BRIGHAM MINERALS, INC. Brigham Minerals, Inc. (the "Company," "we," "us," or "our") is the managing member ofBrigham Minerals Holdings, LLC ("Brigham LLC ") and is responsible for all operational, management and administrative decisions related toBrigham LLC and its operating subsidiaries' business. The following discussion and analysis should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year endedDecember 31, 2021 (the "Annual Report"), as well as the accompanying unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q (this "Quarterly 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 and the current conflict betweenRussia andUkraine , regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report and in our Annual Report, particularly in "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. OverviewBrigham 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 continentalUnited 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 ofJune 30, 2022 , we owned 81,810 net royalty acres across 36 counties within theDelaware and Midland Basins inWest Texas andNew Mexico , theAnadarko Basin inOklahoma , theDenver -Julesburg ("DJ") Basin inColorado andWyoming and theWilliston Basin inNorth Dakota .
Financial and Operational Overview:
•Our production volume of 13,019 Boe/d (72% liquids, 52% oil) for the three months endedJune 30, 2022 increased 8% compared to the three months endedMarch 31, 2022 . Our production volume of 12,528 Boe/d (71% liquids, 51% oil) for the six months endedJune 30, 2022 increased 40% compared to the six months endedJune 30, 2021 . •Our mineral and royalty revenues composed of crude oil, natural gas and NGL sales of$90.4 million for the three months endedJune 30, 2022 increased 29% compared to the three months endedMarch 31, 2022 due to an 18% increase in realized commodity pricing and 8% higher production volumes. Our mineral and royalty revenues of$160.4 million for the six months endedJune 30, 2022 increased 132% compared to the six months endedJune 30, 2021 due to a 66% increase in realized commodity pricing and a 40% increase in production volumes. •Our net income was$50.2 million for the three months endedJune 30, 2022 compared to$39.1 million for the three months endedMarch 31, 2022 . Our net income was$89.2 million for the six months endedJune 30, 2022 compared to$27.4 million for the six months endedJune 30, 2021 . •Adjusted EBITDA and Adjusted EBITDA ex lease bonus were$79.7 million and$79.2 million , respectively, for the three months endedJune 30, 2022 and increased 31% and 34%, respectively, as compared to the three months endedMarch 31, 2022 . Adjusted EBITDA and Adjusted EBITDA ex lease bonus were$140.4 million and$138.4 million , respectively, for the six months endedJune 30, 2022 and increased 143% and 150%, respectively, as compared to the six months endedJune 30, 2021 . Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP financial measures. For a definition of 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-Non-GAAP Financial Measures."
•On
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•As of
Market Environment, COVID-19 and
The ongoing global spread of coronavirus (SARS-Cov-2), which causes COVID-19, remains a global pandemic, however, demand for the commodities produced by the oil and natural gas industry and commodity prices have continued to improve substantially from historic lows in 2020. However, the duration of the 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. Additionally, inFebruary 2022 ,Russia invadedUkraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. The current conflict betweenRussia andUkraine may also have the effect of heightening many of the risks disclosed in our Annual Report, any of which could have a material adverse effect on our business and results of operations. Such risks include, but are not limited to, adverse effects on global macroeconomic conditions, increased volatility in the price and demand for oil and natural gas, and disruptions in global supply chains. Inflationary pressures and the effects of rising interests rates specifically, could hurt the financial and operating results of our operators' businesses. If our operators are unable to secure the goods, services and labor necessary for their operations at reasonable costs, their exploration and development activities could be delayed or restricted, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow. 22
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Operational UpdateMineral and Royalty Interest Ownership Update
During the second quarter 2022, the Company completed 20 ground game transactions acquiring approximately 885 net royalty acres (standardized to a 1/8th royalty interest) and deploying$33.2 million in capital. The Company deployed all of its mineral acquisition capital in the second quarter to thePermian Basin . As ofJune 30, 2022 , the Company owned roughly 81,810 net royalty acres, encompassing 11,290 gross (90.4 net) undeveloped horizontal locations, across 36 counties in what the Company views as the cores of theDelaware and Midland Basins inWest Texas andNew Mexico , theAnadarko Basin inOklahoma , theDJ Basin inColorado andWyoming and theWilliston Basin inNorth Dakota . The Company also divested 12,550 net royalty acres in theAnadarko Basin generating$67.3 million in cash proceeds, net of customary closing adjustments. This disposition consisted primarily of undeveloped Probable and Possible reserves and represented approximately 4% of Proved reserves and 13% of total Proved, Probable and Possible reserves, in aggregate, based on our audited reserve report as ofDecember 31, 2021 .
