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 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 ofSeptember 30, 2022 , we owned 82,175 net royalty acres across 38 counties within theDelaware and Midland Basins inWest Texas andNew Mexico , theAnadarko Basin inOklahoma , theDenver -Julesburg ("DJ") Basin inColorado andWyoming and theWilliston Basin inNorth Dakota .
Merger Announcement
OnSeptember 6, 2022 , the Company andBrigham LLC , entered into an Agreement and Plan of Merger (as amended from time to time, the "merger agreement") with Sitio Royalties Corp., aDelaware corporation ("Sitio"),Sitio Royalties Operating Partnership, LP ("Opco LP "),Snapper Merger Sub I, Inc. ("New Sitio"),Snapper Merger Sub IV, Inc. ("Brigham Merger Sub"),Snapper Merger Sub V, Inc. ("Sitio Merger Sub") andSnapper Merger Sub II, LLC ("Opco Merger Sub LLC "). Pursuant to the terms of the merger agreement, Sitio will acquire the Company in an all-stock transaction through: (i) the merger of Brigham Merger Sub with and into the Company (the "Brigham Merger"), with the Company surviving the Brigham Merger as a wholly owned subsidiary of New Sitio, (ii) simultaneously with the Brigham Merger, the merger of Sitio Merger Sub with and into Sitio (the "Sitio Merger" and together with the Brigham Merger, the "Pubco Mergers"), with Sitio surviving the Sitio Merger as a wholly owned subsidiary of New Sitio, and (iii) immediately thereafter, the merger ofOpco Merger Sub LLC with and intoBrigham LLC (the "Opco Merger," and, together with the Brigham Merger and the Sitio Merger, the "Mergers"), withBrigham LLC surviving the Opco Merger as a wholly owned subsidiary ofOpco LP , in each case on the terms set forth in the merger agreement. The Sitio Merger and the Brigham Merger shall become effective concurrently (such time as the Sitio Merger and the Brigham Merger become effective, the "First Effective Time"), and the Opco Merger shall become effective immediately following the First Effective Time (such time as the Opco Merger becomes effective, the "Second Effective Time"). If the mergers are completed, (i) at the First Effective Time, (A) each share of the Company's Class A common stock, par value$0.01 per share (the "Brigham Class A Common Stock"), issued and outstanding immediately prior to the First Effective Time will be converted into the right to receive 1.133 fully-paid and nonassessable shares of Class A common stock, par value$0.0001 per share, of New Sitio (the "New Sitio Class A Common Stock"), (B) each share of the Company's Class B common stock, par value$0.01 per share (the "Brigham Class B Common Stock"), issued and outstanding immediately prior to the First Effective Time will be converted into the right to receive 1.133 fully-paid and nonassessable shares of Class C common stock, par value$0.0001 per share, of New Sitio (the "New Sitio ClassC Common Stock" and together with the New Sitio Class A Common Stock, the "New Sitio Common Stock"), (C) each share of Sitio's Class A common stock, par value$0.0001 per share (the "Sitio Class A Common Stock"), issued and outstanding immediately prior to the First Effective Time will be converted into one share of New Sitio Class A Common Stock and (D) each share of Sitio's Class C common stock, par value$0.0001 per share 23 -------------------------------------------------------------------------------- Table of Contents (the "Sitio ClassC Common Stock"), issued and outstanding immediately prior to the First Effective Time, will be converted into one share of New Sitio ClassC Common Stock, in each case, excluding shares owned by us, Sitio or any of our or Sitio's wholly owned subsidiaries and, to the extent applicable, shares owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to the Delaware General Corporation Law (the "DGCL") and, (ii) at the Second Effective Time, each Brigham LLC Unit issued and outstanding immediately prior to the Second Effective Time will be converted into the right to receive 1.133 common units representing limited partnership interests inOpco LP (the "Opco LP Units"). Sitio stockholders immediately prior to the First Effective Time will own approximately 54% of the outstanding shares of New Sitio after the Pubco Mergers, and the Company's stockholders immediately prior to the First Effective Time will own approximately 46% of the outstanding shares of New Sitio after the Pubco Mergers. The Mergers have been unanimously approved by the boards of directors of both companies. The closing of the Mergers is subject to customary closing conditions, including regulatory clearance and approvals by the shareholders of Sitio and the Company. The merger agreement contains termination rights for each of the Company and Sitio, including, among others, if the consummation of the merger does not occur on or beforeJune 6, 2023 . Upon termination of the merger agreement under specified circumstances, the Company may be required to pay Sitio a termination fee equal to$65.0 million . Upon termination of the merger agreement under specified circumstances, Sitio may be required to pay the Company a termination fee equal to$75.0 million .
