BRIGHAM MINERALS, INC. Brigham Minerals, Inc. (the "Company," "we," "us," or "our") is the managing member ofBrigham Minerals Holdings, LLC ("Brigham LLC ") and is indirectly 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 and combined financial statements included in our Annual Report on Form 10-K for the year endedDecember 31, 2020 (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 spread of the COVID-19 pandemic, 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 shareholders through (i) the organic 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, 2021 , we owned 88,570 net royalty acres across 37 counties within theDelaware and Midland Basins inWest Texas andNew Mexico , the SCOOP/STACK plays in theAnadarko Basin ofOklahoma , theDenver -Julesburg ("DJ") Basin inColorado andWyoming and theWilliston Basin inNorth Dakota . Financial and Operational Overview: •Our production volumes of 8,988 Boe/d (70% liquids, 52% oil) for the three months endedJune 30, 2021 increased 1% compared to the three months endedMarch 31, 2021 and decreased 7% for the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 . •Our royalty revenues comprised of crude oil, natural gas and NGL sales for the three months endedJune 30, 2021 increased 15% to$37.0 million compared to the three months endedMarch 31, 2021 due to a 13% increase in realized commodity pricing and a 1% higher production volumes and increased 69% for six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 due to an 83% increase in realized commodity pricing partially offset by the decrease in production volumes. •Our net income for the three months endedJune 30, 2021 was$15.3 million compared to a net income of$12.1 million for the three months endedMarch 31, 2021 and net income for six months endedJune 30, 2021 of$27.4 million compared to a net income of$2.0 million for the six months endedJune 30, 2020 . •Adjusted EBITDA and Adjusted EBITDA ex lease bonus for the three months endedJune 30, 2021 were$30.8 million , and$30.0 million , respectively, and increased 14% and 18%, respectively, as compared to the three months endedMarch 31, 2021 and increased 86% and 105%, respectively, for the six months endedJune 30, 2021 to$57.8 million and$55.4 million , respectively, as compared to the six months endedJune 30, 2020 . 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." •OnAugust 3, 2021 , the Board of Directors ofBrigham Minerals declared a dividend of$0.35 per share of Class A common stock payable onAugust 27, 2021 to shareholders of record at the close of business onAugust 20, 2021 . •As ofJune 30, 2021 ,Brigham Minerals had a cash balance of$6.4 million and$92.0 million of capacity on our revolving credit facility, providing the Company with total liquidity of$98.4 million . OnJuly 7, 2021 , the borrowing 20 -------------------------------------------------------------------------------- Table of Contents base and elected commitments on our revolving credit facility were increased from$135.0 million to$165.0 million . Pro-forma for the increase in the borrowing base, the Company would have had total liquidity of$128.4 million as ofJune 30, 2021 . 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. As a result, stability in the markets and demand for the commodities produced by the oil and natural gas industry have not returned to pre-pandemic levels and may not for some time. Commodity prices have improved from historic lows in 2020, however, the impacts of the pandemic continue to be unpredictable and dynamic, so we are unable to reasonably estimate the period of time that related market conditions could exist or the extent to which they may continue to impact our business, results of operations, financial condition, or the timing of further industry recovery. 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 the second half of 2020 and the first half of 2021, along with our financial strength, we believe we are well positioned to capture attractive opportunities for the remainder of 2021 that will generate shareholder value. Given that our capital allocation is within our control, we believe that the liquidity provided by our cash flow from operations and borrowings under our revolving credit facility will provide us with sufficient capital to execute our current strategy. The company is currently operating its office at 100% capacity while continuing to support working from home for our employees that are considered high-risk pursuant to theCenters for Disease Control and Prevention guidelines or have household members meeting the criteria of the guidelines. The Company has not experienced material disruptions to our operations or the health of our workforce to date.
Winter Storm Uri
InFebruary 2021 , Winter Storm Uri caused severe winter weather and freezing temperatures in the southernUnited States , which effected our properties in the Permian and Anadarko Basins, resulting in the curtailment of a portion of our production, delays in drilling and completion of wells, other operational constraints and ultimately adversely impacted our first quarter 2021 production. These curtailments, delays and operational constraints also resulted in increases in commodity prices, primarily natural gas prices. For example, the Henry Hub spot market price for natural gas for the month ofFebruary 2021 ranged from a low of$2.66 per MMBtu to a high of$23.86 per MMBtu. Given we do not operate our properties,Brigham Minerals has limited visibility into the timing of when production resumed and was required to estimate the amount of production delivered to the purchaser and the price that will be ultimately received for the sale of the product. As ofJune 30, 2021 , commodity prices, in particular natural gas prices, have stabilized. The Henry Hub spot market price for natural gas for the three months endedJune 30, 2021 ranged from a low of$2.43 per MMBtu to a high of$3.79 per MMBtu. Operational Update
Mineral and Royalty Interest Ownership Update
During the second quarter 2021, the Company completed 22 transactions, acquiring 640 net royalty acres (standardized to a 1/8th royalty interest) and deploying$14.4 million in capital primarily in thePermian Basin . As ofJune 30, 2021 , the Company owned roughly 88,570 net royalty acres, encompassing 13,462 gross (114.8 net) undeveloped horizontal locations, across 37 counties in what the Company views as the cores of theDelaware and Midland Basins inWest Texas andNew Mexico , the SCOOP/STACK plays in theAnadarko Basin ofOklahoma , theDJ Basin inColorado andWyoming and theWilliston Basin inNorth Dakota .
