil, natural gas and NGL sales increased 82%, to $156.7 million, for the year ended December 31, 2021 as compared to the prior year.

• Our net income for the year ended December 31, 2021 was $68.0 million. Our net loss for the twelve months ended December 31, 2020 was $58.0 million. Adjusted Net Income for December 31, 2020 was $7.1 million, excluding an after-tax impairment to oil and gas properties of $65.1 million. Adjusted EBITDA and Adjusted EBITDA ex lease bonus increased 103% to $132.3 million, and 115% to $127.8 million, respectively, for the year ended December 31, 2021 as compared to the prior year. Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP financial measures. For a definition of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation to our most directly comparable measure calculated and presented in accordance with GAAP, please read "How We Evaluate Our Operations—Adjusted EBITDA and Adjusted EBITDA Ex Lease Bonus."

• As of December 31, 2021, Brigham Minerals had a cash balance of $20.8 million and $137.0 million of capacity on our revolving credit facility, providing the Company with total liquidity of $157.8 million.

• On February 18, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.45 per share of Class A common stock payable on March 25, 2022 to stockholders of record at the close of business on March 18, 2022. This brings the total capital returned to stockholders related to financial results from fiscal year 2021 to $1.52 per share

2021 Acquisition

On December 15, 2021, Rearden Minerals, LLC, ("Rearden"), a wholly owned subsidiary of Brigham Minerals, acquired certain mineral and royalty assets in the DJ Basin from Principle Energy, LLC and Regal Petroleum LLC (D/B/A Regal Royalty, LLC), in each case, an unrelated seller (collectively, the “Sellers”). Upon closing of the acquisition, the Company and Rearden delivered to the Sellers $43.1 million of cash consideration, net of $1.7 million of customary closing adjustments and 2,180,128 shares of the Company’s Class A common stock. The combined cash consideration and acquisition shares issued totaled $89.4 million.

Market Environment and COVID-19

The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, remains a global pandemic, however, with the gradual easing of COVID-19 lockdown restrictions globally, primarily due to the increase in accessibility of vaccines and demand for the commodities produced by the oil and natural gas industry have continued to improve. In addition, commodity prices have continued to improve substantially from historic lows in 2020 and the current outlook on commodity prices is generally favorable. However, the duration of COVID-19 pandemic and potential future impact to our business and industry continues to be unpredictable and dynamic.

In connection with the previously mentioned COVID-19 pandemic and resulting market and commodity price challenges experienced during 2020, we saw reduced levels of potential acquisition opportunities. With an improvement in commodity prices in 2021 and into 2022, along with our financial strength, we believe we are well positioned to capture attractive opportunities that will generate stockholder value. Given that our capital allocation is within our control, we believe that the liquidity provided by our cash flow from operations, proceeds from portfolio rationalizations and borrowings under our revolving credit facility will provide us with sufficient capital to execute our current strategy.

Operational Update

Mineral and Royalty Interest Ownership Update

During the year ended December 31, 2021, the Company completed 62 ground game transactions and one marketed transaction in the DJ Basin acquiring 6,090 net royalty acres (standardized to a 1/8th royalty interest) net of asset sales. The aggregate consideration paid for new assets in 2021 was approximately $150.3 million, including the equity consideration for the DJ Basin acquisition. The Company deployed approximately 35% of its mineral acquisition capital in 2021 to the Permian Basin (18% Delaware and 17% Midland), 1% to the Williston Basin and 64% to the DJ Basin. The acquired minerals are expected to deliver near-term production and cash flow growth with the addition of 231 gross DUCs (3.0 net DUCs) and 292 gross permits (2.2 net permits) to our inventory counts. As of December 31, 2021, the Company owned roughly 92,375 net royalty acres, encompassing 12,220 gross (109.4 net) undeveloped horizontal locations, across 36 counties in what the Company views as the cores of the Delaware and Midland Basins in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota.

The table below summarizes the Company’s mineral and royalty interest ownership as of the dates indicated and changes in such ownership on an annual basis.

Delaware

Midland

SCOOP

STACK

Williston

Other

Total

Net Royalty Acres

December 31, 2021

December 31, 2020

Acres Added & (Sold) in 2021

% Added & (Sold) in 2021

Operating Activity Update

DUC Conversions

In 2021, the Company identified approximately 495 gross DUCs (2.2 net DUCs) converted to production, representing 69% of its gross DUC inventory (60% of its net DUCs) as of year-end 2020. 2021 conversions of gross wells by status are summarized in the graph below:

Drilling Activity

During 2021 the Company saw 656 gross (5.0 net) wells spud on its acreage position as of December 31, 2021. 60% of gross (75% net) wells spud were in the Permian Basin, with 34% gross (35% net) wells spud in the Delaware Basin and 26% gross (40% net) wells spud in the Midland Basin:

DUC and Permit Inventory

The Company expects any near-term production growth will be driven by the continued conversion of its DUC and permit inventory. Brigham’s DUC and permit inventory as of December 31, 2021 by basin is outlined in the table below:

Development Inventory by Basin (1)

Delaware

Midland

SCOOP

STACK

Williston

Other

Total

Gross Inventory

DUCs

Permits

Net Inventory

DUCs

Permits

(1) Individual amounts may not total due to rounding.

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, natural gas and NGLs produced;

• number of rigs on location, permits, spuds, completions and wells turned-in-line;

• commodity prices; and

• Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus.

Volumes of Oil, Natural Gas and NGLs Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various resource plays that comprise our portfolio of mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Number of Rigs on Location, Permits, Spuds, Completions and Wells Turned-In-Line

In order to track and assess the performance of our assets, we monitor and analyze the number of permits, rigs, spuds, completions and wells on production that are applicable to our mineral and royalty interests in an effort to evaluate near-term production growth from the various basins and resource plays that comprise our asset base.

Commodity Prices

Historically, oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a historic, record low price of negative $36.98 per barrel in April 2020 to a high of $85.64 per barrel in October 2021. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. As of December 31, 2021, the posted price for oil was $75.33 per barrel and the Henry Hub spot market price of natural gas was $3.82 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically as well as the amount of capital they are willing to spend.