Financial and Operational Overview
•Our production volume of 15,000 Boe/d (73% liquids, 50% oil) for the three months endedSeptember 30, 2022 increased 15% compared to the three months endedJune 30, 2022 . Our production volume of 13,361 Boe/d (72% liquids, 51% oil) for the nine months endedSeptember 30, 2022 increased 49% compared to the nine months endedSeptember 30, 2021 . •Our mineral and royalty revenues composed of crude oil, natural gas and NGL sales of$92.8 million for the three months endedSeptember 30, 2022 increased 3% compared to the three months endedJune 30, 2022 due to 15% higher production volumes, offset by a 12% decrease in realized commodity pricing. Our mineral and royalty revenues of$253.1 million for the nine months endedSeptember 30, 2022 increased 131% compared to the nine months endedSeptember 30, 2021 due to a 55% increase in realized commodity pricing and a 49% increase in production volumes. •Our net income was$44.4 million for the three months endedSeptember 30, 2022 , inclusive of$7.8 million of merger-related costs. Adjusted Net Income for the three months endedSeptember 30, 2022 was$52.2 million , up 4% from the three months endedJune 30, 2022 . Our net income was$133.7 million for the nine months endedSeptember 30, 2022 , inclusive of$7.8 million of merger-related costs. Adjusted Net Income for the nine months endedSeptember 30, 2022 was$141.5 million , up 205% from the nine months endedSeptember 30, 2021 . Adjusted Net Income is a non-GAAP financial measure. For a definition of Adjusted Net Income 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." •Adjusted EBITDA and Adjusted EBITDA ex lease bonus were$82.1 million and$80.7 million , respectively, for the three months endedSeptember 30, 2022 and increased 3% and 2%, respectively, as compared to the three months endedJune 30, 2022 . Adjusted EBITDA and Adjusted EBITDA ex lease bonus were$222.5 million and$219.1 million , respectively, for the nine months endedSeptember 30, 2022 and increased 140% and 147%, respectively, as compared to the nine months endedSeptember 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." •OnNovember 2, 2022 , the Board of Directors ofBrigham Minerals declared a dividend of$0.81 per share of Class A common stock payable onNovember 25, 2022 to stockholders of record at the close of business onNovember 18, 2022 . •As ofSeptember 30, 2022 ,Brigham Minerals had a cash balance of$33.0 million and$217.0 million of capacity on our revolving credit facility, providing the Company with total liquidity of$250.0 million . 24
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Midland Acquisition
OnAugust 22, 2022 ,Brigham LLC entered into a definitive purchase and sale agreement (the "Purchase Agreement") withAvant Royalties, LP ,Avant Royalties II, LP andAvant Royalties II Sidecar Fund, LP (collectively, the "Sellers"), pursuant to whichBrigham LLC agreed to acquire certain mineral and royalty interests from the Sellers (the "Midland Acquisition") for$132.5 million in cash, subject to customary closing adjustments. The Midland Acquisition was completed onOctober 21, 2022 and has an effective date ofJuly 1, 2022 . The Company financed the Midland Acquisition through a combination of cash on hand and borrowings under the Company's revolving credit facility.