The table below summarizes the Company's mineral and royalty interest ownership at the dates indicated.
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Delaware Midland SCOOP STACK DJ Williston Other Total
Net Royalty Acres
June 30, 2021 29,270 6,105 11,415 10,650 16,345 7,995 6,790 88,570
March 31, 2021 28,940 5,775 11,400 10,725 16,320 7,980 6,790 87,930
Acres Added (Revised)
Q/Q 330 330 15 (75) 25 15 - 640
% Added Q/Q 1% 6% -% (1)% -% -% -% 1%
Operating Activity Update
DUC Conversions
The Company identified approximately 204 gross (0.7 net) DUCs converted to
production during the second quarter 2021, which represented 26% of its gross
DUCs (16% of net) in inventory as of first quarter 2021. Second quarter 2021 DUC
and PDP conversion waterfalls are summarized in the charts below:
[[Image Removed: mnrl-20210630_g1.jpg]]
[[Image Removed: mnrl-20210630_g2.jpg]]
Drilling Activity
During the second quarter 2021, the Company identified 153 gross (1.3 net) wells
spud on its mineral position, which represents a 31% increase in net well
drilling activity relative to first quarter 2021. Brigham's gross and net wells
spud activity per quarter is summarized in the chart below:
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[[Image Removed: mnrl-20210630_g3.jpg]]
DUC and Permit Inventory
Brigham Minerals ended the second quarter 2021 with 5.0 net DUCs and 4.1 net
permits versus 4.4 net DUCs and 4.7 net permits as of first quarter 2021,
representing a 14% sequential increase in total net DUCs. The sequential DUC
inventory increase was largely driven by an increase in net Permian DUCs.
Brigham Minerals ended the second quarter 2021 with 3.3 net Permian DUCs up from
2.7 net Permian DUCs as of first quarter 2021. Brigham Minerals' DUC and permit
inventory as of June 30, 2021 by basin is outlined in the table below:
Development Inventory by Basin (1)
Delaware Midland SCOOP STACK DJ Williston Other Total
Gross Inventory
DUCs 176 232 50 10 124 123 17 732
Permits 162 99 5 - 149 258 10 683
Net Inventory
DUCs 1.9 1.4 0.3 - 1.1 0.2 0.1 5.0
Permits 1.0 1.1 - - 1.3 0.6 - 4.1
(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 EBITDA and Adjusted EBITDA ex lease bonus.
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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 $77.41 per barrel in June 2018 . 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,
2021 , the posted price for oil was $73.52 per barrel and the Henry Hub spot
market price of natural gas was $3.79 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 epidemics 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
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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, 2021 and
June 30, 2020 , the SEC oil price and SEC gas price used in the calculation of
the ceiling test were $49.78 and $47.13 , respectively, per barrel for oil, and
$2.47 and $2.08 , respectively, per MMBtu for natural gas. There were no
impairment charges during the three and six months ended June 30, 2021 and 2020.
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, such as
occurred in the third and fourth quarters of 2020. 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 June 30, 2021 and December 31,
2020 .
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 (Loss) 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.
Three Months Ended Six Months Ended
(In thousands) June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020
Reconciliation of Adjusted EBITDA and
Adjusted EBITDA ex lease bonus to Net
Income:
Net Income (Loss) $ 15,326 $ 12,071 $ 27,397 $ 1,985
Add:
Depreciation, depletion, and amortization 9,080 9,367 18,447 24,026
Share-based compensation expense 2,555 2,300 4,855 3,736
Interest expense 387 267 654 577
Income tax expense 3,430 3,073 6,503 732
Less:
Other income, net 2 13 15 25
Adjusted EBITDA $ 30,776 $
27,065
806 1,597 2,403 3,968
Adjusted EBITDA ex lease bonus $ 29,970 $ 25,468 $ 55,438 $ 27,063
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,
June 30, 2021 March 31, 2021 2021 2020
Royalty revenues
Oil sales 71 % 68 % 69 % 74 %
Natural gas sales 18 % 15 % 17 % 10 %
NGL sales 9 % 12 % 11 % 7 %
Total royalty revenue 98 % 95 % 97 % 91 %
Lease bonus and other revenues 2 % 5 % 3 % 9 %
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.