The prices we receive for oil, natural gas and NGLs vary by geographical area. The relative prices of these products are determined by factors affecting global and regional supply and demand dynamics, such as economic and geopolitical conditions, the effects of health pandemics such as COVID-19, production levels, availability of transportation and storage, weather cycles and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.

Oil . The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude 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 crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Natural Gas . The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that 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 is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

Oil and Gas Properties

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax effects (full cost ceiling limitation). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. A ceiling limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using an unweighted arithmetic average of oil prices ("SEC oil price") and natural gas prices ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, adjusted by area for energy content, transportation fees and regional price differentials, as required under the guidelines established by the SEC. As of December 31, 2021, 2020 and 2019, the SEC gas prices were $66.56, $39.57, and $55.65, respectively, per barrel for oil, adjusted by area for energy content, transportation fees and regional price differentials, and the SEC gas prices were $3.64, $2.00, and $2.60, respectively, per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. As a result of the decline in the SEC oil prices and SEC gas prices during the twelve months ended December 31, 2020, and taking into consideration certain reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020, as a result of a slowdown in operator activity, the net book value of oil and natural gas properties exceeded the ceiling limitation as of September 30, 2020 and December 31, 2020, resulting in an impairment charge of $79.6 million to oil and gas properties, net during the year ended December 31, 2020. There were no impairment charges during the years ended December 31, 2021 and 2019.

A significant and prolonged decline in the SEC oil price or the SEC gas price could cause many of our operators to reduce substantially their development activities and capital expenditures, which could lead to additional impairment charges in the future and such impairment charges could be material. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact the amount of any impairment charge. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development activities, production data, economics and other factors, we may be required to write down the carrying value of our properties in future periods. The risk that we will be required to recognize impairments of our oil, natural gas and NGL properties increases during sustained periods of low

commodity prices. In addition, impairments could occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. If we incur impairment charges in the future, our results of operations for the periods in which such charges are taken may be materially and adversely affected.

Hedging

We may enter into certain derivative instruments to partially mitigate the impact of commodity price volatility on our cash flow 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 cash flows we ultimately realize. Historically, we have only entered into minimal 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. 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 may partially mitigate the effect of lower prices on our future revenue.

Our revolving credit facility allows us to hedge up to 85% of our reasonably anticipated projected production from our proved reserves of oil and natural gas, calculated separately, for up to 60 months in the future. We had no natural gas or oil derivative contracts in place as of December 31, 2021 and 2020. For the year ended December 31, 2019, we recorded a loss on commodity derivative instruments, net of $0.6 million.

Non-GAAP Financial Measures

Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.

We define Adjusted Net Income as Net Income (Loss) before impairment of oil and gas properties, after tax, and loss on extinguishment of debt, after tax. We define Adjusted EBITDA as Adjusted Net Income before depreciation, depletion and amortization, share based compensation expense, interest expense, gain or loss on derivative instruments and income tax expense, less other income. We define Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to eliminate the impacts of lease bonus and other revenues we receive due to the unpredictability of timing and magnitude of the revenue.

Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus do not represent and should not be considered alternatives to, or more meaningful than, net income or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus have important limitations as analytical tools because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our computation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus to the most directly comparable GAAP financial measure for the periods indicated.

Years Ended December 31,

(In Thousands)

Reconciliation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus to Net Income (Loss):

Net Income (Loss)

Add:

Impairment of oil and gas properties, after tax (1)

Loss on extinguishment of debt, after tax (2)

Adjusted Net Income

Add:

Depreciation, depletion, and amortization

Share-based compensation expense

Interest expense, net

Loss on derivative instruments, net

Income tax expense

Less:

Other income, net

Adjusted EBITDA

Less:

Lease bonus and other revenues

Adjusted EBITDA ex lease bonus

(1) Tax effect of $14.4 million tax benefit for the year ended December 31, 2020.

(2) Tax effect of $0.8 million tax benefit for the year ended December 31, 2019.

Sources of Our Revenues

Our revenues are primarily derived from the mineral and royalty payments we receive from our operators based on the sale of oil, natural gas and NGLs produced from our properties, as well as from lease bonus payments. Mineral and royalty revenues may vary significantly from period to period as a result of changes in volumes of production sold by our operators, production mix and commodity prices. Lease bonus and other revenues vary from period to period as a result of leasing activity on our mineral interests.

The following table presents the breakdown of our revenues for the following periods:

Years Ended December 31,

Royalty revenues

Oil sales

Natural gas sales

NGL sales

Total royalty revenues

Lease bonus and other revenues

Total revenues

Principle Components of Our Cost Structure

The following is a description of the principle components of our cost structure. However, as an owner of mineral and royalty interests, we are not obligated to fund drilling and completion capital expenditures to bring a horizontal well on line, lease operating expenses to produce our oil, natural gas and NGLs nor the plugging and abandonment costs at the end of a well’s economic life. All the aforementioned costs are borne entirely by the exploration and production companies that have leased our mineral and royalty interests.

Gathering, Transportation and Marketing Expenses

Gathering, transportation and marketing expenses include the costs to process and transport our production to applicable sales points. Generally, the terms of the lease governing the development of our properties permits the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

Severance and Ad Valorem Taxes

Severance taxes are paid on sold oil, natural gas or NGLs based on either a percentage of revenues from production sold or the number of units of production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues, which is driven by our production volumes and prices received for our oil, natural gas and NGLs. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the state or local government’s appraisal of the value of our oil, natural gas and NGL properties, which also trend with anticipated production, as well as oil, natural gas and NGL prices. Rates, methods of calculating property values and timing of payments vary across the different counties in which we own mineral and royalty interests.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire evaluated oil and natural gas properties. We use the full cost method of accounting, and, as such, all acquisition-related costs to acquire evaluated properties are capitalized and amortized in aggregate based on the estimated economic productive lives of our properties. Depletion is the expense recorded based on the cost basis of our properties and the volume of hydrocarbons extracted during each respective period, calculated on a units-of-production basis. Estimates of proved reserves are a major component of our calculation of depletion. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports. The year-end reserve reports are audited by CG&A.