Market Environment and
The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as global supply chain disruptions and inflation, war and political instability in oil producing countries, government regulations (both inthe United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control. For example, the global public health crisis associated with the COVID-19 pandemic has had an adverse effect on global economic activity and the oil and natural gas industry, including reduced demand for the commodities produced by the oil and natural gas industry and depressed commodity prices. In connection with the market and commodity price challenges experienced during the COVID-19 pandemic in 2020, we saw reduced levels of potential acquisition opportunities. With the improvements in demand and 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 ongoing 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. 25
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Operational UpdateMineral and Royalty Interest Ownership Update
During the third quarter 2022, the Company completed 12 ground game transactions acquiring approximately 365 net royalty acres (standardized to a 1/8th royalty interest) and deploying$12.2 million in capital. The Company deployed substantially all of its mineral acquisition capital in the third quarter to thePermian Basin . As ofSeptember 30, 2022 , the Company owned roughly 82,175 net royalty acres, encompassing 11,222 gross (88.7 net) undeveloped horizontal locations, across 38 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 table below summarizes the Company's mineral and royalty interest ownership at the dates indicated.
Delaware Midland Anadarko DJ Williston Total
Net Royalty Acres
September 30, 2022 30,150 9,235 9,850 24,755 8,185 82,175
June 30, 2022 30,010 9,015 9,850 24,755 8,180 81,810
Acres Added and (Sold) Q/Q 140 220 - - 5 365
% Added and (Sold) Q/Q -% 2% -% -% -% -%
Operating Activity Update
DUC Conversions
The Company identified 307 gross (1.9 net) DUCs converted to production during
the third quarter 2022, which represented 30% of its net DUCs (28% of its gross
DUCs) in inventory as of second quarter 2022. Third quarter 2022 gross DUC and
PDP conversion waterfalls are summarized in the charts below:
[[Image Removed: mnrl-20220930_g1.jpg]]
[[Image Removed: mnrl-20220930_g2.jpg]]
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Drilling Activity
During the third quarter 2022, the Company identified 207 gross (1.7 net) wells
spud on its mineral position, which represents a 13% increase in net well
drilling activity relative to second quarter 2022. Brigham's gross and net wells
spud activity per quarter is summarized in the chart below:
[[Image Removed: mnrl-20220930_g3.jpg]]DUC and Permit Inventory
Development Inventory by Basin (1)
Delaware Midland Anadarko DJ Williston Total
Gross Inventory
DUCs 207 368 18 166 170 929
Permits 355 149 5 149 199 857
Net Inventory
DUCs 2.5 1.8 0.1 2.0 0.4 6.7
Permits 2.0 0.7 - 0.9 0.4 4.1
(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 . 28 -------------------------------------------------------------------------------- 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. The Inflation Reduction Act InAugust 2022 ,President Biden signed the Inflation Reduction Act of 2022 ("IRA 2022") into law. Among other provisions, the IRA 2022 imposes the first ever federal fee on the emissions of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emissions of certain sources in the oil and gas sector, starting at$900 per metric ton of leaked methane and rising to$1,200 in 2025 and$1,500 for 2026 and thereafter. The imposition of this fee and other provisions contained within the IRA 2022 could increase costs for the operators of our properties, and consequently could adversely affect production from our mineral interests and further accelerate the transition away from the use of fossil fuels, which could also adversely affect our business. 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.
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Table of Contents 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 inApril 2020 to a high of$123.64 per barrel inMarch 2022 . 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 . As ofSeptember 30, 2022 , the posted price for oil was$79.91 per barrel and the Henry Hub spot market price of natural gas was$6.40 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 ongoing conflict betweenRussia andUkraine , 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 inthe 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 inthe 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.
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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 September 30, 2022
and September 30, 2021 , the SEC oil price and SEC gas price used in the
calculation of the ceiling test were $91.71 and $57.69 , respectively, per barrel
for oil, and $6.07 and $3.00 , respectively, per MMBtu for natural gas. There
were no impairment charges during the three and nine months ended September 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 ofSeptember 30, 2022 andDecember 31, 2021 .