The table below summarizes the Company's mineral and royalty interest ownership at the dates indicated.
Delaware Midland Anadarko DJ Williston Total
Net Royalty Acres
June 30, 2022(1) 30,010 9,015 9,850 24,755 8,180 81,810
March 31, 2022 29,875 8,265 22,400 24,740 8,185 93,465
Acres Added and (Sold) Q/Q 135 750 (12,550) 15 (5) (11,655)
% Added and (Sold) Q/Q -% 9% (56)% -% -% (12)%
(1)
Operating Activity Update
DUC Conversions
The Company identified approximately 223 gross (2.4 net) DUCs converted to
production during the second quarter 2022, which represented 33% of its net DUCs
(24% of its gross DUCs) in inventory as of first quarter 2022. Second quarter
2022 gross DUC and PDP conversion waterfalls are summarized in the charts below:
[[Image Removed: mnrl-20220630_g1.jpg]]
[[Image Removed: mnrl-20220630_g2.jpg]]
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Drilling Activity
During the second quarter 2022, the Company identified 253 gross (1.5 net) wells
spud on its mineral position, which represents a 6% increase in gross well
drilling activity relative to first quarter 2022. Brigham's gross and net wells
spud activity per quarter is summarized in the chart below:
[[Image Removed: mnrl-20220630_g3.jpg]]DUC and Permit Inventory
Brigham Minerals ended the second quarter 2022 with 6.8 net DUCs and 4.2 net permits versus 7.1 net DUCs and 4.6 net permits as of first quarter 2022.Brigham Minerals' gross and net DUC and permit inventory as ofJune 30, 2022 by basin is outlined in the table below: Development Inventory by
Basin (1)
Delaware Midland Anadarko DJ Williston Total
Gross Inventory
DUCs 231 373 35 205 164 1,008
Permits 274 146 5 173 186 784
Net Inventory
DUCs 2.1 1.9 0.1 2.3 0.4 6.8
Permits 2.0 0.7 - 1.1 0.4 4.2
(1) Individual amounts may not total due to rounding.
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Regulatory Update
OnJuly 9, 2020 , theU.S. Supreme Court ruled in McGirt v. Oklahoma that theMuscogee (Creek) Nation reservation inEastern Oklahoma has not been disestablished. Although the Court's ruling indicates that it is limited to criminal law as applied within theMuscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within theMuscogee (Creek) Nation reservation, as well as other reservations inOklahoma that may similarly be found to not have been disestablished. State district courts inOklahoma , applying the analysis inU.S. Supreme Court's ruling regarding theMuscogee (Creek) Nation , have ruled that theCherokee , Chickasaw,Seminole ,Quapaw andChoctaw reservations likewise have not been disestablished. Other nations, such as the Osage Nation, have also sought to have findings of disestablishment overturned. While we cannot predict the full extent to which civil jurisdiction may be affected, the ruling could adversely affect title to our mineral interests, to the extent they are found to be located within reservation areas, and significantly impact laws and regulations to which we and our operators and interests are subject inOklahoma , such as taxation, environmental regulation, and the permitting and siting of energy assets. OnOctober 1, 2020 , theEnvironmental Protection Agency (the "EPA ") granted approval to theState of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the "SAFETE Act") to administer all of the State's existingEPA -approved regulatory programs to many areas of Indian Country withinOklahoma , effectively extendingOklahoma's authority for existingEPA -approved regulatory programs to lands withinOklahoma previously under the jurisdiction of the State before theU.S. Supreme Court's ruling in McGirt. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and, inDecember 2021 , theEPA proposed to withdraw and reconsider theOctober 2020 decision. TheEPA also sought public comment on the proposed withdrawal and reconsideration with a deadline ofJanuary 31, 2022 . Additionally, the SAFETE Act provides that any Tribe inOklahoma may seek "Treatment as a State" by theEPA , and it is possible that one or more of the Tribes inOklahoma may seek such an approval from theEPA . Separately, in 2021, theU.S. Department of the Interior subsequently used the ruling in McGirt to find thatOklahoma could not keep jurisdiction over surface coal mining on theMuscogee (Creek) Nation's lands. TheState of Oklahoma petitioned theU.S. Supreme Court to overturn this determination and find that McGirt either is limited to federal criminal matters or was incorrectly decided. InJune 2022 , theSupreme Court ruled that the federal government and the state have concurrent jurisdiction to prosecute crimes committed by non-Native Americans against tribal members on reservation land. Several other suits have been filed in state and federal courts regarding the appropriate scope of McGirt, including a stayed proceeding before theOklahoma Supreme Court regarding theOklahoma Corporation Commission's authority to issue drilling permits on the Muscogee (Creek) reservation. At this time, we cannot predict how these state and federal court issues may ultimately be resolved following theSupreme Court's decision. We will continue to monitor developments concerning these matters.