General and Administrative

General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our staff, share-based compensation expense, costs of maintaining our headquarters, costs of managing our properties, annual and quarterly reports to stockholders, tax return preparation, independent and internal auditor fees, investor relations activities, incremental director and officer liability insurance costs, independent director compensation, other fees for professional services and legal compliance.

Interest Expense

We finance a portion of our working capital requirements and acquisitions with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest and loan commitment fees paid to the lenders under our debt arrangements (currently, our revolving credit facility) and amortization of debt issuance costs in interest expense.

Income Tax Expense

Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of up to 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A portion of our mineral and royalty interests are located in Texas basins.

Results of Operations

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

The following table provides the components of our revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes:

Years Ended December 31,

(Dollars in Thousands, Except for Realized Prices)

Variance

Production

Oil (MBbls)

Natural gas (MMcf)

NGLs (MBbls)

Equivalents (MBoe)

Equivalents per day (Boe/d)

Revenues

Oil sales

Natural gas sales

NGL sales

Total mineral and royalty revenues

Lease bonus and other revenue

Total revenue

Realized prices, without derivatives:

Oil ($/Bbl)

Natural gas ($/Mcf)

NGLs ($/Bbl)

Equivalents ($/Boe)

Operating expenses

Gathering, transportation and marketing

Severance and ad valorem taxes

Depreciation, depletion, and amortization

Impairment of oil and gas properties

General and administrative (before share-based compensation)

Total operating expenses (before share-based compensation)

General and administrative, share-based compensation

Total operating expenses

Other expense

Interest expense, net

Unit Expenses ($/Boe)

Gathering, transportation and marketing

Severance and ad valorem taxes

Depreciation, depletion, and amortization

General and administrative (before share-based compensation)

General and administrative, share-based compensation

Interest expense, net

*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300.

Revenues

Total revenues for the year ended December 31, 2021 increased by 76%, or $69.5 million, compared to the year ended December 31, 2020. The increase was attributable to a $70.5 million increase in mineral and royalty revenues during the period, partially offset by a $1.0 million decrease in lease bonus revenue. The increase in mineral and royalty revenues was primarily the result of an increase in realized commodity prices of 91% resulting in a $74.7 million increase in mineral and royalty revenues. A decrease in drilling and completion activity on our mineral and royalty interests during the year ended December 31, 2021 compared to the year ended December 31, 2020, partially offset by acquisitions of proved developed producing reserves resulted in a 5% decrease in production volumes to 9,040 Boe/d and a corresponding decrease in mineral and royalty revenues of $4.2 million. The decrease in production volumes was primarily due to the reduction in drilling activity which started during the second quarter of 2020 associated with COVID-19 and the OPEC + production dispute as well as Winter Storm Uri's February 2021 production curtailments.

Oil revenues for the year ended December 31, 2021 increased by 63%, or $42.9 million, compared to the year ended December 31, 2020. The increase in oil revenues was primarily attributable to the 77% increase in realized oil price to $66.08 per barrel resulting in an increase in revenue of $48.3 million. An 8% decrease in oil production volumes to 4,594 barrels per day resulted in a $5.4 million decrease in oil revenues, net of $0.5 million in oil revenues from the DJ Acquisition.

Natural gas revenues for the year ended December 31, 2021 increased by 159%, or $16.6 million compared to the year ended December 31, 2020. The increase in natural gas revenues was primarily attributable to a 156% increase in realized natural gas price to $4.60 per Mcf resulting in an increase in revenue of $16.4 million as well as a $0.2 million increase of natural gas revenues from the DJ Acquisition.

NGL revenues for the year ended December 31, 2021 increased by 139%, or $10.9 million compared to the year ended December 31, 2020. The increase in NGL revenues was primarily attributable to the 153% increase in NGL prices to $29.35 per barrel resulting in an increase in revenue of $11.4 million. A 6% decrease in NGL volumes to 1,759 Boe/d resulted in a $0.4 million decrease in NGL sales, net of NGL revenues from the DJ Acquisition of $0.2 million, was primarily attributable to a decrease in drilling and completion activities on our properties in the Permian Basin, the Anadarko Basin and the Williston Basin.

Lease Bonus and Other Revenues

When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenues for the year ended December 31, 2021 decreased by 18%, or $1.0 million compared to the year ended December 31, 2020. The decrease in revenues from lease bonus payments is primarily attributable to a $2.2 million decrease in leasing activity in the Permian Basin partially offset by the $0.8 million and $0.4 million increases in leasing activity in the DJ and Anadarko Basins, respectively. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.

Operating and other expenses

Gathering, transportation, and marketing expenses. For the year ended December 31, 2021 decreased by 2%, or $0.2 million, as compared to the year ended December 31, 2020, which was largely driven by the 5% decrease in our production volumes.

Severance and ad valorem taxes. For the year ended December 31, 2021 increased by 66%, or $3.7 million, as compared to the year ended December 31, 2020, primarily due to the 82% increase in mineral and royalty revenues which was primarily due to an increase in realized commodity prices of 91%, partially offset by a 5% decrease in production volumes.

Depreciation, depletion and amortization . For the year ended December 31, 2021 decreased by 24%, or $11.6 million, compared to the year ended December 31, 2020, which was primarily due to a decrease in depletion expense of $10.9 million. Lower production volumes decreased our depletion expense by $2.3 million, and a lower depletion rate decreased our depletion expense by $8.6 million. The depletion rate was $11.05 per Boe and $13.63 per Boe for the years ended December 31, 2021 and 2020, respectively. The decrease in the depletion rate was a result of the impairment charge of $79.6 million for the year ended December 31, 2020, resulting in lower depletable cost (or amortizable base) in the calculation of the depletion rate for the year ended December 31, 2021. In addition, an increase in total proved reserves of 43% from December 31, 2020 to December 31, 2021, which was primarily a result of acquisitions and 68% higher SEC oil price and 82% higher SEC gas prices, contributed to the decrease in depletion rate. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.