Non-GAAP Financial Measures
Adjusted Net Income, Adjusted EBITDA, and Adjusted EBITDA ex lease bonus are
non-GAAP supplemental financial measures used by our management and by external
users of our financial statements such as investors, research analysts and
others to assess the financial performance of our assets and their ability to
sustain dividends over the long term without regard to financing methods,
capital structure or historical cost basis.
We define Adjusted Net Income as net income excluding the impacts of
merger-related costs. We define Adjusted EBITDA as Adjusted 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 Net Income, Adjusted EBITDA, and Adjusted EBITDA ex lease bonus do not
represent and should not be considered alternatives to, or more meaningful than,
net income or any other measure of financial performance presented in accordance
with GAAP as measures of our financial performance. Adjusted Net Income,
Adjusted EBITDA, and Adjusted EBITDA ex lease bonus have important limitations
as analytical tools because they exclude some but not all items that affect net
income, the most directly comparable GAAP financial measure. Our computation of
Adjusted Net Income, Adjusted EBITDA, and Adjusted EBITDA ex lease bonus may
differ from computations of similarly titled measures of other companies.
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The following table presents a reconciliation of Adjusted Net Income, Adjusted
EBITDA, and Adjusted EBITDA ex lease bonus to the most directly comparable GAAP
financial measure for the periods indicated (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30, September 30,
2022 June 30, 2022 2022 2021
Reconciliation of Adjusted Net Income, Adjusted
EBITDA, and Adjusted EBITDA ex lease bonus to
Net Income:
Net Income $ 44,443 $ 50,180 $ 133,688 $ 46,308
Add:
Merger-related costs 7,769 - 7,769 -
Adjusted Net Income $ 52,212
14,964 13,449 40,726 27,129
Share-based compensation expense 1,961 1,959 5,401 7,537
Interest expense, net 1,046 1,154 3,114 1,105
Income tax expense 11,950 12,957 31,820 10,717
Less:
Other income, net 6 14 40 51
Adjusted EBITDA $ 82,127
1,456 476 3,365 3,894
Adjusted EBITDA ex lease bonus $ 80,671 $ 79,209 $ 219,113 $ 88,851
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 Nine Months Ended
September 30, 2022 June 30, 2022 September 30, 2022 September 30, 2021
Royalty revenues
Oil sales 71 % 73 % 72 % 69 %
Natural gas sales 17 % 15 % 16 % 17 %
NGL sales 10 % 11 % 11 % 11 %
Total royalty revenue 98 % 99 % 99 % 97 %
Lease bonus and other revenues 2 % 1 % 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, including certain costs related
to the pending merger with Sitio.
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. 33
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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
September 30,
2022 June 30, 2022 Variance
Production:
Oil (MBbls) 691 612 79 13 %
Natural gas (MMcf) 2,259 2,011 248 12 %
NGLs (MBbls) 312 237 75 32 %
Equivalents (MBoe) 1,379 1,185 194 16 %
Equivalents per day (Boe/d) 15,000 13,019 1,981 15 %
Revenues:
Oil sales $ 67,132 $ 66,415 $ 717 1 %
Natural gas sales 16,016 13,968 2,048 15 %
NGL sales 9,602 10,020 (418) (4) %
Total mineral and royalty revenue $ 92,750 $ 90,403 $ 2,347 3 %
Lease bonus and other revenue 1,456 476 980 206 %
Total revenues $ 94,206 $ 90,879 $ 3,327 4 %
Realized prices
Oil ($/Bbl) $ 97.20 $ 108.37 $ (11.17) (10) %
Natural gas ($/Mcf) 7.09 6.95 0.14 2 %
NGLs ($/Bbl) 30.70 42.31 (11.61) (27) %
Equivalents ($/Boe) $ 67.21 $ 76.31 $ (9.10) (12) %
Operating expenses:
Gathering, transportation and marketing $ 2,962 $ 2,246 $ 716 32 %
Severance and ad valorem taxes 5,972 5,361 611 11 %
Depreciation, depletion, and amortization 14,964 13,449 1,515 11 %
General and administrative (before
share-based compensation) 10,914 3,587 7,327 204 %
Total operating expenses (before share-based
compensation) $ 34,812 $ 24,643 $ 10,169 41 %
General and administrative, share-based
compensation 1,961 1,959 2 - %
Total operating expenses $ 36,773 $ 26,602 $ 10,171 38 %
Other expenses:
Interest expense, net $ 1,046 $ 1,154 $ (108) (9) %
Unit Expenses ($/Boe)
Gathering, transportation and marketing $ 2.15 $ 1.90 $ 0.25 13 %
Severance and ad valorem taxes 4.33 4.52 (0.19) (4) %
Depreciation, depletion and amortization 10.84 11.35 (0.51) (4) %
General and administrative (before
share-based compensation) (1) 7.91 3.03 4.88 161 %
General and administrative, share-based
compensation 1.42 1.65 (0.23) (14) %
Interest expense, net 0.76 0.97 (0.21) (22) %
(1)General and administrative expenses (before share-based compensation) for the
three months ended September 30, 2022 include costs related to the Mergers of
$7.8 million , or $5.63 per Boe.
