Document/ExhibitDescriptionPagesSize 1: 10-Q Quarterly Report HTML 2.00M
2: EX-31.1 Certification -- §302 - SOA'02 HTML 24K
3: EX-31.2 Certification -- §302 - SOA'02 HTML 24K
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5: EX-32.2 Certification -- §906 - SOA'02 HTML 20K
11: R1 Cover HTML 77K
12: R2 Condensed Consolidated Balance Sheets HTML 129K
13: R3 Condensed Consolidated Balance Sheets HTML 41K
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14: R4 Condensed Consolidated Statements of Operations HTML 106K
15: R5 Condensed Consolidated Statements of Changes in HTML 120K
Equity
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18: R8 Summary of Significant Accounting Policies HTML 50K
19: R9 Oil and Gas Properties HTML 33K
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28: R18 Income Taxes HTML 32K
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42: R32 Summary of Significant Accounting Policies - HTML 33K
Narrative (Details)
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Schedule of Accounts Receivable (Details)
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Concentration of Credit Risk (Details)
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Acquisitions (Details)
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Disaggregation of Revenue (Details)
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(Exact name of registrant as specified in its charter)
iDelaware
i83-1106283
(State
or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
i5914 W. Courtyard Drive, iSuite
200
iAustin, iTexas
i78730
(Address
of principal executive offices)
(Zip code)
(i512) i220-6350
(Registrant’s telephone number, including area code)
___________________
Securities
registered pursuant to section 12(b) of the Act:
Title of each class
Trading symbol(s)
Name of each exchange on which registered
iClass A common stock, par value $0.01
iMNRL
iNew
York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYesx No o
Indicate
by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYesx No o
Indicate by check mark whether the
registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
iLarge
accelerated filer
☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
i☐
Emerging
growth company
i☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No x
The registrant had i54,175,458
shares of Class A common stock and i6,270,684 shares of Class B common stock outstanding as of October 31, 2022.
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
Term
Definition
Basin
A depression in the Earth's crust formed from plate tectonics providing accommodation space for the accumulation of sedimentary
rocks and organic material. When subjected to the appropriate depth and duration of burial, hydrocarbon generation can occur creating oil and natural gas bearing strata.
Bbl
One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Boe
One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d
One
Boe per day.
British thermal unit or Btu
The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion
The process of treating a drilled well followed by the installation of permanent equipment for the production of oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Development well
A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential
An
adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Drilled but Uncompleted Well (DUC)
A well that an operator has spud but has not yet begun hydraulic fracturing or completion operations.
Gross acres or gross wells
The total acres or wells, as the case may be, in which a mineral or royalty interest is owned.
MBbl
One thousand barrels of crude oil, condensate or NGLs.
MBoe
One
thousand Boe.
Mcf
One thousand cubic feet of natural gas.
Mcf/d
One Mcf per day.
MMBtu
One million British thermal units.
MMcf
One million cubic feet of natural gas.
Net royalty acre
Mineral ownership standardized to a 12.5%, or 1/8th, royalty interest.
Net
well
The percentage of net revenue interest an owner has out of a gross well. For example, an owner who has an 25% royalty interest in a single well owns 0.25 net wells.
NGLs
Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
NYMEX
The New York Mercantile Exchange.
Operator
The individual or company responsible for the development and/or production of an oil or natural gas well or lease.
Possible
reserves
Reserves that are less certain to be recovered than probable reserves.
Probable reserves
Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.
Prospect
A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves
Proved
reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Those quantities of oil, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).
Proved
undeveloped reserves or PUDs
Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The following rules apply to PUDs: (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances; (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time; and (iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which
an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Realized price
The cash market price less all applicable deductions such as quality, transportation and demand adjustments.
Reserves
Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation
that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir
A porous and permeable underground formation containing a natural accumulation of
producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty
An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Spot market price
The
cash market price without reduction for expected quality, transportation and demand adjustments.
Spud
Commenced drilling operations on an identified location.
Undeveloped acreage
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas or NGLs regardless of whether such acreage contains proved reserves.
The information in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2022 (this "Quarterly Report") includes “forward-looking statements.” All statements, other than statements of historical fact, included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management and matters relating to our pending merger with Sitio Royalties Corp. ("Sitio") are forward-looking statements. When used in this Quarterly Report, the words “may,”“could,”“believe,”“anticipate,”“intend,”“estimate,”“expect,”“project” and similar expressions and the negative
of such words and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2021 (the "Annual Report"), as well as the risk factors and other cautionary statements contained in our other filings with the United States
Securities and Exchange Commission (the "SEC").
The following important factors, in addition to those discussed elsewhere in this Quarterly Report, could affect the future results of the energy industry in general, and our company in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:
•our pending merger with Sitio and the expected timing of the consummation of the merger;
•our ability to execute on our business objectives;
•the effect of changes in commodity prices;
•the
level of production on our properties;
•risks associated with the drilling and operation of oil and natural gas wells;
•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;
•legislative or regulatory actions pertaining to hydraulic fracturing, including restrictions on the use of water;
•the availability of pipeline capacity and transportation facilities;
•the effect of existing and future laws and regulatory actions;
•the impact of derivative instruments;
•conditions
in the capital markets and our ability to obtain capital on favorable terms or at all;
•rising interest rates and its effects on our cost of capital;
•the overall supply and demand for oil, natural gas and NGLs, and regional supply and demand factors, storage availability, delays, or interruptions of production, including voluntary shut-ins;
•operator budget constraints and their ability to obtain capital on favorable terms or at all;
•the actions of the Organization of Petroleum Exporting Countries ("OPEC") and other significant producers and governments and the ability of such producers to agree to and maintain oil price and production controls;
•competition
from others in the energy industry;
•the impact of reduced drilling activity in our focus areas and uncertainty as to whether development projects will be pursued;
•the continued threat of terrorism and the impact of military and other action and armed conflict, such as the ongoing conflict between Russia and Ukraine;
•global or national health events, such as the COVID-19 pandemic;
•the effects of current or future litigation, including
the recent U.S. Supreme Court ruling involving the Muscogee (Creek) Nation reservation in Eastern Oklahoma and similar rulings regarding reservations;
•uncertainty of estimates of oil and natural gas reserves and production;
•the cost of developing the oil and natural gas underlying our properties;
•our ability to replace our oil, natural gas and NGL reserves;
•our ability to identify, complete and integrate acquisitions;
•title defects in the properties in which we invest;
•technological advances;
•weather
conditions, natural disasters and other matters beyond our control;
•general economic, business, political or industry conditions, including the impact of continued inflation and associated changes in monetary policy; and
•certain factors discussed elsewhere in this Quarterly Report.
Should one or more of the risks or uncertainties described in this Quarterly Report, our Annual Report or any of our other SEC filings occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors
on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In
addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect
events or circumstances after the date of this Quarterly Report.
Oil
and gas properties, at cost, using the full cost method of accounting:
Unevaluated property
i310,783
i338,613
Evaluated
property
i754,418
i633,138
Less
accumulated depreciation, depletion, and amortization
(i354,361)
(i239,612)
Oil
and gas properties, net
i710,840
i732,139
Other
property and equipment
i3,559
i2,060
Less
accumulated depreciation
(i1,629)
(i1,280)
Other
property and equipment, net
i1,930
i780
Operating
lease right-of-use asset
i5,883
i6,764
Deferred
tax asset
i39,485
i25,308
Other
assets, net
i1,202
i1,183
Total
assets
$
i865,477
$
i820,877
LIABILITIES
AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities
$
i21,923
$
i20,473
Current
operating lease liability
i1,211
i1,178
Total
current liabilities
i23,134
i21,651
Long-term
bank debt
i73,000
i93,000
Non-current
operating lease liability
i4,831
i5,742
Other
non-current liabilities
i2,427
i810
Equity:
Preferred
stock, $ii0.01/ par value; ii50,000,000/
authorized; iiiino///
shares issued and outstanding at September 30, 2022 and December 31, 2021
i—
i—
Class
A common stock, $ii0.01/ par value; i400,000,000
authorized, i54,734,157 shares issued and i54,175,458 shares outstanding at September 30, 2022; i400,000,000
authorized, i48,796,518 shares issued and i48,359,888 shares outstanding at December 31, 2021
i547
i488
Class
B common stock, $ii0.01/ par value; i150,000,000
authorized, ii6,270,684/ shares issued and outstanding
at September 30, 2022; i150,000,000 authorized, ii11,371,517/
shares issued and outstanding at December 31, 2021
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.iBusiness
and Basis of Presentation
Description of the Business
Brigham Minerals, Inc. (together with its wholly owned subsidiaries, "Brigham Minerals,"“we,""us,""our," or the "Company"), a Delaware corporation, is a holding company whose sole material asset consists of an i89.6% interest in
Brigham Minerals Holdings, LLC (“Brigham LLC”), which indirectly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”). The Minerals Subsidiaries acquire and actively manage a portfolio of mineral and royalty interests in the core of what we view as the most active, highly economic, liquids-rich resource plays across the continental United States.