Gathering, Transportation and Marketing Expenses
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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 shareholders, 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 1.00% 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
On November 19, 2020 , the SEC adopted amendments to modernize and simplify
Regulation S-K, including its Management's Discussion and Analysis and certain
financial disclosure requirements. Specifically, the final rule gives
registrants the option to disclose their results of operations of the most
recently completed fiscal quarter compared to the immediately preceding fiscal
quarter rather than compared to the corresponding fiscal quarter of the prior
year. We believe that a comparison of the results of operations of the most
recently completed fiscal quarter to the immediately preceding fiscal quarter is
more
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meaningful and useful to investors than comparing the most recently completed
fiscal quarter to the corresponding fiscal quarter of the prior year, and we
voluntary complied with the amendments beginning in our Quarterly Report on Form
10-Q for the quarter ended March 31, 2021 . As a result of our voluntary
compliance, we are presenting a comparison of the results of operations of the
three months ended June 30, 2021 to the three months ended March 31, 2021 and of
the six months ended June 30, 2021 to the six months ended June 30, 2020 .
Three Months Ended June 30, 2021 Compared to Three Months Ended March 31, 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:
Three Months Ended
(Dollars in thousands, except for realized prices and unit expenses) June 30, 2021 March 31, 2021 Variance Production: Oil (MBbls) 424 411 13 3 % Natural gas (MMcf) 1,465 1,451 14 1 % NGLs (MBbls) 150 151 (1) (1) % Equivalents (MBoe) 818 804 14 2 % Equivalents per day (Boe/d) 8,988 8,931 57 1 % Revenues: Oil sales$ 26,729 $ 22,813 $ 3,916 17 % Natural gas sales 6,704 5,437 1,267 23 % NGL sales 3,572 3,926 (354) (9) % Total mineral and royalty revenue$ 37,005 $ 32,176 $ 4,829 15 % Lease bonus and other revenue 806 1,597 (791) (50) % Total revenues$ 37,811 $ 33,773 $ 4,038 12 % Realized prices Oil ($/Bbl)$ 63.11 $ 55.55$ 7.56 14 % Natural gas ($/Mcf) 4.58 3.75 0.83 22 % NGLs ($/Bbl) 23.77 25.97 (2.20) (8) % Equivalents ($/Boe)$ 45.24 $ 40.03$ 5.21 13 % Operating expenses: Gathering, transportation and marketing$ 1,593 $ 1,733$ (140) (8) % Severance and ad valorem taxes 2,300 1,833 467 25 % Depreciation, depletion, and amortization 9,080 9,367 (287) (3) % General and administrative (before share-based compensation) 3,142 3,142 - - % Total operating expenses (before share-based compensation)$ 16,115 $ 16,075 $ 40 - % Share-based compensation 2,555 2,300 255 11 % Total operating expenses$ 18,670 $ 18,375 $ 295 2 % Other expenses: Interest expense, net $ 387 $ 267$ 120 45 % Total other expenses $ 387 $ 267$ 120 45 % 28
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Three Months Ended
Unit Expenses ($/Boe) June 30, 2021 March 31, 2021 Variance
Gathering, transportation and marketing $ 1.95 $ 2.16 $ (0.21) (10) %
Severance and ad valorem taxes 2.81 2.28 0.53 23 %
Depreciation, depletion and amortization 11.10 11.65 (0.55) (5) %
General and administrative (before
share-based compensation) 3.84 3.91 (0.07) (2) %
General and administrative, share-based
compensation 3.12 2.86 0.26 9 %
Interest expense, net 0.47 0.33 0.14 42 %
Revenues
Total revenues for the three months ended June 30, 2021 increased 12%, or $4.0
million , compared to the three months ended March 31, 2021 . The increase was
attributable to a $4.8 million increase in mineral and royalty revenues,
partially offset by an $0.8 million decrease in lease bonus and other revenues
during the period. The increase in mineral and royalty revenue was primarily
attributable to the 13% increase in realized commodity prices, resulting in an
increase in royalty revenues of $4.3 million , and a 1% increase in production
volumes to 8,988 Boe/d, resulting in an increase in royalty revenues of
$0.5 million .
Oil revenues for the three months ended June 30, 2021 increased 17%, or $3.9
million , compared to the three months ended March 31, 2021 . The increase in oil
revenues was attributable to the 14% increase in realized oil prices to $63.11
per barrel, resulting in an increase in revenues of $3.2 million , and a 3%
increase in oil production volumes to 4,654 barrels per day, resulting in a $0.7
million increase in oil revenues.
Natural gas revenues for the three months ended June 30, 2021 increased 23%, or
$1.3 million , compared to the three months ended March 31, 2021 . The increase in
natural gas revenues was primarily attributable to the 22% increase in realized
natural gas prices to $4.58 per Mcf attributable to Winter Storm Uri, resulting
in an increase in revenues of $1.2 million .