Dakota Access Pipeline ("DAPL")
OnJuly 6, 2020 , theU.S. District Court for the District of Columbia ordered vacatur of DAPL's easement from the "Corps" and further ordered the shutdown of the pipeline byAugust 5, 2020 while the Corps completes a full environmental impact statement for the project. OnJanuary 26, 2021 , theCourt of Appeals for the District of Columbia affirmed the vacatur of the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access filed its reply. OnMay 21, 2021 , the District Court denied the Plaintiff's request for an injunction and, onJune 22, 2021 , terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. Following the denial of a rehearing en banc, onSeptember 20, 2021 , Dakota Access filed a petition with theU.S. Supreme Court to hear the case. OnFebruary 22, 2022 , theU.S. Supreme Court declined to consider Dakota Access' appeal. The pipeline continues to operate pending completion of the Environmental Impact Statement, the release of which is paused at the request of the Assistant Secretary of the Army for Civil Works to engage with theStanding Rock Sioux Tribe to understand concerns expressed in theirJanuary 2022 letter formally withdrawing as a cooperating agency. We cannot determine when or how future lawsuits will be resolved or the impact they may have on the DAPL. If future legal challenges to DAPL are successful, transportation costs for crude oil will likely increase in theWilliston Basin , and the operators of our properties in theWilliston Basin may choose to shut in wells if they are unable to connect those wells to other pipelines or obtain sufficient capacity on other pipelines at an effective cost, both of which may adversely impact our revenues and future production from our properties in theWilliston Basin . 25 -------------------------------------------------------------------------------- Table of Contents Implementation of Colorado SB 19-181 ("SB 181") InNovember 2020 , theColorado Oil and Gas Conservation Committee ("COGCC"), as part of SB 181's mandate for the COGCC to prioritize public health and environmental concerns in its decisions, adopted revisions, effectiveJanuary 15, 2021 , to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate 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.The Colorado Department of Public Health and the Environment also recently finalized rules related to the control of emissions from certain pre-production activities; namely, the curbing of methane emissions from oil and gas operations to include setting methane emissions limits per 1,000 Boe produced, more frequent inspections, and limits on emissions during maintenance. These and other developments related to the implementation of SB 181 could adversely impact our revenues and future production from our properties.
Proposed SEC Climate Disclosure Rules
OnMarch 21, 2022 , theU.S. Securities and Exchange Commission proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, following theSEC's review of the public comments received, we or our operators could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. 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 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.
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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 $123.64 per barrel in March 2022 . 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
June 30, 2022 , the posted price for oil was $107.76 per barrel and the Henry Hub
spot market price of natural gas was $6.54 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, including the current conflict between Russia and Ukraine , 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 (the "ceiling
test"). 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 test is calculated at each reporting period. The ceiling test
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 June 30, 2022 and
June 30, 2021 , the SEC oil price and SEC gas price used in the
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calculation of the ceiling test were $85.78 and $49.78 , respectively, per barrel
for oil, and $5.14 and $2.47 , respectively, per MMBtu for natural gas. There
were no impairment charges during the three and six months ended June 30, 2022
and 2021.
A decline in the SEC oil price or the SEC gas price could lead to 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 the lesser of the remaining time until maturity or up to 60 months in the future. We had no natural gas or oil derivative contracts in place as ofJune 30, 2022 andDecember 31, 2021 .
Non-GAAP Financial Measures
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 EBITDA as Net Income before depreciation, depletion and
amortization, share-based compensation expense, interest expense, 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 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 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 EBITDA and Adjusted EBITDA ex
lease bonus may differ from computations of similarly titled measures of other
companies.