Our portfolio is comprised of mineral and royalty interests across ifive
of the most highly economic, liquids-rich resource plays in the continental United States, including the Delaware and Midland Basins in West Texas and New Mexico, the Anadarko Basin in Oklahoma, the Denver-Julesburg (“DJ”) Basin in Colorado and Wyoming and the Williston Basin in North Dakota. Our highly technical approach towards mineral acquisitions in the geologic core of top-tier resource plays has purposefully led to a concentrated portfolio covering i38 of the most highly active counties for horizontal drilling in the continental United States.
Merger
Announcement
On September 6, 2022, the Company and Brigham LLC, entered into an Agreement and Plan of Merger (as amended from time to time, the “merger agreement”) with Sitio Royalties Corp., a Delaware 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”) and Snapper 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 of Opco Merger Sub LLC with and into Brigham LLC (the “Opco Merger,” and, together with the Brigham Merger and the Sitio Merger, the “Mergers”), with Brigham LLC surviving the Opco Merger as a wholly owned subsidiary of Opco 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 $i0.01
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 i1.133 fully-paid and nonassessable shares of Class A common stock, par value $i0.0001
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 $i0.01 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 i1.133
fully-paid and nonassessable shares of Class C common stock, par value $i0.0001 per share, of New Sitio (the “New Sitio Class C 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 $i0.0001
per share (the “Sitio Class A Common Stock”), issued and outstanding immediately prior to the First Effective Time will be converted into ione share of New Sitio Class A Common Stock and (D) each share of Sitio’s Class C common stock, par value $i0.0001
per share (the “Sitio Class C Common Stock”), issued and outstanding immediately prior to the First Effective Time, will be converted into ione share of New Sitio Class C 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 i1.133 common units representing limited partnership interests in Opco
LP (the “Opco LP Units”). Sitio stockholders immediately prior to the First Effective Time will own approximately i54% 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 i46%
of the outstanding shares of New Sitio after the Pubco Mergers.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 before June 6, 2023. Upon termination of the merger agreement under specified circumstances, the Company may be required to pay Sitio a termination fee equal to $i65.0 million.
Upon termination of the merger agreement under specified circumstances, Sitio may be required to pay the Company a termination fee equal to $i75.0 million.
i
Basis
of Presentation
The accompanying unaudited condensed consolidated interim financial statements of Brigham Minerals have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), except that, in accordance with the instructions to Form 10-Q, they do not include all of the notes required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim financial statements should be read in conjunction with our audited financial statements included in our Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") on February 28, 2022 (the "Annual Report"). The unaudited interim financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair
representation. The results of operations for the three and nine months ended September 30, 2022 are not necessarily indicative of the results to be expected for the entire fiscal year ending December 31, 2022. Brigham Minerals operates in ione segment: oil and natural gas exploration and production.
/
As
the primary beneficiary, Brigham Minerals consolidates the financial results of Brigham LLC and its subsidiaries and reports the interest related to the portion of the units in Brigham LLC not owned by Brigham Minerals as non-controlling interest, which will reduce net income attributable to the holders of Brigham Minerals' Class A common stock. For more information, see "Note 10—Non-controlling interest.”
2.iSummary
of Significant Accounting Policies
i
Use of Estimates
These condensed consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the condensed consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could
differ from these estimates. Changes in estimates are recorded prospectively.
The accompanying condensed consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGL reserves that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Brigham Minerals’ year-end
reserve estimates are audited by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Quarterly reserve estimates are internally generated by our in-house engineering staff. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, share-based compensation costs, and revenue accruals.
Significant Accounting Policies
Significant accounting policies are disclosed in Brigham Minerals' audited consolidated financial statements and notes for the year ended December 31, 2021, presented in the Annual Report. There have been no changes in such policies or the application of such policies during the three and nine months ended September
30, 2022.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
i
Accounts Receivable
Brigham
Minerals routinely reviews outstanding balances, assesses the financial strength of its operators and records a reserve for amounts not expected to be fully recovered, using a current expected credit loss model. We did inot record credit losses for the three months ended September 30, 2022. We recorded credit losses of $i0.3
million for the nine months ended September 30, 2022 and $ii0.1/ million
for the three and nine months ended September 30, 2021 which was included in general and administrative expenses.
Concentration of Credit Risk and Significant Customers
Financial instruments that potentially subject Brigham Minerals to concentrations of credit risk consist of cash, accounts receivable, and its revolving credit facility. Cash and cash equivalents are held in a few financial institutions in amounts that may, at times, exceed federally insured limits. However, no losses have been incurred and management believes that counterparty risks are minimal based on the reputation and history of the institutions selected. Accounts receivable are concentrated among operators and purchasers engaged in the energy industry within the United States. Management periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal. iConcentrations
of oil and gas sales to significant customers (operators) are presented in the table below.
Management
does not believe that the loss of any customer would have a long-term material adverse effect on our financial position or the results of operations. For the three and nine months ended September 30, 2022, we received revenues from over i170 operators with approximately ii72/%
of revenues coming from the top ten operators on our properties. For the three and nine months ended September 30, 2021, we received revenues from over i140 operators with approximately ii66/%
of revenues coming from the top ten operators on our properties.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
3.iOil
and Gas Properties
Brigham Minerals uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs incurred for the purpose of acquiring mineral and royalty interests are capitalized into a full cost pool. In addition, certain internal costs (or "capitalized general and administrative costs"), are also included in the full cost pool. Capitalized general and administrative costs were $ii3.1/
million during the three months ended September 30, 2022 and 2021 and $i9.2 million and $i8.8
million for the nine months ended September 30, 2022 and 2021, respectively. Capitalized costs do not include any costs related to general corporate overhead or similar activities, which are expensed in the period incurred. iOil and gas properties consisted of the following (in thousands):
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property
$
i310,783
$
i338,613
Evaluated
property
i754,418
i633,138
Total
oil and gas properties, at cost
i1,065,201
i971,751
Less
accumulated depreciation, depletion, and amortization
(i354,361)
(i239,612)
Total
oil and gas properties, net
$
i710,840
$
i732,139
Capitalized
costs are depleted on a unit of production basis based on proved oil and natural gas reserves. Depletion expense was $i14.8 million and $i8.6 million
for the three months ended September 30, 2022 and 2021, respectively, and $i40.4 million and $i27.0
million for the nine months ended September 30, 2022 and 2021, respectively. The increases in depletion expense recognized in the three and nine months ended September 30, 2022 were primarily due to higher production volumes. Average depletion of proved properties was $i10.76 per Boe and $i10.34
per Boe for the three months ended September 30, 2022 and 2021, respectively, and $i11.07 per Boe and $i10.98
per Boe for the nine months ended September 30, 2022 and 2021, respectively.