NGL revenues for the three months ended June 30, 2021 decreased 9%, or $0.4
million , compared to the three months ended March 31, 2021 . The decrease in NGL
revenues was primarily attributable to the 8% decrease in realized NGL prices to
$23.77 per barrel, resulting in a decrease in NGL revenues of $0.3 million .
Lease Bonus and Other Revenues
When we lease our minerals, we generally receive an upfront cash payment, or a
lease bonus. The $0.8 million decrease in revenues from lease bonus payments for
the three months ended June 30, 2021 is primarily attributable to the $1.3
million decrease in leasing activity in the Permian Basin , partially offset by
the $0.5 million increase in leasing activity in DJ basin. Other revenues
include payments for 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
ended June 30, 2021 , GTM expenses decreased 8% compared to the three months
ended March 31, 2021 , primarily due to an overall 10% decrease in GTM rate to
$1.95 per Boe for the three months ended June 30, 2021 compared to $2.16 per Boe
for the three months ended March 31, 2021 .
Severance and ad valorem taxes. For the three months ended June 30, 2021 ,
severance and ad valorem taxes increased 25%, or $0.5 million , over the three
months ended March 31, 2021 , primarily due to the increase in mineral and
royalty revenues which was driven by an increase in realized commodity prices of
13%.
Depreciation, depletion and amortization. DD&A expense decreased 3%, or $0.3
million , for the three months ended June 30, 2021 as compared to the three
months ended March 31, 2021 . A lower depletion rate decreased our depletion
expense by $0.5 million . This was partially offset by slightly higher production
volumes, which increased our depletion expense by $0.2 million . The depletion
rate was $11.03 per Boe and $11.58 per Boe for the three months ended June 30,
2021 and the three months ended March 31, 2021 , respectively. The decrease in
the depletion rate was primarily a result of an 8% increase of our total proved
reserves for the three months ended June 30, 2021 compared to the three months
ended March 31, 2021 as a result of higher SEC pricing.
General and administrative and share-based compensation. General and
administrative expense (before share-based compensation) was unchanged for the
three months ended June 30, 2021 , compared to the three months ended March 31,
2021 .
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Share-based compensation expense for the three months ended June 30, 2021 was
$2.6 million , net of $0.6 million of share-based compensation cost capitalized
to unevaluated property and $1.3 million of share-based compensation cost
capitalized to evaluated property. Share-based compensation expense for the
three months ended March 31, 2021 was $2.3 million , net of $0.9 million of
share-based compensation cost capitalized to unevaluated property and $0.7
million of share-based compensation cost capitalized to evaluated property. The
sequential increase in share-based compensation expense of $0.3 million was
primarily due to additional grants of PSUs that were granted during the three
months ended June 30, 2021 . See table below for additional details.
Three Months Ended
(In thousands) June 30, 2021 March 31, 2021 Variance
Incentive Units $ 178 $ 178 $ -
RSAs 163 134 29
RSUs 2,534 2,542 (8)
PSUs 1,534 1,079 455
Capitalized share-based compensation (1,854)
(1,633) (221)
Total share-based compensation expense
Interest expense, net. Interest expense, net increased
Three Months Ended
(In thousands, except for interest rate) June 30, 2021 March 31, 2021 Variance
Interest expense - revolving credit facility $ 190 $ 113 $ 77 Commitment fees
127 104 23
Amortization of loan closing costs 82 58 24
Interest income (12) (8) (4)
Total interest expense, net $ 387 $ 267 $ 120
Total weighted average interest rate 1.98 % 1.90 %
Total weighted average debt balance$ 37,802 $ 23,911 30
-------------------------------------------------------------------------------- Table of Contents Six Months EndedJune 30, 2021 Compared to Six Months EndedJune 30, 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: Six Months Ended June
30,
(Dollars in thousands, except for realized prices and unit expenses) 2021 2020 Variance Production: Oil (MBbls) 834 921 (87) (9) % Natural gas (MMcf) 2,916 2,986 (70) (2) % NGLs (MBbls) 301 333 (32) (10) % Equivalents (MBoe) 1,621 1,752 (131) (7) % Equivalents per day (Boe/d) 8,959 9,628 (669) (7) % Revenues: Oil sales$ 49,542 $ 33,353 $ 16,189 49 % Natural gas sales 12,141 4,346 7,795 179 % NGL sales 7,498 3,218 4,280 133 % Total mineral and royalty revenue$ 69,181 $ 40,917 $ 28,264 69 % Lease bonus and other revenue 2,403 3,968 (1,565) (39) % Total revenues$ 71,584 $ 44,885 $ 26,699 59 % Realized prices Oil ($/Bbl)$ 59.39 $ 36.20 $ 23.19 64 % Natural gas ($/Mcf) 4.16 1.46 2.70 185 % NGLs ($/Bbl) 24.88 9.66 15.22 158 % Equivalents ($/Boe)$ 42.66 $ 23.35 $ 19.31 83 % Operating expenses: Gathering, transportation and marketing$ 3,326 $ 3,404 $ (78) (2) % Severance and ad valorem taxes 4,133 2,786 1,347 48 % Depreciation, depletion, and amortization 18,447 24,026 (5,579) (23) % General and administrative (before share-based compensation) 6,284 7,664 (1,380) (18) % Total operating expenses (before share-based compensation)$ 32,190 $ 37,880 $ (5,690) (15) % Share-based compensation 4,855 3,736 1,119 30 % Total operating expenses$ 37,045 $ 41,616 $ (4,571) (11) % Other expenses: Interest expense, net $ 654$ 577 $ 77 13 % Total other expenses $ 654$ 577 $ 77 13 % Six Months Ended June 30, Unit Expenses ($/Boe) 2021 2020 Variance Gathering, transportation and marketing $ 2.05$ 1.94 $ 0.11 6 % Severance and ad valorem taxes 2.55 1.59 0.96 60 % Depreciation, depletion and amortization 11.38 13.71 (2.33) (17) % General and administrative (before share-based compensation) 3.87 4.37 (0.50) (11) % General and administrative, share-based compensation 2.99 2.13 0.86 40 % Interest expense, net 0.40 0.33 0.07 21 % 31