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The following table presents a reconciliation of Adjusted EBITDA and Adjusted
EBITDA ex lease bonus to the most directly comparable GAAP financial measure for
the periods indicated (in thousands):
Three Months Ended Six Months Ended
June 30, 2022 March 31, 2022 June 30, 2022 June 30, 2021
Reconciliation of Adjusted EBITDA and
Adjusted EBITDA ex lease bonus to Net
Income:
Net Income $ 50,180 $ 39,065 $ 89,245 $ 27,397
Add:
Depreciation, depletion, and amortization 13,449 12,313 25,762 18,447
Share-based compensation expense 1,959 1,481 3,440 4,855
Interest expense, net 1,154 914 2,068 654
Income tax expense 12,957 6,913 19,870 6,503
Less:
Other income, net 14 20 34 15
Adjusted EBITDA $ 79,685 $
60,666
476 1,433 1,909 2,403
Adjusted EBITDA ex lease bonus $ 79,209 $ 59,233 $ 138,442 $ 55,438
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:
Three Months Ended Six Months Ended
June 30, 2022 March 31, 2022 June 30, 2022 June 30, 2021
Royalty revenues
Oil sales 73 % 71 % 72 % 69 %
Natural gas sales 15 % 14 % 15 % 17 %
NGL sales 11 % 13 % 12 % 11 %
Total royalty revenue 99 % 98 % 99 % 97 %
Lease bonus and other revenues 1 % 2 % 1 % 3 %
Total revenues 100 % 100 % 100 % 100 %
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 of the aforementioned costs are borne entirely by the
exploration and production companies that have leased our mineral and royalty
interests.
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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 Cawley, Gillespie & Associates,
Inc. , our independent reserve engineers.
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 toU.S. federal and state income taxes as a corporation.Texas imposes a franchise tax (commonly referred to as theTexas margin tax) at a rate of up to 0.75% on gross revenues less certain deductions, as specifically set forth in theTexas margin tax statute. A portion of our mineral and royalty interests are located inTexas basins. 30
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Results of Operations
Three Months Ended
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 (dollars in thousands, except for realized prices and unit
expenses):
Three Months Ended
June 30, 2022 March 31, 2022 Variance
Production:
Oil (MBbls) 612 552 60 11 %
Natural gas (MMcf) 2,011 1,868 143 8 %
NGLs (MBbls) 237 220 17 8 %
Equivalents (MBoe) 1,185 1,083 102 9 %
Equivalents per day (Boe/d) 13,019 12,031 988 8 %
Revenues:
Oil sales $ 66,415 $ 50,688 $ 15,727 31 %
Natural gas sales 13,968 10,312 3,656 35 %
NGL sales 10,020 8,995 1,025 11 %
Total mineral and royalty revenue $ 90,403 $ 69,995 $ 20,408 29 %
Lease bonus and other revenue 476 1,433 (957) (67) %
Total revenues $ 90,879 $ 71,428 $ 19,451 27 %
Realized prices
Oil ($/Bbl) $ 108.37 $ 91.90 $ 16.47 18 %
Natural gas ($/Mcf) 6.95 5.52 1.43 26 %
NGLs ($/Bbl) 42.31 40.90 1.41 3 %
Equivalents ($/Boe) $ 76.31 $ 64.64 $ 11.67 18 %
Operating expenses:
Gathering, transportation and marketing $ 2,246 $ 2,003 $ 243 12 %
Severance and ad valorem taxes 5,361 4,331 1,030 24 %
Depreciation, depletion, and amortization 13,449 12,313 1,136 9 %
General and administrative (before
share-based compensation) 3,587 4,428 (841) (19) %
Total operating expenses (before
share-based compensation) $ 24,643 $ 23,075 $ 1,568 7 %
General and administrative, share-based
compensation 1,959 1,481 478 32 %
Total operating expenses $ 26,602 $ 24,556 $ 2,046 8 %
Other expenses:
Interest expense, net $ 1,154 $ 914 $ 240 26 %
Unit Expenses ($/Boe)
Gathering, transportation and marketing $ 1.90 $ 1.85 $ 0.05 3 %
Severance and ad valorem taxes 4.52 4.00 0.52 13 %
Depreciation, depletion and amortization 11.35 11.37 (0.02) - %
General and administrative (before
share-based compensation) 3.03 4.09 (1.06) (26) %
General and administrative, share-based
compensation 1.65 1.37 0.28 20 %
Interest expense, net 0.97 0.84 0.13 15 %
31-------------------------------------------------------------------------------- Table of Contents Revenues Total revenues for the three months endedJune 30, 2022 increased 27%, or$19.5 million , compared to the three months endedMarch 31, 2022 . The increase was attributable to a$20.4 million increase in mineral and royalty revenues partially offset by a$0.9 million decrease in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 18% increase in realized commodity prices, resulting in an increase in royalty revenues of$13.8 million , and an 8% increase in production volumes to 13,019 Boe/d, resulting in an increase in royalty revenues of$6.6 million . Oil revenues for the three months endedJune 30, 2022 increased 31%, or$15.7 million , compared to the three months endedMarch 31, 2022 . The increase in oil revenues was attributable to the 18% increase in realized oil prices to$108.37 per barrel, resulting in an increase in revenues of$10.1 million , and an 11% increase in oil production volumes to 6,735 barrels per day, resulting in a$5.6 million increase in oil revenues. Natural gas revenues for the three months endedJune 30, 2022 increased 35%, or$3.7 million , compared to the three months endedMarch 31, 2022 . The increase in natural gas revenues was attributable to the 26% increase in realized natural gas prices to$6.95 per Mcf, resulting in an increase in revenues of$2.9 million , and an 8% increase in natural gas production volumes to 22,093 Mcf per day, resulting in a$0.8 million increase in natural gas revenues. NGL revenues for the three months endedJune 30, 2022 increased 11%, or$1.0 million , compared to the three months endedMarch 31, 2022 . The increase in NGL revenues was attributable to the 3% increase in realized NGL prices to$42.31 per barrel, resulting in an increase in NGL revenues of$0.3 million , and an 8% increase in NGL production volumes to 2,602 Boe per day, resulting in a$0.7 million increase in NGL revenues.