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Revenues
Total revenues for the three months ended September 30, 2022 increased 4%, or
$3.3 million , compared to the three months ended June 30, 2022 . The increase was
attributable to a $2.3 million increase in mineral and royalty revenues and a
$1.0 million increase in lease bonus and other revenues during the period. The
increase in mineral and royalty revenue was primarily attributable to the 15%
increase in production volumes to 15,000 Boe/d, resulting in an increase in
royalty revenues of $14.9 million , partially offset by a 12% decrease in
realized commodity prices, resulting in a decrease in royalty revenues of $12.6
million . During the three months ended September 30, 2022 , we collected revenues
attributable to first payments received on production from numerous new wells
turned-in-line at high initial flow rates on high-interest acreage in the
Delaware and Midland basins. We typically receive first payment from an operator
several months or longer after initial production, which typically covers
multiple months of production, and as such, high-interest wells or wells with
robust initial production rates can have a significant impact on revenues for
the period in which first payments are collected.
Oil revenues for the three months ended September 30, 2022 increased 1%, or $0.7
million , compared to the three months ended June 30, 2022 . The increase in oil
revenues was attributable to the 13% increase in oil production volumes to 7,507
barrels per day, resulting in an $8.4 million increase in oil revenues,
partially offset by the 10% decrease in realized oil prices to $97.20 per
barrel, resulting in a decrease in revenues of $7.7 million .
Natural gas revenues for the three months ended September 30, 2022 increased
15%, or $2.0 million , compared to the three months ended June 30, 2022 . The
increase in natural gas revenues was attributable to the 12% increase in natural
gas production volumes to 24,561 Mcf per day, resulting in a $1.7 million
increase in natural gas revenues, and the 2% increase in realized natural gas
prices to $7.09 per Mcf, resulting in an increase in revenues of $0.3 million .
NGL revenues for the three months ended September 30, 2022 decreased 4%, or $0.4
million , compared to the three months ended June 30, 2022 . The decrease in NGL
revenues was attributable to the 27% decrease in realized NGL prices to $30.70
per barrel, resulting in a decrease in NGL revenues of $3.6 million , partially
offset by a 32% increase in NGL production volumes to 3,399 Boe per day,
resulting in a $3.2 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$1.0 million increase in revenues from lease bonus payments for the three months endedSeptember 30, 2022 was primarily attributable to increases in leasing activity in thePermian Basin . 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
ended September 30, 2022 , GTM expenses increased 32% compared to the three
months ended June 30, 2022 , which is attributable to increased production
volumes, including an increase in natural gas and NGL volumes in the Permian
Basin .
Severance and ad valorem taxes. For the three months ended September 30, 2022 ,
severance and ad valorem taxes increased 11% compared to the three months ended
June 30, 2022 , primarily due to the increase in mineral and royalty revenues,
which was driven by increased production volumes, partially offset by declines
in realized commodity prices.