Impairment . In determining the full cost ceiling impairment at December 31, 2021, we estimated the PV-10 of our total proved oil and natural gas reserves using the SEC oil price and the SEC gas price of $66.56 per Bbl and $3.64 per MMBtu, respectively. There was no impairment for the year ended December 31, 2021. As of September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and gas properties exceeded the full cost ceiling limitation primarily due to the decline in oil and gas prices and reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020 as a result of a slowdown in operator activity. As a result, we recorded impairments of our oil and gas properties, net of $79.6 million for the year ended December 31, 2020. In determining the full cost ceiling impairment at December 31, 2020, we estimated the PV-10 of our total proved oil and natural gas reserves using the SEC oil price and the SEC gas price of $39.57 per Bbl and $2.00 per MMBtu, respectively, which is a decrease of 29% and 23%, respectively, from the December 31, 2019 SEC oil price and SEC gas price of $55.65 per Bbl and $2.60 per MMBtu, respectively.

General and administrative before share-based compensation. For the year ended December 31, 2021 decreased by 9% or $1.3 million, compared to the year ended December 31, 2020. Decreases to G&A expense are a result of a $2.0 million decrease in incremental legal, professional, and tax fees, partly due to the absence of equity offerings in 2021, partially offset by $0.2 million increase in rent expense and $0.3 million increase in salary and compensation expense.

Share-based compensation . For the year ended December 31, 2021 share-based compensation expense was $9.7 million, net of $3.6 million of share-based compensation expense capitalized to unevaluated property and $4.4 million of share-based compensation expense capitalized to evaluated property. Share-based compensation expense for the year ended December 31, 2020 was $7.5 million, net of $3.0 million of share-based compensation expense capitalized to unevaluated property and $3.1 million of share-based compensation cost capitalized to evaluated property. The increase in share-based compensation expense of $2.2 million was primarily due to additional RSU and PSU grants made during the year ended December 31, 2021. See table below and "Note 10—Share-Based Compensation" to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion.

Years Ended December 31,

(In Thousands)

Variance

Incentive Units

RSAs

RSUs

PSUs

Capitalized share-based compensation

Total share-based compensation expense

Interest expense, net for the year ended December 31, 2021 increased by 91%, or $0.8 million, compared to the year ended December 31, 2020 due to higher average outstanding borrowings and higher average interest rates. See table below and “Note 6—Long-Term Debt” and “Note 1—Business and Basis of Presentation” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion of this transaction.

Years Ended December 31,

(In Thousands, Except for Interest Rate)

Variance

Interest expense - Revolving credit facility

Commitment fees

Amortization of loan closing costs

Interest income

Total interest expense, net

Total weighted average interest rate

Total weighted average debt balance

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

The following table provides the components of our revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes:

Years Ended December 31,

(Dollars in Thousands, Except for Realized Prices)

Variance

Production

Oil (MBbls)

Natural gas (MMcf)

NGLs (MBbls)

Equivalents (MBoe)

Equivalents per day (Boe/d)

Revenues

Oil sales

Natural gas sales

NGL sales

Total mineral and royalty revenues

Lease bonus and other revenues

Total revenue

Realized prices, without derivatives:

Oil ($/Bbl)

Natural gas ($/Mcf)

NGLs ($/Bbl)

Equivalents ($/Boe)

Realized prices, with derivatives(1):

Oil ($/Bbl)

Equivalents ($/Boe)

Operating expenses

Gathering, transportation and marketing

Severance and ad valorem taxes

Depreciation, depletion, and amortization

Impairment of oil and gas properties

General and administrative (before share-based compensation)

Total operating expenses (before share-based compensation)

General and administrative, share-based compensation

Total operating expenses

Other income (expense)

(Loss) gain on derivative instruments, net

Loss on extinguishment of debt

Interest expense, net

Total other income (expense), net

Unit Expenses ($/Boe)

Gathering, transportation and marketing

Severance and ad valorem taxes

Depreciation, depletion, and amortization

General and administrative (before share-based compensation)

General and administrative, share-based compensation

Interest expense, net

(1) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300.

Revenues

Total revenues for the year ended December 31, 2020 decreased by 10%, or $9.8 million, compared to the year ended December 31, 2019. The decrease was attributable to a $11.6 million decrease in mineral and royalty revenues during the period, partially offset by a $1.8 million increase in lease bonus revenue. The decrease in mineral and royalty revenues was primarily the result of a decrease in realized commodity prices of 31% resulting in a $39.3 million decrease in mineral and royalty revenues. This was partially offset by an increase in drilling and completion activity on our mineral and royalty interests, and to a lesser degree by acquisitions of proved developed producing reserves, which resulted in a 28% increase in production volumes to 9,483 Boe/d and a corresponding increase in mineral and royalty revenues of $27.7 million.

Oil revenues for the year ended December 31, 2020 decreased by 17%, or $14.1 million, compared to the year ended December 31, 2019. The decrease in oil revenues was primarily attributable to the 31% decrease in realized oil price to $37.26 per barrel resulting in a decrease in revenue of $30.8 million. This was partially offset by a 20% increase in oil production volumes to 4,980 barrels per day resulting in a $16.7 million increase in oil revenues. The increase in oil production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in the Permian Basin, and to a lesser degree by acquisitions of proved developed producing reserves.

Natural gas revenues for the year ended December 31, 2020 increased by 7%, or $0.7 million compared to the year ended December 31, 2019. The increase in natural gas revenues was primarily attributable to the 23% increase in natural gas production volume to 15,871 Mcf/d resulting in a $2.3 million increase in natural gas sales. The increase in natural gas production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in the Permian Basin, and to a lesser degree by acquisitions of proved developed producing reserves. This was partially offset by a 13% decrease in realized natural gas price to $1.80 per Mcf resulting in a decrease in revenue of $1.6 million.

NGL revenues for the year ended December 31, 2020 increased by 29%, or $1.8 million compared to the year ended December 31, 2019. The increase in NGL revenues was primarily attributable to the 67% increase in NGL volumes to 1,858 Boe/d resulting in a $4.1 million increase in NGL sales was primarily attributable to increased drilling and completion activities on our properties in the Permian Basin, and to a lesser degree by acquisitions of proved developed producing reserves. This was partially offset by a 23% decrease in NGL prices to $11.61 per barrel resulting in a decrease in revenue of $2.3 million.