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. At September 30, 2022 and September 30, 2021, the SEC oil price and SEC gas price used in the calculation of the ceiling test, adjusted by area for energy content, transportation fees and regional price differentials, was $91.71 and $57.69, respectively, per barrel of oil, and $6.07 and $3.00, respectively, per MMBtu of natural gas. There were iiiino///
impairment charges during the three and nine months ended September 30, 2022 or 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
4. iAcquisitions and Divestitures
Midland Acquisition
On August 22, 2022,
Brigham LLC entered into a definitive purchase and sale agreement (the “Purchase Agreement”) with Avant Royalties, LP, Avant Royalties II, LP and Avant Royalties II Sidecar Fund, LP (collectively, the “Sellers”), pursuant to which Brigham LLC agreed to acquire certain mineral and royalty interests from the Sellers (the “Midland Acquisition”) for $i132.5 million in cash, subject to customary closing adjustments. The Midland Acquisition was completed on October 21, 2022
and has an effective date of July 1, 2022. The Company financed the Midland Acquisition through a combination of cash on hand and borrowings under the Company’s revolving credit facility.
DJ Acquisition
On December 15, 2021, the Company completed the acquisition of approximately i8,400
net royalty acres primarily in Weld County, Colorado for $i89.4 million, consisting of i2.2 million
shares of the Company's Class A common stock valued at $i46.3 million and $i43.1 million
of cash, net of $i1.7 million of customary closing adjustments (the "DJ Acquisition"). During the nine months ended September 30, 2022, the Company received customary post-closing adjustments from the seller consisting of $i1.9 million
in cash and i122,069 shares of the Company's Class A common stock valued at $i2.8 million
which has been retained as treasury stock. The post-closing adjustments were recorded as a reduction of evaluated oil and gas properties.
Echo Acquisition
On March 31, 2022, the Company completed the acquisition of approximately i1,800 net royalty acres in the Midland Basin largely operated by Pioneer Natural
Resources and Endeavor Energy Resources for $i34.8 million, consisting of $i14.4 million in cash, net of $i0.6 million
of customary closing adjustments, and i800,000 shares of the Company's Class A common stock valued at $i20.4
million (the "Echo Acquisition"). The cash portion of the purchase price was funded by cash on hand. Subsequent to the closing of the Echo Acquisition, the Company received customary post-closing adjustments from the seller of $i1.3 million in cash.
The Echo Acquisition has been accounted for as an asset acquisition and the allocation of the purchase price was $i16.8 million
to unevaluated properties and $i16.7 million to evaluated properties.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
(Unaudited)
Other Acquisitions
i
During the nine months ended September 30, 2022 and 2021, Brigham Minerals entered into a number of additional other acquisitions of mineral and royalty interests
from various sellers in Texas, Oklahoma, Colorado, New Mexico, and North Dakota, as reflected in the tables below (in thousands).
The
change in the oil and natural gas property balance is comprised of payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative expenses that for the nine months ended September 30, 2022 and 2021 were funded with our retained operating cash flow, proceeds from asset sales and our revolving credit facility (as hereinafter defined).
Divestitures
During the nine months ended September 30, 2022, Brigham Minerals divested certain non-core, mostly undeveloped acreage totaling i13,535
net royalty acres in the Anadarko Basin and received cash proceeds of $i74.4 million, net of customary closing adjustments. These sales were accounted for as adjustments to the full cost pool, with no gains or losses recognized.
Mineral and royalty revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company's oil, natural gas and NGL sales are made under contracts with customers (operators). The performance obligations for the
Company's contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 60 days of the month of delivery, however this can extend approximately six months after initial production from the well as our team works with the operator to put us into pay status. The
Company's contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, Brigham Minerals recognizes revenue from oil and natural gas sales using the allocation exception for variable consideration in ASC 606.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
i
During the three and nine months ended September 30, 2022 and 2021, the disaggregated revenues from sales of oil, natural gas and NGLs are as follows (in thousands):
Brigham Minerals also earns revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease bonus revenue by leasing our mineral interests to exploration and production companies. A lease agreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. The Company recognizes lease bonus revenues when the lease agreement has been executed, payment has been received, and the Company
has no further obligation to refund the payment. At the time Brigham Minerals executes the lease agreement, Brigham Minerals expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that Brigham Minerals has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. Brigham Minerals also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and we have no further obligation to refund the payment. Right-of-way payments are recorded by the Company when the agreement has been executed, payment is determined to be collectable, and the Company has no further obligation to refund the payment.
Allocation
of transaction price to remaining performance obligations
Mineral and royalty revenues
Brigham Minerals’ right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of our royalty income contracts.
Lease bonus and other income
Given that Brigham Minerals does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied,
and payment is received, Brigham Minerals does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.
Prior-period performance obligations
Brigham Minerals records revenue in the month production is delivered to the purchaser. As a non-operator, Brigham Minerals has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, Brigham Minerals is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the accounts receivable line item
in the accompanying condensed consolidated balance sheets. The difference between the Company’s estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the three and nine months ended September 30, 2022, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was approximately i16.4%
and i2.3% of total revenues, respectively.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
6. iFair Value Measurements
We classify financial assets and liabilities that are measured and reported at fair value on a recurring basis using a hierarchy based on the inputs used in measuring fair value. GAAP defines fair value as the price that would be received
to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We classify the inputs used to measure fair value into the following hierarchy:
• Level 1: Inputs based on quoted market prices in active markets for identical assets or liabilities at the measurement date.
• Level 2: Inputs based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable and can be corroborated by observable market data.
• Level 3: Inputs that reflect management’s best estimates and assumptions of what market participants
would use in pricing the asset or liability at the measurement date. The inputs are unobservable in the market and significant to the valuation of the instruments.
Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer would be reported at the beginning of the period in which the change occurs.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
We had no financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2022 and December
31, 2021.
Brigham Minerals had no transfers into or out of Level 1 and no transfers into or out of Level 2 for the nine months ended September 30, 2022 and September 30, 2021.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Certain non-financial assets and liabilities, such as assets and liabilities acquired in a business combination, are measured at fair value on a nonrecurring basis on the acquisition date and are subject to fair value adjustments under certain circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and include
factors such as estimates of economic reserves, future commodity prices and risk-adjusted discount rates, and are classified within Level 3.
Fair Value of Other Financial Instruments
The carrying value of cash, trade and other receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments. The carrying amount of debt outstanding pursuant to our revolving credit facility approximates fair value as interest rates on the revolving credit facility approximate current market rates. We categorized our long-term debt within Level 2 of the fair value hierarchy.
7. iLong-Term
Debt
Revolving Credit Facility
On May 16, 2019, Brigham Resources, LLC ("Brigham Resources"), a wholly-owned subsidiary of Brigham LLC, 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 a substantial portion of Brigham Resources and its domestic subsidiaries’
assets, including a substantial portion of their respective royalty and mineral properties.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
On July 7, 2021, Brigham Resources entered into the Third Amendment to the credit agreement (the "Third Amendment"). The Third Amendment, among other things, evidenced an increase of the borrowing base and elected commitments
under the prior credit agreement from $i135.0 million to $i165.0 million and the addition of leverage
(maximum i3.00x) and liquidity (minimum i10% of total net revolving commitments) conditions to Brigham Resources’ ability to pay dividends or distributions (other than permitted tax distributions) to the owners of its equity
interests.
On December 15, 2021, Brigham Resources entered into the Fourth Amendment to the credit agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, evidenced a further increase of the borrowing base and elected commitments under the prior credit agreement from $i165.0 million to $i230.0 million.
On June 3, 2022, Brigham Resources entered into the Fifth Amendment to the credit agreement (the "Fifth Amendment"). The Fifth Amendment, among other things, (1) evidenced an increase of the borrowing base and elected commitments under the Credit Agreement from $i230.0 million to $i290.0 million,
respectively, (2) effected a transition of the benchmark interest rate from the London interbank offered rate (“LIBOR”) to the secured overnight financing rate (“SOFR”) as administered by the Federal Reserve Bank of New York, by replacing reserve-adjusted LIBOR with term SOFR for one, three or six month interest periods, plus a fixed credit spread adjustment of i0.10% irrespective of elected tenor (subject to a floor of i0.00%),
and (3) grandfathered all outstanding LIBOR borrowings at original LIBOR benchmark pricing through expiry of the applicable interest periods therefor.