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Revenues
Total revenues for the six months endedJune 30, 2021 increased 59%, or$26.7 million , compared to the six months endedJune 30, 2020 . The increase was attributable to a$28.3 million increase in mineral and royalty revenues offset by a$1.6 million decrease in lease bonus and other revenues during the period. The increase in mineral and royalty revenue was primarily attributable to the 83% increase in realized commodity prices, resulting in an increase in royalty revenues of$31.3 million . This was partially offset by a 7% decrease in production volumes to 8,959 Boe/d, resulting in an decrease in revenues of$3.0 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 theOPEC + production dispute as well as Winter Storm Uri'sFebruary 2021 production curtailments. Oil revenues for the six months endedJune 30, 2021 increased 49%, or$16.2 million , compared to the six months endedJune 30, 2020 . The increase in oil revenues was attributable to the 64% increase in realized oil prices to$59.39 per barrel, resulting in an increase in revenues of$19.3 million . This was partially offset by a 9% decrease in oil production volumes to 4,609 barrels per day, resulting in a$3.1 million decrease in oil revenues. Natural gas revenues for the six months endedJune 30, 2021 increased 179%, or$7.8 million , compared to the six months endedJune 30, 2020 . The increase in natural gas revenues was attributable to the 185% increase in realized natural gas prices to$4.16 per Mcf, resulting in an increase in revenues of$7.9 million . This was partially offset by the 2% decrease in natural gas production volumes to 16,110 Mcf/d, resulting in a$0.1 million decrease in natural gas revenues. NGL revenues for the six months endedJune 30, 2021 increased 133%, or$4.3 million , compared to the six months endedJune 30, 2020 . The increase in NGL revenues was attributable to the 158% increase in NGL prices to$24.88 per barrel, resulting in an increase in NGL revenues of$4.6 million . This was partially offset by the 10% decrease in NGL volumes to 1,665 barrels per day, resulting in a decrease in revenues of$0.3 million . Lease Bonus and Other Revenues When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. The decrease in revenues from lease bonus payments for the six months endedJune 30, 2021 is primarily attributable to the$2.0 million decrease in leasing activity in thePermian Basin partially offset by the$0.5 million increase in leasing activity in DJ basin. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount. Operating Expenses Gathering, transportation and marketing expenses. For the six months endedJune 30, 2021 , GTM expenses decreased 2% compared to the six months endedJune 30, 2020 primarily due to the 7% decrease in production volumes. Severance and ad valorem taxes. For the six months endedJune 30, 2021 , severance and ad valorem taxes increased 48% compared to the six months endedJune 30, 2020 , due to the 69% increase in mineral and royalty revenues which was primarily due to an increase in realized commodity prices of 83%, partially offset by a 7% decrease in production volumes. Depreciation, depletion and amortization. DD&A expense decreased 23%, or$5.6 million , for the six months endedJune 30, 2021 as compared to the six months endedJune 30, 2020 . A lower depletion rate decreased our depletion expense by$3.3 million and lower production volumes also decreased our depletion expense by$1.7 million . The depletion rate was$11.30 per Boe and$13.31 per Boe for the six months endedJune 30, 2021 and 2020, respectively. The decrease in the depletion rate was primarily a result of the impairment charge of$79.6 million for the year endedDecember 31, 2020 , resulting in lower depletable cost (or amortizable base) in the calculation of the depletion rate for the six months endedJune 30, 2021 . General and administrative and share-based compensation. General and administrative expense (before share-based compensation) decreased 18%, or$1.4 million , for the six months endedJune 30, 2021 , compared to the six months endedJune 30, 2020 as a result of the Company's ongoing efforts to reduce its overall general and administrative expenses and the$0.5 million in incremental legal, professional, audit, and tax fees attributable to the Company'sJune 2020 Secondary Offering. Share-based compensation expense for the six months endedJune 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. Share-based compensation expense for the six months endedJune 30, 2020 was$3.7 million , net of$1.8 million of share-based compensation cost capitalized to unevaluated property and$1.2 million of share-based compensation cost 32 -------------------------------------------------------------------------------- Table of Contents capitalized to evaluated property. The increase in share-based compensation expense of$1.1 million was primarily due to additional grants of RSUs and PSUs that were granted during the six months endedJune 30, 2021 . See table below for further details. Six Months Ended June 30, (In thousands) 2021 2020 Variance Incentive Units $ 356$ 356 $ - RSAs (1) 297 891 (594) RSUs 5,076 3,434 1,642 PSUs 2,613 2,054 559 Capitalized share-based compensation (3,487) (2,998) (489) Total share-based compensation expense$ 4,855 $