Lease Bonus and Other Revenues
When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The$0.9 million decrease in revenues from lease bonus payments for the three months endedJune 30, 2022 was primarily attributable to the$0.6 million and$0.5 million decreases in leasing activity in the Permian and DJ Basins, respectively. Other revenues include payments for land easements (or "right-of-way") and surface damages and were not a significant portion of the overall amount. Operating Expenses Gathering, transportation and marketing expenses ("GTM"). For the three months endedJune 30, 2022 , GTM expenses increased 12% compared to the three months endedMarch 31, 2022 , which is attributable to increased production volumes. Severance and ad valorem taxes. For the three months endedJune 30, 2022 , severance and ad valorem taxes increased 24% compared to the three months endedMarch 31, 2022 , primarily due to the increase in mineral and royalty revenues which was driven by increased realized commodity prices.
Depreciation, depletion and amortization. DD&A expense increased 9%, or
General and administrative and share-based compensation. General and administrative expense (before share-based compensation) decreased 19%, or$0.8 million , for the three months endedJune 30, 2022 compared to the three months endedMarch 31, 2022 , primarily as a result of decreased compensation costs of$0.3 million , provision for credit losses of$0.2 million and insurance expenses of$0.2 million . 32 -------------------------------------------------------------------------------- Table of Contents Share-based compensation expense for the three months endedJune 30, 2022 was$2.0 million , net of$0.3 million of share-based compensation cost capitalized to unevaluated property,$1.2 million of share-based compensation cost capitalized to evaluated property and$0.1 million of share-based compensation cost capitalized to internally developed software. Share-based compensation expense for the three months endedMarch 31, 2022 was$1.5 million , net of$0.6 million of share-based compensation cost capitalized to unevaluated property and$0.6 million of share-based compensation cost capitalized to evaluated property. The sequential increase in share-based compensation expense of$0.5 million was primarily due to the timing of the share-based awards granted during 2022. See table below for additional details (in thousands). Three Months Ended June 30, 2022 March 31, 2022 Variance Incentive units$ 178 $ 178 $ - RSAs 39 125 (86) RSUs 2,127 1,426 701 PSUs 1,173 974 199 STIP awards 67 8 59 Capitalized share-based compensation (1,625)
(1,230) (395)
Total share-based compensation expense
Interest expense, net. Interest expense, net increased
Three Months Ended
June 30, 2022 March 31, 2022 Variance
Interest expense - revolving credit facility $ 900 $ 692
172 128 44
Amortization of loan closing costs 149 131 18
Interest income (67) (37) (30)
Total interest expense, net $ 1,154 $ 914 $ 240
Total weighted average interest rate 3.31 % 2.96 %
Total weighted average debt balance$ 107,615 $ 93,000 33
-------------------------------------------------------------------------------- Table of Contents Six Months EndedJune 30, 2022 Compared to Six Months EndedJune 30, 2021 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 (dollars in thousands, except for realized prices and unit expenses): Six Months Ended June 30, 2022 2021 Variance Production: Oil (MBbls) 1,164 834 330 40 % Natural gas (MMcf) 3,879 2,916 963 33 % NGLs (MBbls) 457 301 156 52 % Equivalents (MBoe) 2,268 1,621 647 40 % Equivalents per day (Boe/d) 12,528 8,959 3,569 40 % Revenues: Oil sales$ 117,103 $ 49,542 $ 67,561 136 % Natural gas sales 24,280 12,141 12,139 100 % NGL sales 19,015 7,498 11,517 154 % Total mineral and royalty revenue$ 160,398 $ 69,181 $ 91,217 132 % Lease bonus and other revenue 1,909 2,403 (494) (21) % Total revenues$ 162,307 $ 71,584 $ 90,723 127 % Realized prices Oil ($/Bbl)$ 100.57 $ 59.39 $ 41.18 69 % Natural gas ($/Mcf) 6.26 4.16 2.10 50 % NGLs ($/Bbl) 41.63 24.88 16.75 67 % Equivalents ($/Boe)$ 70.74 $ 42.66 $ 28.08 66 % Operating expenses: Gathering, transportation and marketing$ 