Lease bonus revenues for the year ended December 31, 2020 increased by 51%, or $1.8 million compared to the year ended December 31, 2019. The increase was primarily attributable to an increase in leasing activity on our interests in Texas, partially offset by a decrease in leasing activity in Colorado and Oklahoma. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.

Operating and other expenses

Gathering, transportation, and marketing expenses for the year ended December 31, 2020 increased by 40%, or $2 million, as compared to the year ended December 31, 2019, which was largely driven by the 28% increase in our production volumes as well as an increase in gathering, transportation and marketing rates.

Severance and ad valorem taxes for the year ended December 31, 2020 decreased by 13%, or $0.8 million, as compared to the year ended December 31, 2019, primarily due to the 12% decrease in mineral and royalty revenues.

DD&A expense for the year ended December 31, 2020 increased by 56%, or $17.3 million, compared to the year ended December 31, 2019, which was primarily due to an increase in depletion expense of $17.0 million. Higher production volumes increased our depletion expense by $8.6 million, and a higher depletion rate increased our depletion expense by $8.4 million. The depletion rate was $13.63 per Boe and $11.22 per Boe for the years ended December 31, 2020 and 2019, respectively. The increase in the depletion rate was a result of recent acquisition efforts focused on largely de-risked acreage with an increased likelihood of near-term production and development, as well as reclassification of proved undeveloped reserves to probable and possible reserves due to changes in assumptions of the development timing as a result of reduced activity by our operators. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.

As of September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and gas properties exceeded the full cost ceiling limitation primarily due to the decline in oil and gas prices and reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020 as a result of a slowdown in operator activity. As a result, we recorded impairments of our oil and gas properties, net of $79.6 million for the year ended December 31, 2020. In determining the full cost ceiling impairment at December 31, 2020, we estimated the PV-10 of our total proved oil and natural gas reserves using the SEC oil price and the SEC gas price of $39.57 per Bbl and $2.00 per MMBtu, respectively, which is a decrease of 29% and 23%, respectively, from the December 31, 2019 SEC oil price and SEC gas price of $55.65 per Bbl and $2.60 per MMBtu, respectively. No impairment charge was recorded for the year ended December 31, 2019.

G&A before share-based compensation for the year ended December 31, 2020 increased by 18%, or $2.2 million, compared to the year ended December 31, 2019. Increases to G&A expense are a result of: (i) $0.7 million in incremental legal, professional, audit, and tax fees as a result of the Company's June 2020 Secondary Offering and September 2020 Secondary Offering, (ii) $0.5 million in additional rent expense, (iii) $0.4 million of incremental directors and officers insurance expenses, and (iv) $0.3 million of additional salaries due to an increase in headcount.

Share-based compensation expense for the year ended December 31, 2020 decreased by 25%, or $2.5 million compared to the year ended December 31, 2019. The decrease in share-based compensation expense was due to a cumulative effect adjustment of $5.2 million pertaining to the period from the grant date to the IPO, which consists of a $2.0 million cumulative effect adjustment related to the estimated fair value of the Incentive Units and a $3.2 million cumulative effect adjustment related to the estimated fair value of the RSAs, partially offset by share-based compensation expense related to awards granted during the year ended December 31, 2020. Brigham Minerals capitalizes a portion of the share-based compensation expense incurred after the IPO. See table below and "Note 10—Share-Based Compensation" to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion.

Years Ended December 31,

(In Thousands)

Variance

Incentive Units

RSAs

RSUs

PSUs

Capitalized share-based compensation

Total share-based compensation expense

Interest expense, net for the year ended December 31, 2020 decreased by 84%, or $4.7 million, compared to the year ended December 31, 2019 due to lower average outstanding borrowings and lower average interest rates. For the year ended December 31, 2020, our weighted average debt outstanding on our revolving credit facility was $2.8 million compared to our weighted average debt outstanding on our credit facilities of $55.0 million for the year ended December 31, 2019. Our weighted average interest was 1.91% and 7.29% for the years ended December 31, 2020 and 2019, respectively. In December 2019, a portion of the net proceeds received from the December 2019 Offering were used to fully repay the outstanding borrowings under our revolving credit facility. See table below and “Note 1—Business and Basis of Presentation” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion of this transaction.

Years Ended December 31,

(In Thousands, Except for Interest Rate)

Variance

Interest expense - credit facilities

Commitment fees

Amortization of loan closing costs

Interest income

Total interest expense, net

Total weighted average interest rate

Total weighted average debt balance

Loss on extinguishment of debt. We recognized a loss on extinguishment of debt of approximately $6.9 million for the year ended December 31, 2019. The loss on extinguishment of debt consisted of a $4.0 million write-off of capitalized debt issuance costs, a $2.1 million prepayment fee and legal fees of $0.8 million.

Loss on derivative instruments, net. Brigham Minerals did not have any derivative contracts in place as of December 31, 2020 and 2019. Prior to December 31, 2019, we had certain oil swap contracts based on the NYMEX futures index. For the year ended December 31, 2019, we recognized a loss on derivative instruments, net of $0.6 million, which is attributable to oil derivative instruments. We realized $0.5 million of gains on our settled derivative instruments during the year ended December 31, 2019.

Factors Affecting the Comparability of Our Results of Operations to Our Historical Results of Operations

Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.

Corporate Reorganization and Transactions

The historical consolidated financial statements included in this Annual Report for periods on or before April 23, 2019 are based on the financial statements of Brigham Resourcse, LLC, our predecessor, and Brigham Minerals prior to our corporate reorganization consummated in connection with our IPO. As a result, such historical consolidated financial data may not give you an accurate indication of what our actual results would have been if the corporate reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

In April 2019, Brigham Minerals completed the IPO of 16,675,000 shares of Class A common stock at a price to the public of $18.00 per share. As a result of the IPO, Brigham Minerals became a holding company whose sole material asset consisted of a 43.3% interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to wholly own the Minerals Subsidiaries, which own all of Brigham Resources’ operating assets. In connection with the IPO, Brigham Minerals became the sole managing member of Brigham LLC and is responsible for all operational, management and administrative decisions relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its wholly-owned subsidiary, Brigham Resources.