Depreciation, depletion and amortization. DD&A expense increased 11%, or $1.5
million , for the three months ended September 30, 2022 as compared to the three
months ended June 30, 2022 , predominantly due to higher production volumes.
General and administrative and share-based compensation. General and
administrative expense (before share-based compensation) increased 204%, or $7.3
million , for the three months ended September 30, 2022 compared to the three
months ended June 30, 2022 , primarily as a result of costs related to the
Mergers of $7.8 million .
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Share-based compensation expense for the three months ended September 30, 2022
was $2.0 million , net of $0.9 million of share-based compensation cost
capitalized to unevaluated property, $0.6 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 ended June 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. See table below for additional details (in
thousands).
Three Months Ended
September 30, 2022 June 30, 2022 Variance
Incentive units $ 178 $ 178 $ -
RSAs - 39 (39)
RSUs 2,149 2,127 22
PSUs 1,187 1,173 14
STIP awards 68 67 1
Capitalized share-based compensation (1,621) (1,625) 4
Total share-based compensation expense
1,959
Interest expense, net. Interest expense, net decreased$0.1 million for the three months endedSeptember 30, 2022 compared to the three months endedJune 30, 2022 , primarily due to the sequential decrease of the weighted average debt outstanding on our revolving credit facility from$107.6 million to$73.0 million as shown in the table below (in thousands, except for interest rate). Three Months Ended September 30, 2022 June 30, 2022 Variance Interest expense - revolving credit facility $ 704 $ 900$ (196) Commitment fees 208 172 36 Amortization of loan closing costs 187 149 38 Interest income (53) (67) 14 Total interest expense, net $ 1,046$ 1,154 $ (108) Total weighted average interest rate 3.77 % 3.31 % Total weighted average debt balance $ 73,000
During the three months endedSeptember 30, 2022 , a portion of our debt outstanding was grandfathered at original LIBOR benchmark pricing through the expiration of the applicable interest periods. We expect our weighted average interest rate to rise during the fourth quarter of 2022 as all of our outstanding borrowings will be based on current SOFR rates. 36 -------------------------------------------------------------------------------- Table of Contents Nine Months EndedSeptember 30, 2022 Compared to Nine Months EndedSeptember 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): Nine Months Ended September 30, 2022 2021 Variance Production: Oil (MBbls) 1,855 1,245 610 49 % Natural gas (MMcf) 6,138 4,441 1,697 38 % NGLs (MBbls) 769 471 298 63 % Equivalents (MBoe) 3,647 2,456 1,191 48 % Equivalents per day (Boe/d) 13,361 8,996 4,365 49 % Revenues: Oil sales$ 184,235 $ 78,022 $ 106,213 136 % Natural gas sales 40,296 19,450 20,846 107 % NGL sales 28,617 12,182 16,435 135 % Total mineral and royalty revenue$ 253,148 $ 109,654 $ 143,494 131 % Lease bonus and other revenue 3,365 3,894 (529) (14) % Total revenues$ 256,513 $ 113,548 $ 142,965 126 % Realized prices Oil ($/Bbl) $ 99.32$ 62.68 $ 36.64 58 % Natural gas ($/Mcf) 6.56 4.38 2.18 50 % NGLs ($/Bbl) 37.19 25.87 11.32 44 % Equivalents ($/Boe) $ 69.40$ 44.65 $ 24.75 55 % Operating expenses: Gathering, transportation and marketing $ 7,211$ 4,967 $ 2,244 45 % Severance and ad valorem taxes 15,664 6,505 9,159 141 % Depreciation, depletion, and amortization 40,726 27,129 13,597 50 % General and administrative (before share-based compensation) 18,929 9,331 9,598 103 % Total operating expenses (before share-based compensation) $ 82,530$ 47,932 $ 34,598 72 % General and administrative, share-based compensation 5,401 7,537 (2,136) (28) % Total operating expenses $ 87,931$ 55,469 $ 32,462 59 % Other expenses: Interest expense, net $ 3,114$ 1,105 $ 2,009 182 % Unit Expenses ($/Boe) Gathering, transportation and marketing $ 1.98$ 2.02 $ (0.04) (2) % Severance and ad valorem taxes 4.29 2.65 1.64 62 % Depreciation, depletion and amortization 11.17 11.05 0.12 1 % General and administrative (before share-based compensation) (1) 5.19 3.80 1.39 37 % General and administrative, share-based