4,249 $ 3,326 $ 923 28 % Severance and ad valorem taxes 9,692 4,133 5,559 135 % Depreciation, depletion, and amortization 25,762 18,447 7,315 40 % General and administrative (before share-based compensation) 8,015 6,284 1,731 28 % Total operating expenses (before share-based compensation)$ 47,718 $ 32,190 $ 15,528 48 % General and administrative, share-based compensation 3,440 4,855 (1,415) (29) % Total operating expenses$ 51,158 $ 37,045 $ 14,113 38 % Other expenses: Interest expense, net$ 2,068 $ 654 $ 1,414 216 % Unit Expenses ($/Boe) Gathering, transportation and marketing $ 1.87$ 2.05 $ (0.18) (9) % Severance and ad valorem taxes 4.27 2.55 1.72 67 % Depreciation, depletion and amortization 11.36 11.38 (0.02) - % General and administrative (before share-based compensation) 3.53 3.87 (0.34) (9) % General and administrative, share-based compensation 1.52 2.99 (1.47) (49) % Interest expense, net 0.91 0.40 0.51 128 % 34
-------------------------------------------------------------------------------- Table of Contents Revenues Total revenues for the six months endedJune 30, 2022 increased 127%, or$90.7 million , compared to the six months endedJune 30, 2021 . The increase was attributable to a$91.2 million increase in mineral and royalty revenues partially offset by a$0.5 million decrease in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 66% increase in realized commodity prices, resulting in an increase in royalty revenues of$63.7 million , and a 40% increase in production volumes to 12,528 Boe/d, resulting in an increase in royalty revenues of$27.5 million . Oil revenues for the six months endedJune 30, 2022 increased 136%, or$67.6 million , compared to the six months endedJune 30, 2021 . The increase in oil revenues was attributable to the 69% increase in realized oil prices to$100.57 per barrel, resulting in an increase in revenues of$48.0 million , and a 40% increase in oil production volumes to 6,433 barrels per day, resulting in a$19.6 million increase in oil revenues. Natural gas revenues for the six months endedJune 30, 2022 increased 100%, or$12.1 million , compared to the six months endedJune 30, 2021 . The increase in natural gas revenues was attributable to the 50% increase in realized natural gas prices to$6.26 per Mcf, resulting in an increase in revenues of$8.1 million , and a 33% increase in natural gas production volumes to 21,428 Mcf per day, resulting in a$4.0 million increase in natural gas revenues. NGL revenues for the six months endedJune 30, 2022 increased 154%, or$11.5 million , compared to the six months endedJune 30, 2021 . The increase in NGL revenues was attributable to the 67% increase in realized NGL prices to$41.63 per barrel, resulting in an increase in NGL revenues of$7.7 million , and a 52% increase in NGL production volumes to 2,523 Boe per day, resulting in a$3.8 million increase in NGL revenues.
Lease Bonus and Other Revenues
When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The$0.5 million decrease in revenues from lease bonus payments for the six months endedJune 30, 2022 was primarily attributable to the$0.8 million decrease in leasing activity in thePermian Basin slightly offset by an increase in leasing activity in theDJ Basin of$0.2 million . Other revenues include payments for land easements (or "right-of-way") and surface damages and were not a significant portion of the overall amount.
Operating Expenses
Gathering, transportation and marketing expenses ("GTM"). For the six months
ended June 30, 2022 , GTM expenses increased 28% compared to the six months ended
June 30, 2021 , which is attributable to increased production volumes.
Severance and ad valorem taxes. For the six months ended June 30, 2022 ,
severance and ad valorem taxes increased 135% compared to the six months ended
June 30, 2021 , primarily due to the increase in mineral and royalty revenues
which was driven by increased realized commodity prices and production volumes.
Depreciation, depletion and amortization. DD&A expense increased 40%, or $7.3
million , for the six months ended June 30, 2022 as compared to the six months
ended June 30, 2021 , predominantly due to higher production volumes.