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 ione additional redetermination each year. Brigham
Resources can also request ione 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 ended September 30, 2022 was i3.31%. As of September 30, 2022, the borrowing base on our revolving credit facility was $i290.0 million,
with outstanding borrowings of $i73.0 million, resulting in $i217.0 million available for future borrowings. The
Company expects 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 of June 3, 2022 or the adjusted SOFR rate plus an applicable margin for tranches effective post June 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, i1.500%
to i2.500% and (b) in the case of adjusted LIBOR rate loans and adjusted SOFR rate loans, i2.500% to i3.500%.
Brigham Resources may elect an interest period of one, three or isix 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 i0.375%
to i0.500% 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 on May 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Our revolving credit facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making distributions (subject to Consolidated Total Leverage Ratio and liquidity thresholds) and investments. In addition, our revolving credit facility requires us to maintain (a) a current ratio of not less than i1.00
to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than i3.50 to 1.00. As of September 30, 2022, we were in compliance with all covenants in accordance with our revolving credit facility.
8. iLeases
The
Company enters into leasing transactions in which the Company is the lessee. The Company's lease contracts are generally for office buildings, and office equipment. The Company performed evaluations of its contracts and determined it has only operating leases.
In July 2019, the Company entered into a lease agreement for its corporate headquarters located in
Austin, TX (the “Bridgepoint Lease”). The Bridgepoint Lease includes approximately i29,546 square feet and commenced in July 2019, with an expiration on June 30, 2027. The Bridgepoint Lease includes lease and non-lease components that we account for as a single lease component as an accounting policy election. The Bridgepoint Lease requires monthly lease payments that may be subject to annual increases throughout the lease term and also includes renewal options at the election of the
Company to renew or extend the lease for itwo, consecutive, ifive-year lease terms. This optional period has not been included in the lease term in the determination of the operating lease right-of-use-assets
or operating lease liabilities associated with these leases as the Company did not consider it reasonably certain it would exercise the options. Since the Bridgepoint Lease does not contain an implicit rate, the Company used the incremental borrowing rate of i2% as the discount rate to calculate present value of lease payments. Rent expense on operating leases is recognized over the term of the lease on a straight-line basis.
Rent expense for the three months ended September 30, 2022 and 2021 was $ii0.3/
million in each period. Rent expense for the nine months ended September 30, 2022 and 2021 was $ii1.0/
million in each period.
The Company also enters into leasing transactions in which the Company is the lessor, primarily through land easements. The Company performed evaluations on all term-based land easement payments received during the three and nine months ended September 30, 2022 and determined that all such payments were immaterial in the aggregate.
i
The
following table summarizes the Company’s recognition of its operating lease (in thousands):
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
i
The table below presents the maturity of the Company’s liabilities under the Bridgepoint Lease as of September 30, 2022 (in thousands):
Commitment
2022
(remainder of)
$
i327
2023
i1,319
2024
i1,340
2025
i1,360
2026
i1,383
Thereafter
i582
Total lease payments
i6,311
Less
imputed interest
(i269)
Total lease liabilities
$
i6,042
/
9. iEquity
Class
A Common Stock
Brigham Minerals had approximately i54.2 million shares of its Class A common stock outstanding as of September 30, 2022. Holders of Class A common stock are entitled to ione
vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s Board of Directors. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities.
Class B Common Stock
Brigham Minerals had approximately i6.3
million shares of its Class B common stock outstanding as of September 30, 2022. Holders of the Class B common stock are entitled to ione vote per share on all matters to be voted upon by the stockholders. Holders of Class A common stock and Class B common stock generally vote together as a single class on all matters presented to Brigham Minerals’ stockholders for their vote or approval. Holders of Class B common stock do not have any right to receive dividends or distributions upon a liquidation or winding
up of Brigham Minerals.
Treasury Stock
As of September 30, 2022, there were i0.6 million shares of Class A common stock held in treasury.
Earnings per Share
Basic earnings per share (“EPS”) measures
the performance of an entity over the reporting period. Diluted earnings per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. Brigham Minerals uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding shares of Class B common stock (and corresponding units of Brigham LLC ("Brigham LLC Units")), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding RSAs, RSUs, PSUs (each as defined in "Note 11—Share-Based Compensation") and unvested Incentive Units. Brigham Minerals does not use the two-class method because the Class B common stock and the unvested share-based awards are nonparticipating securities.
For the three and nine months ended September
30, 2022 and 2021, the Incentive Units and shares of Class B common stock were not recognized in dilutive EPS calculations as the effects would have been antidilutive. Additionally, for the nine months ended September 30, 2021 the RSAs were not recognized in dilutive EPS calculations as the effects would have been antidilutive.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
i
The
following table reflects the allocation of net income to common stockholders and EPS computations for the period indicated based on a weighted average number of common stock outstanding for the period (in thousands, except per share data):
Basic
net income attributable to Brigham Minerals, Inc. stockholders
$
i38,459
$
i14,213
$
i111,690
$
i33,997
Denominator:
Basic
weighted average shares outstanding
i53,943
i45,198
i51,663
i44,216
Basic
EPS attributable to Brigham Minerals, Inc. stockholders
$
i0.71
$
i0.31
$
i2.16
$
i0.77
Diluted
EPS
Numerator:
Basic net income attributable to Brigham Minerals, Inc. stockholders
$
i38,459
$
i14,213
$
i111,690
$
i33,997
Diluted
net income attributable to Brigham Minerals, Inc. stockholders
$
i38,459
$
i14,213
$
i111,690
$
i33,997
Denominator:
Basic
weighted average shares outstanding
i53,943
i45,198
i51,663
i44,216
Effects
of dilutive securities:
Unvested equity awards
i1,999
i690
i1,800
i840
Diluted
weighted average shares outstanding
i55,942
i45,888
i53,463
i45,056
Diluted
EPS attributable to Brigham Minerals, Inc. stockholders
$
i0.69
$
i0.31
$
i2.09
$
i0.75
/
10. iNon-controlling
interest
Non-controlling interest represents the i10.4% interest in the units of Brigham LLC not owned by Brigham Minerals, as of September 30, 2022. Each share of Class B common stock does not have any economic rights but entitles its holder to ione
vote on all matters to be voted on by our stockholders generally, and holders of Brigham LLC Units (and Class B common stock) have a redemption right into shares of Class A common stock. Under the Brigham LLC Agreement, each Brigham LLC Unit Holder, subject to certain limitations, has a right (the "Redemption Right") to cause Brigham LLC to acquire all or a portion of its Brigham LLC Units for, at Brigham LLC’s election, (i) shares of our Class A common stock at a redemption ratio of ione
share of Class A common stock for each Brigham LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. We will determine whether to issue shares of Class A common stock or cash based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Brigham LLC Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Brigham Minerals (instead of Brigham LLC) will have a call right to, for administrative convenience, acquire each tendered Brigham LLC Unit directly from the redeeming Brigham LLC Unit Holder for, at its election, (x) ione
share of Class A common stock or (y) an equivalent amount of cash (the "Call Right"). The decision to make a cash payment upon a Brigham LLC Unit Holder's exercise of its Redemption Right is required to be made by the Company's directors who are independent under Section 10A-3 of the Securities Act of 1933, as amended, and do not hold any Brigham LLC Units subject to such redemption. In connection with any redemption of Brigham LLC Units pursuant to the Redemption Right or acquisition pursuant to our Call Right, the corresponding number of shares of Class B common stock will be cancelled.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Non-controlling interest is recorded at its carrying value. iFor the period from December 31, 2021 to September 30, 2022,
the Company recorded adjustments to the value of non-controlling interest as presented in the table below (in thousands):
As part of the Second Amended and Restated Limited Liability Company Agreement of Brigham Resources, LLC dated May 8, 2015, Brigham Resources authorized i120,000 restricted incentive units for issuance to management, independent
directors, employees, and consultants (such incentive units, as converted as described below, the “Incentive Units”). Brigham Resources granted Incentive Units in April 2013 and September 2015 and 2018. In connection with the 2018 corporate reorganizations and the corporate reorganization consummated in connection with Brigham Minerals’ IPO (collectively with the 2018 corporate reorganizations, the “corporate reorganization”), these Incentive Units were converted into units in Brigham Equity Holdings, LLC (“Brigham Equity Holdings”) with equivalent rights, responsibilities, and preferences. The Incentive Units were subject to vesting as follows: i20%
of the Incentive Units were vested on the date of grant and iiii20///%
of the Incentive Units vest on each anniversary of the date of grant if the holder remains continuously employed by Brigham Resources or its affiliates through the applicable vesting date. Upon vesting of the Incentive Units, holders of the Incentive Units received ione share of Brigham Minerals’ Class B common stock and ione
Brigham LLC Unit for each vested Incentive Unit.