3,737
(1)During the three months endedJune 30, 2020 , share-based compensation cost included$0.5 million associated with the accelerated vesting of 30,174 RSAs for certain employees who retired inFebruary 2020 . Interest expense, net. Interest expense, net increased$0.1 million for the three months endedJune 30, 2021 compared to the three months endedJune 30, 2020 . See table below for further details. Six Months Ended June 30, (In thousands, except for interest rate) 2021 2020 Variance Interest expense - revolving credit facility $ 302 $ -$ 302 Commitment fees 231 352 (121) Amortization of loan closing costs 141 488 (347) Interest income (20) (263) 243 Total interest expense, net $ 654$ 577 $ 77 Total weighted average interest rate 1.95 % - % Total weighted average debt balance$ 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 OnJune 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 shareholders of the Company (the "June 2020 Selling Shareholders"), and 4,872,669 of which represented shares issued upon redemption of an equivalent number of theJune 2020 Selling Shareholders' Brigham LLC Units (together with a corresponding number of shares of Class B common stock inBrigham Minerals ), at a price to the public of$13.75 per share.Brigham Minerals did not sell any shares of its common stock in theJune 2020 Secondary Offering and did not receive any proceeds pursuant to theJune 2020 Secondary Offering. OnSeptember 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 shareholders of the Company (the "September 2020 Selling Shareholders"), and 3,062,011 of which represented shares issued upon redemption of an equivalent number of theSeptember 2020 Selling Shareholders' Brigham LLC Units (together with a corresponding number of shares of Class B common stock inBrigham 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 theSeptember 2020 Secondary Offering and did not receive any proceeds pursuant to theSeptember 2020 Secondary Offering. In addition, in connection with theSeptember 2020 Secondary Offering,Brigham Minerals repurchased 436,630 shares of its Class A common stock from theSeptember 2020 Selling Shareholders in a privately negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from theSeptember 2020 Selling 33 -------------------------------------------------------------------------------- Table of Contents Shareholders in theSeptember 2020 Secondary Offering (andBrigham LLC redeemed a corresponding number of Brigham LLC Units held byBrigham Minerals ). As ofJune 30, 2020 ,Brigham Minerals owned a 69.1% interest inBrigham LLC and the Brigham LLC Unit Holders owned 30.9% of the outstanding voting stock ofBrigham Minerals . Certain other entities affiliated with Warburg Pincus LLC,Yorktown Partners LLC andPine Brook Road Advisors, LP , which are a subset of the Company's Brigham LLC Unit Holders, collectively owned 27.5% of the outstanding voting stock ofBrigham Minerals as ofJune 30, 2020 . 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 Company's Brigham LLC Unit Holders, collectively owned 16.9% of the outstanding voting stock ofBrigham Minerals as ofJune 30, 2021 . The change in ownership interest inBrigham LLC fromJune 30, 2020 toJune 30, 2021 impacts the attribution of net income betweenBrigham Minerals' shareholders and Brigham LLC Unit Holders. As ofFebruary 19, 2021 and thereafter, Brigham LLC Unit Holders' interest is classified as non-controlling interest in the condensed consolidated balance sheets ofBrigham Minerals . See "Note 9-Temporary equity and Non-controlling interest" for further details. 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 we may enter into in the future and additional issuances of debt or equity securities. As a result of the COVID-19 pandemic and the decline in commodities prices in 2020, coupled with many of our operators announcing significant reductions in projected capital expenditures in 2021 and beyond, our revenues and cash flows from operations have been and may continue to 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 shareholders and for investing in our business, specifically the acquisition of additional mineral and royalty interests. In connection with the ongoing COVID-19 pandemic and the announced reductions in projected capital expenditures by our operators, our cash flows from operations have been and may continue to be negatively impacted, and as a result, the dividend amount we are able to pay our shareholders has been and may also continue to 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, 2021 , we deployed approximately$39.8 million for acquisition-related capital expenditures, inclusive of a$3.5 million capitalized share-based compensation cost. 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, 2021 , 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. As ofJune 30, 2021 , our liquidity was as follows: (In millions) Cash and cash equivalents $ 6.4
Revolving credit facility availability $ 92.0 Total Liquidity
$ 98.4
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On July 7, 2021 , the borrowing base and elected commitments on our revolving
credit facility were increased from $135.0 million to $165.0 million . Pro-forma
for the increase in the borrowing base, the Company would have had total
liquidity of $128.4 million as of June 30, 2021 . See "Note 14-Subsequent Events"
to the condensed consolidated financial statements of Brigham Minerals included
elsewhere in this Quarterly Report for further discussion.