compensation 1.48 3.07 (1.59) (52) % Interest expense, net 0.85 0.45 0.40 89 % (1)General and administrative expenses (before share-based compensation) for the nine months endedSeptember 30, 2022 include costs related to the Mergers of$7.8 million , or$2.13 per Boe. 37 -------------------------------------------------------------------------------- Table of Contents Revenues Total revenues for the nine months endedSeptember 30, 2022 increased 126%, or$143.0 million , compared to the nine months endedSeptember 30, 2021 . The increase was attributable to a$143.5 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 55% increase in realized commodity prices, resulting in an increase in royalty revenues of$90.3 million , and a 49% increase in production volumes to 13,361 Boe/d, resulting in an increase in royalty revenues of$53.2 million . Oil revenues for the nine months endedSeptember 30, 2022 increased 136%, or$106.2 million , compared to the nine months endedSeptember 30, 2021 . The increase in oil revenues was attributable to the 58% increase in realized oil prices to$99.32 per barrel, resulting in an increase in revenues of$68.0 million , and a 49% increase in oil production volumes to 6,795 barrels per day, resulting in a$38.2 million increase in oil revenues. Natural gas revenues for the nine months endedSeptember 30, 2022 increased 107%, or$20.9 million , compared to the nine months endedSeptember 30, 2021 . The increase in natural gas revenues was attributable to the 50% increase in realized natural gas prices to$6.56 per Mcf, resulting in an increase in revenues of$13.5 million , and a 38% increase in natural gas production volumes to 22,484 Mcf per day, resulting in a$7.4 million increase in natural gas revenues. NGL revenues for the nine months endedSeptember 30, 2022 increased 135%, or$16.4 million , compared to the nine months endedSeptember 30, 2021 . The increase in NGL revenues was attributable to the 44% increase in realized NGL prices to$37.19 per barrel, resulting in an increase in NGL revenues of$8.7 million , and a 63% increase in NGL production volumes to 2,819 Boe per day, resulting in a$7.7 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$0.5 million decrease in revenues from lease bonus payments for the nine months endedSeptember 30, 2022 was primarily attributable to decreases in leasing activity in theAnadarko and DJ Basins. 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 nine months
ended September 30, 2022 , GTM expenses increased 45% compared to the nine months
ended September 30, 2021 , which is attributable to increased production volumes.
Severance and ad valorem taxes. For the nine months ended September 30, 2022 ,
severance and ad valorem taxes increased 141% compared to the nine months ended
September 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 50%, or $13.6
million , for the nine months ended September 30, 2022 as compared to the nine
months ended September 30, 2021 , predominantly due to higher production volumes.
General and administrative and share-based compensation. General and
administrative expense (before share-based compensation) increased 103%, or $9.6
million , for the nine months ended September 30, 2022 compared to the nine
months ended September 30, 2021 primarily as a result of costs related to the
Mergers of $7.8 million . The remaining increase is primarily due to $1.4 million
of incremental compensation costs resulting from 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.
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Share-based compensation expense for the nine months ended September 30, 2022
was $5.4 million , net of $1.8 million of share-based compensation cost
capitalized to unevaluated property, $2.6 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 nine months ended September 30, 2021 was $7.5
million , net of $3.0 million of share-based compensation cost capitalized to
unevaluated property and $2.5 million of share-based compensation cost
capitalized to evaluated property. The decrease in share-based compensation
expense of $2.1 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 nine months
ended September 30, 2022 . See table below for additional details (in thousands).