In connection with the completion of the IPO, Brigham LLC and Brigham Equity Holdings discontinued granting new Incentive Units. As discussed in "Note 10—Non-controlling interest," participants may receive ione share of Brigham Minerals’ Class A common stock in exchange
for ione share of Class B common stock and ione
Brigham LLC Unit, or cash at the option of Brigham Minerals. Brigham Minerals accounts for the Incentive Units as compensation expense measured at the fair value of the award on the date of grant. No compensation expense was recognized prior to the IPO because the IPO was not considered probable.
i
A summary of the Incentive Unit activity for the nine months ended September 30, 2022 is
as follows:
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Long Term Incentive Plan
In connection with the IPO, Brigham Minerals adopted the Brigham Minerals, Inc. 2019 Long Term Incentive Plan (“LTIP”) for employees, consultants and directors who perform services for Brigham Minerals. The LTIP provides for issuance of awards based on shares of Class A common stock. Brigham Minerals has issued restricted stock awards ("RSAs"), restricted stock units subject to time-based vesting ("RSUs") and restricted stock units subject to performance-based vesting ("PSUs") under the LTIP. The shares to be delivered
under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by Brigham Minerals including shares purchased on the open market. A total of i5,999,600 shares of Class A common stock have been authorized for issuance under the LTIP. At September 30, 2022, i4,437,697 shares
of Class A common stock remained available for future issuances upon vesting of equity awards. Currently, all RSUs and PSUs granted under the LTIP are entitled to receive dividend equivalent rights (“DERs”), which entitle holders of RSUs and PSUs to the same dividend value per share as holders of the Company's Class A common stock. Such DERs are subject to the same vesting and other terms and conditions as the corresponding unvested RSUs and PSUs. DERs are accumulated and paid when the underlying shares vest. The fair value of the RSU awards granted with the right to receive DERs are generally based on the trading price of the Company’s Class A common stock as of the date of grant. Brigham Minerals accounts for the awards granted under the LTIP as compensation cost measured at the fair value
of the award on the date of grant. Brigham Minerals accounts for forfeitures as they occur.
The Company has granted RSAs to certain employees, which are grants of shares of Class A common stock subject to a risk of forfeiture and restrictions on transferability. The share-based compensation expense of such RSAs was determined using the closing price of Class A common stock on April 23, 2019, the date of grant, of $i21.25.
On April 23, 2019, i312,189 RSAs were granted and i152,742
RSAs held by former employees of the Company vested immediately. The RSAs generally vested in one-third increments on each of April 23, 2020, 2021 and 2022.
The following table summarizes activity related to RSAs for the nine months ended September 30, 2022.
The
Company has granted RSUs to certain employees and directors, which represent the right to receive shares of Class A common stock at the end of the vesting period in an amount equal to the number of RSUs that vest. The RSUs issued to employees generally vest in one-third increments over a ithree-year period and RSUs issued to directors vest in ione
year from the date of grant. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient ceases providing services to Brigham Minerals prior to the date the award vests. The share-based compensation cost of such RSUs was determined using the closing price on the applicable date of grant, which is then applied to the total number of RSUs granted.
The following table summarizes activity related to RSUs for the nine months ended September 30, 2022.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The Company has granted PSUs to certain officers and managers, which vest based on continuous employment and satisfaction of a market condition based on the absolute total stockholder return of the
Company’s common stock, including paid dividends, over an approximate ithree-year performance period. The terms and conditions of the PSUs allow for vesting of the awards ranging between i0%
(or forfeiture) and i200% of target. In addition, the number of PSUs earned may be adjusted based on our relative TSR as compared to a benchmarking peer group over the ithree-year
performance period. Expense related to these PSUs is recognized on a straight-line basis over the length of the applicable performance period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The grant date fair value of such PSUs was determined using a Monte Carlo simulation model that utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award to calculate the fair value of the award. Expected volatilities in the model were estimated on the basis of historical volatility of a group of publicly traded oil and gas companies with a performance period of approximately ithree
years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant.
The following table summarizes activity related to PSUs for the nine months ended September 30, 2022:
During 2022, the Company implemented a short term incentive plan (the “STIP”) for executives and certain other employees who perform services for the Company. The STIP is based on quantitative and qualitative metrics that are key drivers of shareholder value.
Each STIP participant was assigned a target award opportunity expressed as a percentage of base salary and the awards allow for attainment ranging between i0%
and i150% of target. Award attainment is based on the achievement of various financial, operational and other strategic metrics.
If earned, the STIP awards will be paid in cash at the completion of the plan year for all employees other than the CEO. The CEO's STIP awards will be paid out in the form of shares of our Class A common stock, rather than cash, with such award subject to a ione-year
vesting period. As the STIP awards to be settled in shares of our Class A common stock will consist of a variable number of shares based on the award attainment at the completion of the plan year and the fair market value of our Class A common stock, we will initially account for these awards as liabilities with performance conditions. Once the number of shares to be issued has been fixed, the awards will be reclassified to equity.
Expense for awards with performance conditions is only recognized when achievement of the performance target is deemed probable. The expense to be recognized is based on the Company’s best estimate of probable attainment at the end of each reporting period prorated for the portion of the requisite service period rendered.
The
target attainment for the STIP awards for the year ended December 31, 2022 is $i2.4 million, of which $i0.5 million
is expected to be settled in shares of the Company's Class A common stock. During the three and nine months ended September 30, 2022, the Company accrued $i0.5 million and $i1.6
million, respectively, related to the STIP awards.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Share-Based Compensation Expense
Share-based compensation expense is included in general and administrative expense in the Company's condensed consolidated statements of operations included
within this Quarterly Report. iShare-based compensation expense recorded for each type of share-based compensation award for the three and nine months ended September 30, 2022 and 2021 is summarized in the table below (in thousands).
(1)Share-based
compensation expense relating to Incentive Units, RSAs and RSUs with ratable vesting is recognized on a straight-line basis over the requisite service period for the entire award.
(2)Share-based compensation expense relating to PSUs with cliff-vesting is recognized on a straight-line basis over the performance period for the entire award.
(3)Share-based compensation expense relating to STIP awards to be settled in shares of our Class A common stock is recognized on a straight-line basis over the requisite service period for the entire award.
(4)During the three and nine months ended September 30, 2022, Brigham Minerals capitalized $i0.9 million
and $i1.8 million, respectively, of share-based compensation cost to unevaluated property, $i0.6
million and $i2.6 million, respectively, of share-based compensation cost to evaluated property and $ii0.1/ million
of share-based compensation cost to internally developed software in each period. During the three and nine months ended September 30, 2021, Brigham Minerals capitalized $i1.5 million and $i3.0 million,
respectively, of share-based compensation cost to unevaluated property and $i0.5 million and $i2.5 million,
respectively, of share-based compensation cost to evaluated property.
Future Share-Based Compensation Expense
The following table reflects the future share-based compensation expense expected to be recorded for the share-based compensation awards that were outstanding at September 30, 2022, a portion of which will be capitalized (in thousands):
RSUs
PSUs
STIP
Awards
Total
2022
$
i2,149
$
i1,188
$
i67
$
i3,404
2023
i5,627
i3,877
i268
i9,772
2024
i2,749
i1,179
i57
i3,985
2025
i593
i254
i—
i847
Total
$
i11,118
$
i6,498
$
i392
$
i18,008
12. iIncome
Taxes
The Company evaluates and updates its annual effective income tax rate on a quarterly basis under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income, except for discrete items. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make comparisons not meaningful. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs.