On December 16, 2019, Brigham Minerals completed an offering of 12,650,000 shares of its Class A common stock (the "December 2019 Offering"), including 6,000,000 shares issued and sold by Brigham Minerals and an aggregate of 6,650,000 shares sold by certain stockholders of the Company, of which 5,496,813 represents shares issued upon redemption of an equivalent number of their Brigham LLC units, at a price to the public of $18.10 per share.

On June 12, 2020, Brigham Minerals completed an offering of 6,600,000 shares of its Class A common stock (the "June 2020 Secondary Offering"), all of which were sold by certain stockholders of the Company (the “June 2020 Selling Stockholders”), and 4,872,669 of which represented shares issued upon redemption of an equivalent number of the June 2020 Selling Stockholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $13.75 per share. Brigham Minerals did not sell any shares of its common stock in the June 2020 Secondary Offering and did not receive any proceeds pursuant to the June 2020 Secondary Offering.

On September 15, 2020, Brigham Minerals completed an offering of 5,021,140 shares of its Class A common stock, including 654,931 shares issued pursuant to the option granted to the underwriter to purchase additional shares to cover over-allotments (the "September 2020 Secondary Offering"), all of which were sold by certain stockholders of the Company (the "September 2020 Selling Stockholders"), and 3,062,011 of which represented shares issued upon redemption of an equivalent number of the September 2020 Selling Stockholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $8.20 per share. Brigham Minerals did not sell any shares of its Class A common stock in the September 2020 Secondary Offering and did not receive any proceeds pursuant to the September 2020 Secondary Offering. In addition, in connection with the September 2020 Secondary Offering, Brigham Minerals repurchased 436,630 shares of its Class A common stock from the September 2020 Selling Stockholders in a privately negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from the September 2020 Selling Stockholders in the September 2020 Secondary Offering (and Brigham LLC redeemed a corresponding number of Brigham LLC Units held by Brigham Minerals). The repurchased shares are presented in the Company's consolidated balance sheet as Treasury Stock, at cost.

As of December 31, 2021, Brigham Minerals owned a 81.0% interest in Brigham LLC and the Original Owners owned 19.0% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Company's Original Owners, collectively owned 8.7% of the outstanding voting stock of Brigham Minerals as of December 31, 2021. Yorktown ceased to be an affiliate of the Company on January 20, 2022 in connection with the resignation of W. Howard Keenan, Jr. from the Board of Directors.

The corporate reorganization that was completed contemporaneously with the closing of the IPO provided a mechanism by which the Brigham LLC Units to be allocated amongst the Original Owners, including the holders of our management incentive units, was determined. As a result, the satisfaction of all conditions relating to the vesting of certain management incentive units held in Brigham Equity Holdings, LLC (“Brigham Equity Holdings”) by our management and employees became probable. Accordingly, at IPO, we recognized a cumulative effect adjustment to share-based compensation expense of approximately $2.0 million pertaining to the period from the grant date through the IPO date, related to the estimated fair value

of the Incentive Units (as defined in “Note 10—Share-Based Compensation—LLC Incentive Units” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report) at grant, all of which was non-cash.

Income Taxes

Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Our predecessor was treated as a flow-through entity, and is currently treated as a disregarded entity, for U.S. federal income tax purposes and, as such, is generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income is passed through to its members, including Brigham Minerals. Accordingly, the financial data of our predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas).

Capital Requirements and Sources of Liquidity

Our current primary sources of liquidity are cash flows from operations, asset sales, borrowings under our revolving credit facility and proceeds from any primary issuances of equity securities. Future sources of liquidity may also include other credit facilities or increases to our current revolving credit facility we may enter into in the future and additional issuances of debt or equity securities. Even with the gradual easing of lockdown restrictions globally and the increase in commodities prices in 2021, COVID-19 remains a global pandemic. As a result, our revenues and cash flows from operations may be negatively impacted and we may not have access to capital markets on terms favorable to us or at all.

Our primary uses of capital are for the payment of dividends to our stockholders for investing in our business, specifically the acquisition of additional mineral and royalty interests and for repaying amounts borrowed under our revolving credit facility. As discussed above, COVID-19 remains a global pandemic. Our cash flows from operations may be negatively impacted, and as a result, the dividend amount we are able to pay our stockholders may be negatively impacted.

As a mineral and royalty interest owner, we incur the initial cost to acquire our interests, but thereafter do not incur any development capital expenditures or lease operating expenses, which are entirely borne by the operator. As a result, the vast majority of our capital expenditures are related to our acquisition of additional mineral and royalty interests. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operations, investing and financing activities and our ability to assimilate acquisitions. For the year ended December 31, 2021, we deployed approximately $158.4 million for acquisition-related capital expenditures, inclusive of a $8.0 million capitalized share-based compensation expense and $46.3 million of equity. In addition to acquisitions, we have certain contractual long-term capital requirements associated with the our office lease and with our revolving credit facility. See "Note 8 – Leases” and "Note 7 – Long-Term Debt” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report. We periodically assess changes in current and projected free cash flows, acquisition and divestiture activities, debt requirements and other factors to determine the effects on our liquidity. Based upon our current oil, natural gas and NGL price expectations for the year ended December 31, 2022, we believe that our retained cash flow from operations, lease bonus, portfolio optimization activities and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through additional borrowings, joint venture partnerships, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us.

Our liquidity was as follows:

(In Millions)

December 31, 2021

Cash and cash equivalents

Revolving credit facility availability

Total Liquidity

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $33.1 million as of December 31, 2021, as compared to $22.6 million at December 31, 2020. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant.

When new wells are turned to sales, our collection of receivables has lagged approximately six months from initial production as operators complete the division order process, at which point we are paid in arrears and then kept current. Our cash and cash equivalents balance totaled $20.8 million and $9.1 million at December 31, 2021 and December 31, 2020, respectively. The increase in cash and cash equivalents was primarily due to increase in cash provided by operating activities, borrowings from our revolving credit facility and sales of mineral and royalty interests offset primarily by acquisitions made and payment of dividends to our stockholders and distributions to the holders of non-controlling interest s during the year ended December 31, 2021. See "Note 4—Acquisitions and Divestitures" to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion. We expect that our cash flows from operations and additional borrowings under our revolving credit facility will be sufficient to fund our working capital needs. We expect that the pace of our operators’ drilling and completion of our undeveloped locations, production volumes, commodity prices and differentials to WTI and Henry Hub prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.