Nine Months Ended September 30,
2022 2021 Variance
Incentive units $ 534 $ 534 $ -
RSAs 164 460 (296)
RSUs 5,702 7,602 (1,900)
PSUs 3,334 4,416 (1,082)
STIP awards 143 - 143
Capitalized share-based compensation (4,476) (5,475) 999
Total share-based compensation expense $ 5,401 Interest expense, net. Interest expense, net increased$2.0 million for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 , primarily due to the increase of the weighted average debt outstanding on our revolving credit facility from$36.3 million to$91.1 million as shown in the table below (in thousands, except for interest rate). Nine Months Ended September 30, 2022 2021 Variance
Interest expense - revolving credit facility $ 2,296
$ 585 $ 1,711 Commitment fees 508 343 165 Amortization of loan closing costs 467 217 250 Interest income (157) (40) (117) Total interest expense, net $ 3,114$ 1,105 $ 2,009 Total weighted average interest rate 3.31 %
2.13 %
Total weighted average debt balance$ 91,132 $ 36,256 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 ofSeptember 30, 2021 ,Brigham Minerals owned a 79.7% interest inBrigham LLC and the Brigham LLC Unit Holders owned 20.3% 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 14.5% of the outstanding voting stock ofBrigham Minerals as ofSeptember 30, 2021 . 39
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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 ofSeptember 30, 2022 ,Brigham Minerals owned an 89.6% interest inBrigham LLC and the Brigham LLC Unit Holders owned 10.4% 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 ofSeptember 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. 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 nine months endedSeptember 30, 2022 , we deployed approximately$93.4 million for acquisition-related capital expenditures, inclusive of$4.4 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
September 30, 2022
Cash and cash equivalents $ 32,995
Revolving credit facility availability $ 217,000
Total liquidity $ 249,995
40-------------------------------------------------------------------------------- Table of Contents Working Capital Our working capital, which we define as current assets minus current liabilities, totaled$83.0 million atSeptember 30, 2022 , as compared to$33.1 million atDecember 31, 2021 . 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$33.0 million and$20.8 million atSeptember 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 nine months endedSeptember 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 August 2, 2022 August 19, 2022 August 26, 2022 $ 0.77 $ 41,806
(1) Dividends paid to holders of Class A common stock.
OnNovember 2, 2022 , the Board of Directors ofBrigham Minerals declared a dividend of$0.81 per share of Class A common stock payable onNovember 25, 2022 , to stockholders of record at the close of business onNovember 18, 2022 . See "Note 14-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):
Nine Months Ended September 30,
2022 2021
Net cash provided by operating activities $ 162,727 $ 72,365
Net cash provided by (used in) investing activities 1,249 (44,790)
Net cash used in financing activities (145,371) (22,425)
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Analysis of Cash Flow Changes For the Nine Months Ended
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 nine months endedSeptember 30, 2022 as compared to the nine months endedSeptember 30, 2021 was primarily due to the 55% increase in realized commodity prices during the nine months endedSeptember 30, 2022 and the 49% 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 nine months endedSeptember 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$71.7 million . For the nine months endedSeptember 30, 2021 , our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests of$49.2 million , partially offset by sales of mineral and royalty interests totaling$4.4 million .
Net cash used in financing activities
Net cash used in financing activities for the nine months endedSeptember 30, 2022 was primarily due to the dividends paid to holders of our Class A common stock of$97.6 million , net repayments under our revolving credit facility of$20.0 million , distributions to holders of non-controlling interest of$17.5 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 nine months endedSeptember 30, 2021 was primarily due to the dividends paid to holders of our Class A common stock of$41.4 million , distributions to holders of non-controlling interest of$12.7 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$33.0 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 nine months endedSeptember 30, 2022 was 3.31%. As ofSeptember 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. We expect the Administrative Agent to recommend a deferral of the redetermination of the Company's borrowing base due to the pending merger, with the expectation that the borrowing base will be finalized in the first quarter of 2023. 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 42
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Table of Contents 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.
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 SOFR 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 ofSeptember 30, 2022 , 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."
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