Total
income tax expense for the three and nine months ended September 30, 2022 and 2021 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due to the impact of excess tax benefits resulting from vesting of equity awards, non-controlling interest, state taxes (net of the anticipated federal benefit), share-based compensation expense, and percentage depletion in excess of basis. The effective tax rate for the three and nine months ended September 30, 2022 and 2021 reflects Brigham Minerals' ownership interest in Brigham LLC of i89.6%
and ii79.7/%,
respectively, at the end of each period.
13. iContingencies
Brigham Minerals may, from time to time, be a party to certain lawsuits and claims arising in the ordinary course of business. The outcome of such lawsuits and claims cannot be estimated with certainty and management may not be able
to estimate the range of possible losses. Brigham Minerals records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Brigham Minerals had no reserves for contingencies at September 30, 2022 and December 31, 2021.
14. iSubsequent Events
On
October 21, 2022, Brigham LLC completed the Midland Acquisition. Upon closing of the Midland Acquisition, pursuant to the terms of the Purchase Agreement, Brigham LLC delivered to the Sellers cash consideration of approximately $i130.7 million, less and except $i6.6 million
of cash consideration that was previously deposited in an escrow account for the benefit of the Sellers as a deposit in connection with the signing of the Purchase Agreement.
On November 2, 2022, the Board of Directors of Brigham Minerals declared a dividend of $i0.81 per share of Class A common stock payable on November 25, 2022, to stockholders of record at the close of business on November 18,
2022.
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Brigham Minerals, Inc. (the "Company,""we,""us," or "our") is the managing member of Brigham Minerals Holdings, LLC (“Brigham LLC”) and is responsible for all operational, management and administrative decisions related to Brigham LLC and its operating subsidiaries’
business. The following discussion and analysis should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 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 between Russia and Ukraine, 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.
Overview
Brigham
Minerals was formed to acquire and actively manage a portfolio of mineral and royalty interests in the core of what we view as the most active, highly economic, liquids-rich resource plays across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our stockholders through (i) the growth of our free cash flow generated from our existing mineral portfolio and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. As of September 30, 2022, we owned 82,175 net royalty acres across 38 counties within the Delaware and Midland Basins in West Texas and New Mexico, the Anadarko Basin in Oklahoma, the Denver-Julesburg ("DJ") Basin in Colorado and Wyoming and the Williston Basin in North Dakota.
Merger Announcement
On
September 6, 2022, the Company and Brigham LLC, entered into an Agreement and Plan of Merger (as amended from time to time, the “merger agreement”) with Sitio Royalties Corp., a Delaware 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”) and Snapper 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 of Opco Merger Sub LLC with and into Brigham LLC (the “Opco Merger,” and, together with the Brigham Merger and the Sitio Merger, the “Mergers”), with Brigham LLC surviving the Opco Merger as a wholly owned subsidiary of Opco 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 Class C 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
(the “Sitio Class C Common Stock”), issued and outstanding immediately prior to the First Effective Time, will be converted into one share of New Sitio Class C 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 in Opco 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 before June 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 ended September
30, 2022 increased 15% compared to the three months ended June 30, 2022. Our production volume of 13,361 Boe/d (72% liquids, 51% oil) for the nine months ended September 30, 2022 increased 49% compared to the nine months ended September 30, 2021.
•Our mineral and royalty revenues composed of crude oil, natural gas and NGL sales of $92.8 million for the three months ended September 30, 2022 increased 3% compared to the three months ended June 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 ended September
30, 2022 increased 131% compared to the nine months ended September 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 ended September 30, 2022, inclusive of $7.8 million of merger-related costs. Adjusted Net Income for the three months ended September 30, 2022 was $52.2 million, up 4% from the three months ended June 30, 2022. Our net income was $133.7 million for the nine months ended September 30, 2022, inclusive of $7.8 million of merger-related costs. Adjusted Net Income for the nine months ended September
30, 2022 was $141.5 million, up 205% from the nine months ended September 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 ended September 30, 2022 and increased 3% and 2%, respectively, as compared to the three months ended June 30, 2022. Adjusted EBITDA and Adjusted EBITDA ex lease bonus were $222.5 million and $219.1 million, respectively, for the nine months ended September
30, 2022 and increased 140% and 147%, respectively, as compared to the nine months ended September 30, 2021. Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP financial measures. For a definition of Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation to our most directly comparable measure calculated and presented in accordance with GAAP, please read "How We Evaluate our Operations—Non-GAAP Financial Measures."
•On November 2, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.81 per share of Class A common stock payable on November 25, 2022 to stockholders of record at the close of business on November 18, 2022.
•As
of September 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.
On August 22, 2022, Brigham LLC entered into a definitive purchase and sale agreement (the “Purchase Agreement”) with Avant
Royalties, LP, Avant Royalties II, LP and Avant Royalties II Sidecar Fund, LP (collectively, the “Sellers”), pursuant to which Brigham 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 on October 21, 2022 and has an effective date of July 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 Russia/Ukraine Conflict
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 in the 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,
in February 2022, Russia invaded Ukraine 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 between Russia and Ukraine 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.
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 the Permian Basin. As of September 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 the Delaware and Midland Basins in West Texas and New Mexico, the Anadarko Basin in Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota.
The table below summarizes the Company’s mineral and royalty interest ownership at the dates indicated.
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:
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:
DUC and Permit Inventory
Brigham Minerals ended the third quarter
2022 with 6.7 net DUCs and 4.1 net permits versus 6.8 net DUCs and 4.2 net permits as of second quarter 2022. Brigham Minerals' gross and net DUC and permit inventory as of September 30, 2022 by basin is outlined in the table below:
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.
On July 9, 2020, the U.S. Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the Court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation,
the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations in Oklahoma that may similarly be found to not have been disestablished. State district courts in Oklahoma, applying the analysis in U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation, have ruled that the Cherokee, Chickasaw, Seminole, Quapaw and Choctaw 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 in Oklahoma, such as taxation, environmental regulation, and the permitting and siting of
energy assets.
On October 1, 2020, the Environmental Protection Agency (the "EPA") granted approval to the State 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 existing EPA-approved regulatory programs to many areas of Indian Country within Oklahoma, effectively extending Oklahoma’s authority for existing EPA-approved regulatory programs to lands within Oklahoma previously under the jurisdiction of the State before the U.S. Supreme Court’s ruling in McGirt. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and, in December 2021, the EPA proposed to withdraw and reconsider the October 2020 decision. The EPA also sought public comment
on the proposed withdrawal and reconsideration with a deadline of January 31, 2022. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from the EPA.
Separately, in 2021, the U.S. Department of the Interior subsequently used the ruling in McGirt to find that Oklahoma could not keep jurisdiction over surface coal mining on the Muscogee (Creek) Nation’s lands. The State of Oklahoma petitioned the U.S. Supreme Court to overturn this determination and find that McGirt either is limited to federal criminal matters or was incorrectly decided. In June 2022, the Supreme 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 the Oklahoma Supreme Court regarding the Oklahoma 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 the Supreme Court's decision. We will continue to monitor developments concerning these matters.
Dakota Access Pipeline (“DAPL”)
On July 6, 2020, the U.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 by August
5, 2020 while the Corps completes a full environmental impact statement for the project. On January 26, 2021, the Court 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. On May 21, 2021, the District Court denied the Plaintiff’s request for an injunction and, on June 22, 2021, terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. Following the denial of a rehearing en banc, on September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. On February
22, 2022, the U.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 the Standing Rock Sioux Tribe to understand concerns expressed in their January 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 the Williston Basin, and the operators of our properties in the Williston 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 the Williston
Basin.
In November 2020, the Colorado 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, effective January 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
On
March 21, 2022, the U.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 the SEC'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
In August 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.