Working Capital
Our working capital, which we define as current assets minus current
liabilities, totaled $27.0 million at June 30, 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 $6.4 million and $9.1
million at June 30, 2021 and December 31, 2020 , respectively. The decrease in
cash and cash equivalents was primarily due to acquisitions made and payment of
dividends to our shareholders during the six months ended June 30, 2021 . See
"Note 4-Acquisitions" to the condensed consolidated financial statements of
Brigham Minerals included elsewhere in this Quarterly 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 the six months ended June 30, 2021 :
Dividends paid
Declaration Date Record Date Payment Date Dividend Amount (in thousands) (1)
February 19, 2021 March 19, 2021 March 26, 2021 $ 0.26 $ 11,336
May 4, 2021 May 21, 2021 May 28, 2021 $ 0.32 $ 14,201
(1) Dividends paid to holders of Class A common stock.
OnAugust 3, 2021 , the Board of Directors ofBrigham Minerals declared a dividend of$0.35 per share of Class A common stock payable onAugust 27, 2021 , to shareholders of record at the close of business onAugust 20, 2021 . See "Note 14-Subsequent Events" to the condensed consolidated financial statements ofBrigham Minerals included elsewhere in this Quarterly Report for further discussion. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board of Directors. Our Board of Directors' determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our results of operations, financial condition, capital requirements, contractual restrictions, restrictions imposed by applicable law and other factors that the Board of Directors deems relevant at the time of such determination. Cash Flows The following table summarizes our cash flows for the periods indicated: Six Months Ended June
30,
(In thousands) 2021
2020
Net cash provided by operating activities$ 45,131 $ 38,617 Net cash used in investing activities (36,358)
(27,476)
Net cash used in financing activities (11,503) (45,809)
Analysis of Cash Flow Changes For the Six Months Ended
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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 ended June 30, 2021 as compared to the
six months ended June 30, 2020 is primarily due to the 83% increase in realized
commodity prices during the six months ended June 30, 2021 , partially offset by
the 7% decrease in production volumes and the increases in operating expenses
during such period discussed above.
Net cash used in investing activities
Net cash used in investing activities is primarily comprised of acquisitions of
mineral and royalty interests, net of dispositions. For the six months ended
June 30, 2021 , our net cash used in investing activities was primarily a result
of acquisitions of mineral and royalty interests totaling $36.3 million . For the
six months ended June 30, 2020 , our net cash used in investing activities was
primarily a result of acquisitions of mineral and royalty interests of $28.8
million , partially offset by sales of mineral and royalty interests totaling
$1.6 million . The increase in cash used in investing activities for the six
months ended June 30, 2021 compared to the six months ended June 30, 2020 was
primarily a result of overall market improvements due to gradual lifting of
COVID-19 restrictions during the six months ended June 30, 2021 . Overall market
challenges associated with the COVID-19 pandemic and the decrease in oil prices
during the second quarter of 2020 resulted in a decrease in investing activities
for the six months ended June 30, 2020 . See "Item 2-Management's Discussion and
Analysis of Financial Condition and Results of Operations-Overview-Market
Environment and COVID-19" for further discussion.
Net cash used in financing activities
Net cash used in financing activities for the six months ended June 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 , partial repayment of our revolving credit facility of $4.0 million and
payment of employee tax withholding for settlement of equity compensation awards
of $1.1 million . This was partially offset by borrowings under our revolving
credit facility of $27.0 million . Net cash used in financing activities for the
six months ended June 30, 2020 was primarily due to the dividends paid to
holders of our Class A common stock of $25.8 million and distributions to
holders of temporary equity of $19.8 million .
Revolving Credit Facility
On May 16, 2019 , Brigham Resources entered into a credit agreement with Wells
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 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 three and six months ended
June 30, 2021 was 1.98% and 1.95%, respectively. As of June 30, 2021 , the
elected borrowing base on our revolving credit facility was $135.0 million , with
outstanding borrowings of $43.0 million , resulting in $92.0 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. The applicable margin is based on utilization of our revolving credit
facility and ranges from (a) in the case of adjusted base rate loans, 0.750% to
1.750% and (b) in the case of adjusted LIBOR rate loans, 1.750% to 2.750%.