General and administrative and share-based compensation. General and
administrative expense (before share-based compensation) increased 28%, or $1.7
million , for the six months ended June 30, 2022 compared to the six months ended
June 30, 2021 as a result of increased compensation costs of $0.9 million ,
professional services of $0.5 million and legal fees of $0.3 million . The
incremental compensation costs were primarily due to the implementation of the
STIP during 2022. The STIP awards reallocated a portion of the annual LTIP
awards for executives and certain other employees in 2022 from share-based
awards to performance-based bonuses. As such, the increase in compensation costs
is offset by the decline in share-based compensation described below.
35
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Table of Contents
Share-based compensation expense for the six months ended June 30, 2022 was $3.4
million , net of $0.9 million of share-based compensation cost capitalized to
unevaluated property, $1.9 million of share-based compensation cost capitalized
to evaluated property and $0.1 million of share-based compensation cost
capitalized to internally developed software. Share-based compensation expense
for the six months ended June 30, 2021 was $4.9 million , net of $1.5 million of
share-based compensation cost capitalized to unevaluated property and $2.0
million of share-based compensation cost capitalized to evaluated property. The
decrease in share-based compensation expense of $1.4 million was primarily due
to the reallocation of a portion of the annual LTIP awards for executives and
certain other employees in 2022 from share-based awards to performance-based
bonuses under the STIP, vesting of awards and the timing of the share-based
awards granted during the six months ended June 30, 2022 . See table below for
additional details (in thousands).
Six Months Ended June 30,
2022 2021 Variance
Incentive units $ 356 $ 356 $ -
RSAs 164 297 (133)
RSUs 3,553 5,076 (1,523)
PSUs 2,147 2,613 (466)
STIP awards 75 - 75
Capitalized share-based compensation (2,855) (3,487) 632
Total share-based compensation expense $ 3,440 $
4,855
Interest expense, net. Interest expense, net increased$1.4 million for the six months endedJune 30, 2022 compared to the six months endedJune 30, 2021 , primarily due to the increase of the weighted average debt outstanding on our revolving credit facility from$30.9 million to$100.3 million as shown in the table below (in thousands, except for interest rate). Six Months Ended June 30, 2022 2021 Variance
Interest expense - revolving credit facility
$ 302 $ 1,290 Commitment fees 300 231 69 Amortization of loan closing costs 280 141 139 Interest income (104) (20) (84) Total interest expense, net$ 2,068 $ 654 $ 1,414 Total weighted average interest rate 3.14 % 1.95 % Total weighted average debt balance$ 100,348 $ 30,895 Factors Affecting the Comparability of Our Results of Operations Our future results of operations may not be comparable to the historical results of operations for the periods presented, primarily for the reasons described below. Corporate Transactions
The change in ownership interest in
As ofJune 30, 2021 ,Brigham Minerals owned a 79.5% interest inBrigham LLC and the Brigham LLC Unit Holders owned 20.5% of the outstanding voting stock ofBrigham Minerals . Certain other entities affiliated withYorktown Partners LLC andPine Brook Road Advisors, LP , which are a subset of the Brigham LLC Unit Holders, collectively owned 16.9% of the outstanding voting stock ofBrigham Minerals as ofJune 30, 2021 . 36
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Table of Contents
As ofDecember 31, 2021 ,Brigham Minerals owned an 81.0% interest inBrigham LLC and the Brigham LLC Unit Holders owned 19.0% of the outstanding voting stock ofBrigham Minerals . Certain other entities affiliated withYorktown Partners LLC andPine Brook Road Advisors, LP , which are a subset of the Brigham LLC Unit Holders, owned 4.8% and 8.7%, respectively, of the outstanding voting stock ofBrigham Minerals as ofDecember 31, 2021 . Yorktown ceased to be an affiliate of the Company onJanuary 20, 2022 in connection with the resignation ofW. Howard Keenan , Jr. from the Board of Directors. As ofJune 30, 2022 ,Brigham Minerals owned an 88.6% interest inBrigham LLC and the Brigham LLC Unit Holders owned 11.4% of the outstanding voting stock ofBrigham Minerals . Certain other entities affiliated withPine Brook Road Advisors, LP , which are a subset of the Brigham LLC Unit Holders, owned 3.6% of the outstanding voting stock ofBrigham Minerals as ofJune 30, 2022 . 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 and 2022, 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. Our cash flows from operations may be negatively impacted by various factors discussed herein, 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 six months endedJune 30, 2022 , we deployed approximately$79.7 million for acquisition-related capital expenditures, inclusive of$2.8 million capitalized share-based compensation expense and$17.6 million of equity. In addition to acquisitions, we have certain contractual long-term capital requirements associated with our office lease and with our revolving credit facility. See "Note 8 - Leases" and "Note 7 - Long-Term Debt" to the condensed consolidated financial statements ofBrigham Minerals included elsewhere in this Quarterly 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 endedDecember 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 as of
June 30, 2022
Cash and cash equivalents $ 24,103
Revolving credit facility availability $ 217,000
Total liquidity $ 241,103
37-------------------------------------------------------------------------------- Table of Contents Working Capital
Our working capital, which we define as current assets minus current
liabilities, totaled
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$24.1 million and$20.8 million atJune 30, 2022 andDecember 31, 2021 , respectively. The increase in cash and cash equivalents was primarily due to an increase in cash flow from operations and proceeds from the sale of mineral and royalty interests, which were partially offset by the payment of dividends to our stockholders and distributions to the holders of non-controlling interests, acquisitions of oil and gas properties, net repayments of debt and the payment of employee tax withholding obligations for the settlement of share-based compensation awards. 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 andHenry 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 the six months endedJune 30, 2022 : Dividends paid Declaration Date Record Date Payment Date Dividend Amount (in thousands) (1) February 18, 2022 March 18, 2022 March 25, 2022 $ 0.45 $ 23,979 May 1, 2022 May 20, 2022 May 27, 2022 $ 0.60 $ 31,789
(1) Dividends paid to holders of Class A common stock.