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 $123.64 per barrel in March 2022. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. As of September
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 between Russia and Ukraine, the effects of health pandemics such as COVID-19, production levels, availability of transportation and storage, weather cycles and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining
markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to
the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
Quality
differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.
NGLs. NGL pricing is generally tied to the
price of oil, but varies based on differences in liquid components and location.
Oil and gas properties
Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax effects (the "ceiling test"). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods.
A ceiling test is calculated at each reporting period. The ceiling test calculation is prepared using an unweighted arithmetic average of oil prices ("SEC oil price") and natural gas prices ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, adjusted by area for energy content, transportation fees and regional price differentials, as required under the guidelines established by the SEC. As of 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 of September 30, 2022 and December 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.
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):
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
$
50,180
$
141,457
$
46,308
Add:
Depreciation,
depletion, and amortization
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
$
79,685
$
222,478
$
92,745
Less:
Lease
bonus and other revenues
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:
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 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 to U.S. federal and state income taxes as a corporation. Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of up to 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A portion of our mineral and royalty interests are located in Texas basins.
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):
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.
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 ended September 30, 2022 was primarily attributable to increases in leasing activity in the Permian 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.
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).
Interest
expense, net. Interest expense, net decreased $0.1 million for the three months ended September 30, 2022 compared to the three months ended June 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).
During the three months ended September 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.
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):
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 ended September 30, 2022 include costs related to the Mergers of $7.8 million, or $2.13 per Boe.
Total revenues for the nine months ended September 30, 2022 increased 126%, or $143.0 million, compared to the nine months ended September 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 ended September 30, 2022 increased 136%, or $106.2 million, compared to the nine months ended September 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 ended September 30, 2022 increased 107%, or $20.9 million, compared to the nine months ended September 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 ended September 30, 2022 increased 135%, or $16.4 million, compared to the nine months ended September 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 ended September 30, 2022 was primarily attributable to decreases in leasing activity in the Anadarko 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.
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).
Interest
expense, net. Interest expense, net increased $2.0 million for the nine months ended September 30, 2022 compared to the nine months ended September 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).
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 Brigham LLC from September 30, 2021 to September 30, 2022 impacts the attribution of net income between Brigham Minerals' stockholders and Brigham LLC Unit Holders.
As of September 30, 2021, Brigham Minerals owned a 79.7% interest in Brigham LLC and the Brigham LLC Unit Holders owned 20.3% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Brigham LLC Unit Holders, collectively owned 14.5% of the outstanding voting stock of Brigham Minerals as of September
30, 2021.
As of December 31, 2021, Brigham Minerals owned an 81.0% interest in Brigham LLC and the Brigham LLC Unit Holders owned 19.0% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Brigham LLC Unit Holders, owned 4.8% and 8.7%, respectively, of the outstanding voting stock of Brigham Minerals as of December 31, 2021. Yorktown ceased to be an affiliate of the
Company on January 20, 2022 in connection with the resignation of W. Howard Keenan, Jr. from the Board of Directors.
As of September 30, 2022, Brigham Minerals owned an 89.6% interest in Brigham LLC and the Brigham LLC Unit Holders owned 10.4% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Pine Brook Road Advisors, LP, which are a subset of the Brigham LLC Unit Holders, owned 3.6% of the outstanding voting stock of Brigham Minerals as of September 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 ended September 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 of Brigham 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 ended December 31, 2022, we believe that our retained cash flow from operations, lease bonus, portfolio optimization activities and additional borrowings under our revolving credit facility will provide us with sufficient liquidity
to execute our current strategy. However, our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through additional borrowings, joint venture partnerships, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us.
Our working capital, which we define as current assets minus current liabilities, totaled $83.0 million at September 30, 2022, as compared to $33.1 million at December 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 at September 30, 2022 and December 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 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 nine months ended September 30, 2022:
(1) Dividends paid to holders of Class A common stock.
On November 2, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.81 per share of Class A common stock payable on November 25, 2022, to stockholders of record at the close of business on November 18, 2022. See "Note 14—Subsequent Events" to the condensed consolidated financial statements
of Brigham 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):
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 ended September 30, 2022 as compared to the nine months ended September 30, 2021 was primarily due to the 55% increase in realized commodity prices during the nine months ended September 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 ended September 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 ended September 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 ended September 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 ended September 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
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 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 ended September 30, 2022 was 3.31%. As of September 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 of June 3, 2022 or the adjusted SOFR rate plus an applicable margin for tranches effective post June 3, 2022. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans and adjusted SOFR rate loans, 2.500% to 3.500%. Brigham Resources may elect an interest period of one, three or six months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging
from
0.375% to 0.500% based on utilization of our borrowing base. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions.
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 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 September 30, 2022, we did not have any material off-balance sheet arrangements.
Critical Accounting Policies and Related Estimates
As of September 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."
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 in the 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 in April 2020 to a high of $123.64 per barrel in March 2022, and as of September 30, 2022, the posted price for oil was $79.91 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 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 in September 2020 to a high of $23.86 per MMBtu in February 2021, and as of September 30, 2022, the Henry Hub spot market price of natural gas was $6.40 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 $1.9 million change in our oil revenues for the nine months ended September 30, 2022. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.6 million
change in our natural gas revenues for the nine months ended September 30, 2022. A $1.00 per barrel change in NGL prices would have resulted in a $0.8 million change in our NGL revenues for the nine months ended September 30, 2022. Total revenues for the nine months ended September 30, 2022 was comprised of 72% from oil sales, 16% 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.
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, we 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. For further discussion, please
refer to "Risk Factors" in our Annual Report.
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 for tranches outstanding as of June 3, 2022 or the adjusted SOFR rate plus an applicable margin for tranches effective post June 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%. We may elect an interest period of one, three or six months. Interest is payable in
arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our 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 nine months ended September 30, 2022 was 3.31%. As of September 30, 2022, the 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. A 1-percentage-point increase in our interest rate would have increased our interest expense by $0.7 million for the nine months ended September
30, 2022.
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 of September 30, 2022.
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 the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and 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 at September 30, 2022.
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 third quarter of 2022 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
Item 1A. — Risk Factors
Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our Class A common stock are described under the caption “Risk Factors”
in our Annual Report. Except for the additional risk factors and updates set forth below, there have been no material changes in our risk factors from those previously disclosed under “Risk Factors” in our Annual Report.
Risks Relating to the Pending Mergers with Sitio
Because the exchange ratio is fixed and will not be adjusted in the event of any change in either our stock price or Sitio’s stock price, our stockholders cannot be certain of the precise value of any merger consideration they may receive in the Mergers.
Upon completion of the Mergers, (i) each issued and outstanding share of Brigham Class A Common Stock will be converted into the right to receive 1.133 fully-paid and nonassessable shares of New
Sitio Class A Common Stock, (ii) each issued and outstanding share of Brigham Class B Common Stock will be converted into the right to receive 1.133 fully-paid and nonassessable shares of New Sitio Class C Common Stock, (iii) each issued and outstanding share of Sitio Class A Common Stock will be converted into one share of New Sitio Class A Common Stock and (iv) each issued and outstanding share of Sitio Class C Common Stock will be converted into one share of New Sitio Class C 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 DGCL. Additionally, upon completion of the Opco Merger, each issued and outstanding Brigham LLC Unit will be converted into the right to receive 1.133
Opco LP Units. These exchange ratios are fixed and will not be adjusted for changes in the market value of Brigham Class A Common Stock or Sitio Class A Common Stock. No fractional shares of New Sitio Common Stock or Opco LP Units will be issued in connection with the Mergers. Instead, a Brigham stockholder who otherwise would have received a fractional share of New Sitio Common Stock will be entitled to receive a cash payment in lieu of such fractional shares in accordance with the terms of the merger agreement.
The market prices of Brigham Class A Common Stock and Sitio Class A Common Stock have fluctuated since the date of the announcement of the merger agreement and may continue to fluctuate until the Mergers are consummated. The market price of New Sitio Common Stock may continue to fluctuate thereafter.
Because
the value of the merger consideration received by our stockholders will depend on the market price of Sitio Class A Common Stock at the time the Mergers are completed, our stockholders will not know or be able to determine the precise value of any merger consideration they may receive upon completion of the Mergers.