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.
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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.
On July 7, 2021 , the borrowing base and elected commitments on our revolving
credit facility were increased from $135.0 million to $165.0 million . Pro-forma
for the increase in the borrowing base, the Company would have had total
liquidity of $128.4 million as of June 30, 2021 . See "Note 14-Subsequent Events"
to the condensed consolidated financial statements of Brigham Minerals included
elsewhere in this Quarterly Report for further discussion.
Off-Balance Sheet Arrangements
As of June 30, 2021 , we did not have any material off-balance sheet
arrangements.
Contractual Obligations
A summary of our contractual obligations as of June 30, 2021 , is provided in the
following table.
By Year:
(In thousands) 2021 2022 2023 2024 2025 Thereafter Total
Long-term debt obligations (1) (2) $ - $ - $ -$ 43,000 $ - $ -$ 43,000 Office lease 640 1,310 1,347 1,384 1,419 2,251 8,351 Total$ 640 $ 1,310 $ 1,347 $ 44,384 $ 1,419 $ 2,251 $ 51,351 (1) As ofJune 30, 2021 , we had$43.0 million outstanding under our revolving credit facility and$92.0 million of additional borrowing capacity. (2) Does not include future unutilized fees, amortization of deferred financing costs, interest expense or other fees related to our revolving credit facility because we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Critical Accounting Policies and Related Estimates As ofJune 30, 2021 , there have been no material changes to our critical accounting policies and related estimates previously disclosed in our Annual Report. See "Note 2-Summary of Significant Accounting Policies." Item 3. - Quantitative and Qualitative Disclosures about Market Risk We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Commodity Price Risk Our major market risk exposure is in the pricing that our operators receive for the oil, natural gas and NGLs produced from our properties. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs inthe United States . Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue 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 inApril 2020 to a high of$77.41 per barrel inJune 2018 , and as ofJune 30, 2021 , the posted price for oil was$73.52 per barrel. NGL prices generally correlate to the price of oil, and accordingly prices for these products have likewise fluctuated and are likely to continue following that market. Prices for domestic natural gas have also fluctuated 37 -------------------------------------------------------------------------------- Table of Contents significantly over the last several years. During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of$1.33 per MMBtu inSeptember 2020 to a high of$23.86 per MMBtu inFebruary 2021 , and as ofJune 30, 2021 , the Henry Hub spot market price of natural gas was$3.79 per MMBtu. The prices our operators receive for the oil, natural gas and NGLs produced from our properties depend on numerous factors beyond their and our control, some of which are previously disclosed under "Risk Factors" in our Annual Report. A$1.00 per barrel change in our realized oil price would have resulted in a$0.8 million change in our oil revenues for the six months endedJune 30, 2021 . A$0.10 per Mcf change in our realized natural gas price would have resulted in a$0.3 million change in our natural gas revenues for the six months endedJune 30, 2021 . A$1.00 per barrel change in NGL prices would have resulted in a$0.3 million change in our NGL revenues for the six months endedJune 30, 2021 . Total revenues for the six months endedJune 30, 2021 was comprised of 69% from oil sales, 17% from natural gas sales, and 11% from NGL sales. We may enter into derivative instruments, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGL prices and provide increased certainty of cash flows for our debt service requirements. However, these instruments provide only partial price protection against declines in oil, natural gas and NGL prices and may partially limit our potential gains from future increases in prices. 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 oil or gas derivatives contracts in place sinceDecember 31, 2019 . Counterparty and Customer Credit Risk When we enter into them, our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral if they are a party to our revolving credit facility, we do evaluate the credit standing of such counterparties as we deem appropriate. Our principal exposures to credit risk are through receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Interest Rate Risk 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, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans, 1.750% to 2.750%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months, for adjusted LIBOR rate loans. Interest on adjusted base rate loans is payable quarterly in arrears, and interest on adjusted LIBOR rate loans 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. The weighted average interest rate for the three and six months endedJune 30, 2021 was 1.98% and 1.95%, respectively. As ofJune 30, 2021 , the elected borrowing base on our revolving credit facility was$135.0 million , with outstanding borrowings of$43.0 million , resulting in$92.0 million available for future borrowings. A 1-percentage-point increase in our interest rate would have increased our interest expense by$0.1 million for the three months endedJune 30, 2021 . Item 4. - Controls and Procedures Evaluation of Disclosure Controls and Procedures As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer ("CEO"), our principal executive officer, and our Chief Financial Officer ("CFO"), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as ofJune 30, 2021 . Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in theSEC's rules and forms, and that such information is accumulated and communicated to our management, including our CEO and 38
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Table of Contents CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective atJune 30, 2021 . Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting (identified in connection with the evaluation required by Rules 13a-15(d) and 15d-15(d) of the Exchange Act) that occurred during the second quarter of 2021 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
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