Dividends

The following table sets forth information with respect to cash dividends declared by our Board of Directors during 2021:

Declaration Date

Record Date

Payment Date

Dividend Amount

Dividends Paid

(In Thousands) (1)

February 24, 2021

March 19, 2021

March 26, 2021

May 6, 2021

May 21, 2021

May 28, 2021

August 4, 2021

August 20, 2021

August 27, 2021

November 3, 2021

November 24, 2021

December 1, 2021

Total:

(1) Dividends paid to holders of Class A common stock.

Our current dividend structure, implemented during the third quarter of 2021, consists of a base dividend of $0.14 per share of Class A common stock plus a variable dividend. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board of Directors. Our Board of Directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our results of operations, financial condition, capital requirements, contractual restrictions, credit agreement restrictions, restrictions imposed by applicable law and other factors that the Board of Directors deems relevant at the time of such determination. See "Item 5—Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy" for further discussion of our dividend policy.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

Years Ended December 31,

(In Thousands)

Net cash provided by operating activities

Net cash used in investing activities

Net cash (used in)/provided by financing activities

Analysis of Cash Flow Changes Between the Years Ended December 31, 2021 , 2020 and 2019

Net cash provided by operating activities

Net cash provided by operating activities is primarily affected by production volumes, the prices of oil, natural gas and NGLs, lease bonus revenue and changes in working capital. The increase in net cash provided by operating activities for the year ended December 31, 2021 as compared to the year ended December 31, 2020 is primarily due to 91% increase in realized commodity prices partially offset by the 5% decrease in production volumes and an increase in operating expenses during these periods discussed above. The increase in net cash provided by operating activities for the year ended December 31, 2020 as compared to the year ended December 31, 2019 is primarily due to improved collections of receivables and reduced payments for interest and income taxes, partly offset by increased payments for operating expenses.

Net cash used in investing activities

Net cash used in investing activities is primarily composed of acquisitions of mineral and royalty interests, net of dispositions. For the year ended December 31, 2021, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $103.5 million, offset by sales of mineral and royalty interests totaling $13.6 million.

For the year ended December 31, 2020, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $66.5 million and other fixed assets totaling $0.5 million, offset by sales of mineral and royalty interests totaling $1.6 million.

For the year ended December 31, 2019, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $219.5 million and additions to other fixed assets of $0.4 million, offset by sales of mineral and royalty interests totaling $3.1 million.

Net cash (used in)/provided by financing activities

Net cash used in financing activities for the year ended December 31, 2021 was primarily a result of dividends paid to holders of our Class A common stock of $60.6 million, distributions to holders of non-controlling interest of $17.9 million, partial repayment of our revolving credit facility of $4.0 million, payment of employee tax withholding for settlement of equity compensation awards of $1.1 million and payments of loan closing costs of $0.7 million, related to the December 15, 2021 borrowing base redetermination. This was partially offset by borrowings under our revolving credit facility of $77.0 million.

Net cash used in financing activities for the year ended December 31, 2020 was primarily due to the dividends paid to holders of our Class A common stock of $42.2 million, distributions to holders of temporary equity (or non-controlling interest as of February 19, 2021) of $24.7 million, and the repurchase of shares of our Class A common stock from the September 2020 Selling Stockholders for an aggregate purchase price of approximately $3.5 million, partially offset by borrowings under our revolving credit facility of $20.0 million.

Net cash provided by financing activities for the year ended December 31, 2019 included the combined net proceeds generated from the IPO and December 2019 Offering of $379.8 million offset by the combined full repayment of the outstanding long-term debt of $175.0 million (net of additional borrowings of $105.0 million incurred during the year), dividends paid to holders of our Class A common stock of $14.7 million, distributions to holders of temporary equity of $20.1 million, payment of debt extinguishment fees of $2.1 million and payment of loan closing costs of $1.3 million.

Revolving Credit Facility

On May 16, 2019 (the “closing date”), Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A., as administrative agent for the various lenders from time to time party thereto, providing for a revolving credit facility (our “revolving credit facility”). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is collateralized by a lien on substantial portion of Brigham Resources and its domestic subsidiaries’ assets, including substantial portion of their respective royalty and mineral properties.

Availability under our revolving credit facility is governed by a borrowing base, which is subject to redetermination semi-annually in May and November of each year. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. Brigham Resources can also request one additional redetermination each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time. The weighted average interest rate for the year ended December 31, 2021 was 2.31%. As of December 31, 2021, the elected borrowing base on our revolving credit facility was $230.0 million, with outstanding borrowings of $93.0 million, resulting in $137.0 million availability for future borrowings.

Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions.

Our revolving credit facility matures on May 16, 2024. Loans drawn under our revolving credit facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full the commitments under our revolving credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our revolving credit facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

A complete list of our significant accounting policies are described in the notes to our audited consolidated financial statements for the year ended December 31, 2021 included elsewhere in this Annual Report.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.

Our consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGL reserves that are the basis for the calculations of DD&A and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are audited by CG&A, an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, share-based compensation expenses, and revenue accruals.

Accounts Receivable

Receivables consist of mineral and royalty revenues due from operators for their oil and gas sales to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Receivables from third parties for which we did not receive actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. Volume estimates for wells with available historical actual data are based upon (i) the historical actual data for the months the data is available, or (ii) engineering estimates for the months the historical actual data is not available. We do not recognize revenues for wells with no historical actual data because we cannot conclude that it is probable that a significant revenue reversal will not occur in future periods. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.

We routinely review outstanding balances, assess the financial strength of our operators and record a reserve for amounts not expected to be fully recovered, using a current expected credit loss model. We recorded credit losses of $0.5 million, $0.3 million and $0.6 million for the years ended December 31, 2021, 2020 and 2019, respectively, which was included in general and administrative expenses.