Stock price changes may result from a variety of factors, including, among others:
•general market and economic conditions;
•changes in our and Sitio’s respective businesses, operations and prospects;
•market assessments of the likelihood that the Mergers will be completed;
•interest
rates, general market, industry, economic and geopolitical conditions, including the impact of continued inflation and associated changes in monetary policy, and other factors generally affecting the respective prices of Brigham Class A Common Stock and Sitio Class A Common Stock;
•federal, state and local legislation, governmental regulation and legal developments in our and Sitio’s businesses; and
•the timing of the Mergers and regulatory considerations.
Many of these factors are beyond our and Sitio’s control, and neither we or Sitio are permitted to terminate the merger agreement solely due to a decline in the market price of the other party. You are urged to obtain current market quotations for Brigham Class A Common Stock and Sitio Class A Common
Stock.
The merger agreement may be terminated in accordance with its terms and the Mergers may not be consummated.
The Mergers are subject to a number of conditions that must be satisfied or waived prior to the completion of the Mergers, including, (i) the receipt of the required approvals from our and Sitio’s respective stockholders; (ii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iii) the absence of any governmental order or law that makes
consummation of the Mergers illegal or otherwise prohibited; (iv) New Sitio’s registration statement on Form S-4 having been declared effective by the SEC under the Securities Act of 1933, as amended; and (v) the shares of New Sitio Class A Common Stock issuable in connection with the Mergers having been authorized for listing on the New York Stock Exchange, subject to official notice of issuance. The obligation of each party to consummate the Mergers is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the merger agreement. The obligation of each party to consummate the Mergers is further conditioned upon the receipt of customary tax opinions from counsel to the effect that, on the basis of the facts, representations and assumptions set forth or referred to in such opinion, either (i) each Pubco Merger
should qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, (the “Code”) with respect to each of the parties to the reorganization or (ii) the transfer of the stock of Sitio and the stock of Brigham to New Sitio in exchange for stock of New Sitio as a result of the Pubco Mergers should constitute a transaction described in Section 351 of the Code.
Moreover, if the Mergers are not completed by June 6, 2023, either we or Sitio may choose not to proceed with the Mergers, and the parties can mutually decide to terminate the merger agreement at any time. In addition, we and Sitio may elect to terminate the merger agreement in certain other circumstances as further detailed in the merger agreement.
Failure
to complete the Mergers or the termination of the merger agreement could negatively impact the price of our Class A Common Stock, as well as our future business and financial results.
The merger agreement contains a number of conditions that must be satisfied or waived prior to the completion of the Mergers. There can be no assurance that all of the conditions to the completion of the Mergers will be so satisfied or waived. If these conditions are not satisfied or waived, we will be unable to complete the Mergers.
If the Mergers are not completed for any reason, including the failure to receive the required approval of our stockholders, our future business and financial results may be adversely affected, including as follows:
•we
may experience negative reactions from the financial markets, including negative impacts on the market price of our Class A Common Stock;
•we may experience negative reactions from our business partners, regulators and employees;
•we will still be required to pay certain legal, financing and accounting costs and associated fees and expenses relating to the Mergers, whether or not the Mergers are completed; and
•our management will have expended time and resources that could otherwise have been devoted to our day-to-day operations and the pursuit of other opportunities that could have been beneficial to us as an independent company.
In addition to the above risks, if the merger agreement
is terminated and our Board of Directors seeks an alternative transaction, our stockholders cannot be certain that we will be able to find a party willing to engage in a transaction on more attractive terms than the Mergers. If the merger agreement is terminated under certain circumstances, we may be required to pay Sitio a termination fee.
The merger agreement contains provisions that limit our ability to pursue alternatives to the Mergers.
The merger agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the Mergers, or may result in a potential competing acquirer proposing to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include covenants
not to solicit, initiate or knowingly encourage or facilitate proposals relating to alternative transactions or, subject to certain exceptions, enter into discussions concerning or provide any non-public information in connection with alternative transactions.
We will be subject to business uncertainties while the Mergers are pending, which could adversely affect our business.
Uncertainties about the effect of the Mergers on our employees and third parties that do business with us may adversely affect our business. These uncertainties
may impair our ability to attract, retain and motivate key personnel until the Mergers are completed and for a period of time thereafter and could cause operators and other third parties that deal with us to delay or defer entering into contracts with us or seek to change or cancel existing business relationships with us, which could negatively affect our business. Employee retention may be particularly challenging during the pendency of the Mergers, as employees may experience uncertainty about their roles with New Sitio following the Mergers. In addition, the merger agreement restricts us from entering into certain corporate transactions and taking other specified actions without the consent of Sitio, and generally requires us to continue our operations in the ordinary course of business, until completion of the Mergers. These restrictions may prevent us from pursuing attractive
business opportunities that may arise prior to the completion of the Mergers and could have the effect of delaying or preventing other strategic transactions. Adverse effects arising from the pendency of the Mergers could be exacerbated by any delays in the consummation of the Mergers or termination of the merger agreement.
We will incur significant transaction and merger-related costs in connection with the Mergers, which may be in excess of those anticipated by us.
We have incurred and expect to continue to incur a number of non-recurring costs associated with the Mergers. These costs and expenses include fees paid to financial, legal and accounting advisors, potential employment-related costs, filing fees, printing expenses and other related charges. Many of these costs are payable by us regardless
of whether the Mergers are completed. There are also a large number of processes, policies, procedures, operations, technologies and systems that may or must be integrated in connection with the Mergers and the integration of our and Sitio’s businesses. While we have assumed that a certain level of expenses would be incurred in connection with the Mergers and the other transactions contemplated by the merger agreement, there are many factors beyond our control that could affect the total amount or the timing of the integration and implementation expenses.
The shares of New Sitio Common Stock to be received by our stockholders upon completion of the Mergers will have rights different from our Common Stock.
Upon consummation of the Mergers, our stockholders will no longer be stockholders of the
Company. Instead, our former stockholders will become stockholders of New Sitio and while their rights as New Sitio stockholders will continue to be governed by the laws of the State of Delaware, their rights will be subject to and governed by the terms of the Amended and Restated Certificate of Incorporation and the Amended and Restated Bylaws of New Sitio, the terms of which are different in some respects than the terms of our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws, which currently govern the rights of our stockholders.
We
may be the target of securities class action and derivative lawsuits, which could result in substantial costs and may prevent or delay the consummation of the Mergers or result in the payment of damages following completion of the Mergers.
Securities class action lawsuits or derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against such claims can result in substantial costs and divert management time and resources. An adverse ruling in any such lawsuit could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Mergers, then that injunction may delay or prevent the Mergers from being completed, which could adversely affect our business,
financial condition, results of operations and cash flows.
Completion of the Mergers may trigger change in control or other provisions in certain agreements to which we or our subsidiaries are a party.
The completion of the Mergers may trigger change in control or other provisions in certain agreements to which we or our subsidiaries are a party. If we or our subsidiaries are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the
agreements, or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to us.
The completion of the Mergers will constitute a change of control under our revolving credit facility. As a result, at the direction of the lenders holding a majority of the outstanding loans under our revolving credit facility, the commitments under our
revolving credit facility may be terminated and the outstanding balance under our revolving credit facility may be accelerated
and become due and payable by us in connection with the completion of the Mergers. As of September 30, 2022, we had approximately $73.0 million of outstanding borrowings under our revolving credit facility.
Risks Related to Our Business
Continuing or worsening inflationary issues and associated changes in monetary policy may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise and may delay or restrict their exploration and development activities.
The rate of inflation in the U.S. has been steadily increasing since 2021 and in to 2022. These inflationary pressures
may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—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.
The following financial information from this Quarterly Report on Form 10-Q of Brigham Minerals, Inc. for the quarter ended September 30, 2022 is formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.
104
Cover
Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
________________
* The exhibits marked with the asterisk symbol (*) are filed or furnished with this Quarterly Report on Form 10-Q.
** Certain schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant will furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon request.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