OnAugust 2, 2022 , the Board of Directors ofBrigham Minerals declared a dividend of$0.77 per share of Class A common stock payable onAugust 26, 2022 , to stockholders of record at the close of business onAugust 19, 2022 . See "Note 15-Subsequent Events" to the condensed consolidated financial statements ofBrigham Minerals included elsewhere in this Quarterly Report for further discussion. Our current dividend structure consists of a base dividend of$0.16 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.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in
thousands):
Six Months Ended June 30,
2022 2021
Net cash provided by operating activities $ 86,948 $ 45,131
Net cash provided by (used in) investing activities 13,341 (36,358)
Net cash used in financing activities (97,205) (11,503)
38-------------------------------------------------------------------------------- Table of Contents Analysis of Cash Flow Changes For the Six Months EndedJune 30, 2022 Compared to the Six Months EndedJune 30, 2021
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 and other revenues and changes in working capital. The increase in net cash provided by operating activities for the six months endedJune 30, 2022 as compared to the six months endedJune 30, 2021 was primarily due to the 66% increase in realized commodity prices during the six months endedJune 30, 2022 and the 40% increase in production volumes.
Net cash provided by (used in) investing activities
Net cash provided by (used in) investing activities is primarily comprised of acquisitions of mineral and royalty interests, net of dispositions. For the six months endedJune 30, 2022 , our net cash provided by investing activities was primarily a result of sales of mineral and royalty interests totaling$74.4 million , partially offset by acquisitions of mineral and royalty interests totaling$59.8 million . For the six months endedJune 30, 2021 , our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests of$36.3 million .
Net cash used in financing activities
Net cash used in financing activities for the six months endedJune 30, 2022 was primarily due to the dividends paid to holders of our Class A common stock of$55.8 million , net repayments under our revolving credit facility of$20.0 million , distributions to holders of non-controlling interest of$11.2 million and payment of employee tax withholding for settlement of equity compensation awards of$9.7 million . Net cash used in financing activities for the six months endedJune 30, 2021 was primarily due to the dividends paid to holders of our Class A common stock of$25.5 million , distributions to holders of non-controlling interest of$7.8 million and payment of employee tax withholding for settlement of equity compensation awards of$1.1 million , partially offset by net borrowings under our revolving credit facility of$23.0 million .
Revolving Credit Facility
OnMay 16, 2019 , Brigham Resources entered into a credit agreement withWells Fargo Bank, N.A. , as administrative agent (the "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 a substantial portion of Brigham Resources and its domestic subsidiaries' assets, including a 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 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 six months endedJune 30, 2022 was 3.14%. As ofJune 30, 2022 , the elected borrowing base on our revolving credit facility was$290.0 million , with outstanding borrowings of$73.0 million , resulting in$217.0 million available 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 for tranches outstanding as ofJune 3, 2022 or the adjusted SOFR rate plus an applicable margin for tranches effective postJune 3, 2022 . 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 and adjusted SOFR rate loans, 2.500% to 3.500%. Brigham Resources may elect an interest period of one, three or six 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 borrowing base. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions. 39 -------------------------------------------------------------------------------- Table of Contents Our revolving credit facility matures onMay 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.
Off-Balance Sheet Arrangements
As of
Critical Accounting Policies and Related Estimates
As of
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