Oil and Gas Properties

We use the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition costs incurred for the purpose of acquiring mineral and royalty interests and certain related employee costs are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred.

Capitalized costs are amortized using the units-of-production method. Under this method, the provision for depletion is calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by the net equivalent proved reserves at the beginning of the period.

Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated properties primarily consist of acquisition and leasehold costs and capitalized interest. Unevaluated properties are assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. There was no impairment recorded for unevaluated properties for the years ended December 31, 2021, 2020 and 2019.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.

Natural gas volumes are converted to Boe at the rate of six thousand Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax effects (full cost ceiling limitation). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. A ceiling limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using the unweighted arithmetic average of oil price ("SEC oil price") and natural gas price ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, as required under the guidelines established by the SEC. As of December 31, 2021, 2020 and 2019, the SEC oil prices were $66.56, $39.57, and $55.65, respectively, per barrel for oil, further adjusted by area for energy content, transportation fees and regional price differentials and the SEC gas prices were $3.64, $2.00, and $2.60, respectively, per MMBtu for natural gas, further adjusted by area for energy content, transportation fees and regional price differentials. As a result of the decline in the SEC oil prices and SEC gas prices during the twelve months ended December 31, 2020, and taking into consideration certain reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020, as a result of a slowdown in operator activity, the net book value of oil and natural gas properties exceeded the ceiling limitation as of September 30, 2020 and December 31, 2020, resulting in an impairment charge of $79.6 million to oil and gas properties, net during the year ended December 31, 2020. There were no impairment charges during the years ended December 31, 2021 and 2019.

Future significant and prolonged declines in the unweighted arithmetic average SEC oil prices used in the full cost ceiling test may cause many of our operators to reduce substantially their development activities and capital expenditures, which could result in additional impairment charges in the future and such impairments could be material. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact the amount of any impairment charge.

We engage CG&A, our independent petroleum engineering firm, to audit our total estimated proved, probable and possible reserves. We expect proved, probable and possible reserve estimates will change as additional information becomes available and as commodity prices and costs change. We evaluate and estimate our proved, probable and possible reserves internally each quarter and CG&A audits our proved, probable and possible reserves annually. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The estimates of proved, probable and possible reserves are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, historical and future operator development plans, and property ownership interests. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, which are considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, are also used.

As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.

It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Revenue from Contracts with Customers

It should not be assumed that the standardized measure included in this report as of December 31, 2021 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2021 standardized measure on the SEC oil price and SEC gas price as of December 31, 2021, and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1—Business—Oil, Natural Gas, and NGLs Data—Proved, Probable and Possible Reserves” and “Item 1A—Risk Factors” for additional information regarding estimates of proved, probable and possible reserves.

Mineral and Royalty Revenues

Mineral and royalty revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that we will receive for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.

Lease bonus and other income

We earn revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease bonus revenue by leasing our mineral interests to exploration and production companies. A lease agreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. We recognize lease bonus revenues when the lease agreement has been executed, payment has been received, and we have no further obligation to refund the payment. At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that we have not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606.

Share-Based Compensation

Brigham Minerals accounts for its share-based compensation, including grants of the Incentive Units, restricted stock awards, time-based restricted stock units and performance-based stock units, in the consolidated statements of operations based on their estimated fair values at grant date. Brigham Minerals uses a Monte Carlo simulation to determine the fair value of performance-based stock units. Brigham Minerals recognizes expense on a straight-line basis over the vesting period of the respective grant, which is generally the requisite service period. Brigham Minerals capitalizes a portion of the share-based compensation expense to oil and gas properties on the consolidated balance sheets. Share-based compensation expense is included in general and administrative expenses in Brigham Minerals’ consolidated statements of operations included within this Annual Report. There was approximately $16.5 million of unamortized compensation expense relating to outstanding awards at December 31, 2021, a portion of which will be capitalized. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards. Brigham Minerals accounts for forfeitures as they occur.

Income Taxes

Brigham Minerals accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be

recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets, including net operating losses. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends and our outlook for future years.

Temporary Equity

Brigham Minerals accounted for the Original Owners’ 23.2% interest in Brigham LLC as of December 31, 2020 as temporary equity as a result of certain redemption rights held by the Original Owners as discussed in “Note 9—Temporary Equity and Non-controlling Interest” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report. As such, Brigham Minerals adjusted temporary equity to its maximum redemption amount at the balance sheet date, if higher than the carrying amount. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of Class A shares at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to additional paid-in capital. Temporary equity is reclassified to permanent equity (i) upon Conversion of Class B common stock (and an equivalent number of Brigham LLC Units) to Class A common stock, or (ii) when holders of Class B common stock no longer control a majority of the votes of the Board of Directors through direct representation on the Board of Directors, and no longer control the determination of whether to make a cash payment upon a Brigham Unit Holder's exercise of its Redemption Right.

As a result of the appointment of an additional independent member to our Board of Directors on February 19, 2021, the holders of Class B common stock no longer hold a majority of the votes of the Board of Directors and no longer control the Board of Directors through direct representation on the Board of Directors. Consequently, after February 19, 2021, Class B common stock is presented as non-controlling interest (as discussed below) in the consolidated balance sheets of Brigham Minerals.

Non-Controlling Interest

As of February 19, 2021 and thereafter, the holders of Class B common stock no longer control a majority of the votes of the Company's Board of Directors through direct representation on the Board of Directors, and no longer control the determination of whether to make a cash payment upon each holder of Brigham LLC Unit's (each a "Brigham LLC Unit Holder") exercise of its Redemption Right (as hereinafter defined). As such, at December 31, 2021, Brigham Minerals accounts for Brigham LLC Unit Holders' 19.0% interest in Brigham LLC not owned by Brigham Minerals as non-controlling interest. For further discussion, see “Note 9—Temporary Equity and Non-controlling Interest.”

Recently Issued Accounting Pronouncements

None that are expected to have a material impact.

Off-Balance Sheet Arrangements

As of December 31, 2021, we did not have any material off-balance sheet arrangements.