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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
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. iYesx No o
Indicate by check mark if the registrant is
not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes oiNox
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ix
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
As of June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates
of the registrant was approximately $i987.3 million, determined using the per share closing price on the New York Stock Exchange on that date of $21.29. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10% or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This
determination of affiliate status is not necessarily a conclusive determination for other purposes.
The registrant had i48,360,253 shares of Class A common stock and i11,371,517
shares of Class B common stock outstanding as of February 18, 2022.
iPortions of the registrant’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K.
The
following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K ("Annual Report"), 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.
4
Term
Definition
Proved
reserves
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 Annual Report includes “forward-looking statements.” All statements, other than statements of historical fact, included in this Annual Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. In particular, our statements regarding the ongoing COVID-19 pandemic and its expected impact on our business, financial position, results of operations and cash flows are forward-looking statements. When used in this Annual 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 “Item 1A—Risk Factors” included in this 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 Annual 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 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;
•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;
•global or national health events, including the ongoing COVID-19 pandemic and its resulting economic effects;
•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;
•the cost of inflation;
6
•technological
advances;
•weather conditions, natural disasters and other matters beyond our control;
•
•general economic, business, political or industry conditions; and
•certain factors discussed elsewhere in this Annual Report.
Should one or more of the risks or uncertainties described in this Annual Report 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 Annual 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 Annual 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 Annual
Report.
7
PART I
Item 1. Business
Unless the context otherwise requires, references in this annual report on Form 10-K (the “Annual Report”) to “Brigham Minerals,” the “Company,”“we,”“our,”“us” or like terms refer to Brigham Minerals, Inc. and its subsidiaries.
References to the “Brigham LLC” refer to Brigham Minerals Holdings, LLC. Brigham Minerals owns an interest in, and acts as the sole managing member of, Brigham LLC. Brigham LLC wholly owns Brigham Resources, LLC (“Brigham Resources”), which wholly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”), which are Brigham Resources’ sole material assets.
On April 17, 2019, the Company completed its initial public offering (the “IPO”) of shares of its Class A common stock, par value $0.01 per share (the “Class A common stock”). Unless indicated otherwise or the context otherwise requires, references in this Annual Report to the
Company (i) for periods prior to completion of the IPO, refer to the assets and operations (including reserves, production and acreage) of Brigham Resources, excluding the historical results and operations of Brigham Resources Operating, LLC (“Brigham Operating”), which was spun out in connection with the IPO, and (ii) for periods after completion of the IPO, refer to the assets and operations of Brigham Minerals and its subsidiaries, including Brigham LLC, Brigham Resources and the Minerals Subsidiaries.
Overview
We formed our company in 2012 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 by both capturing growth in free cash flow from the continued organic development of our existing horizontal well inventory of 850 gross drilled but uncompleted horizontal wells ("DUCs"), 873 gross permits and 12,220 gross undeveloped locations, all of which are unburdened by development capital expenditures or lease operating expenses, as well as leveraging our highly experienced technical evaluation team to continue to execute upon our scalable business model of sourcing, methodically evaluating and integrating accretive minerals acquisitions in the core of top-tier, liquids-rich resource plays.
Our portfolio is comprised of mineral and royalty
interests across six 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 SCOOP and STACK plays in 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 36 of the most highly active counties for horizontal drilling in the continental United States.
Since inception, we have executed on our technically driven, financially disciplined acquisition approach and have closed nearly 1,700 transactions with third-party mineral and royalty interest owners as of December 31, 2021. We have increased our mineral and royalty interests
from approximately 10,200 net royalty acres as of December 31, 2013, to approximately 92,375 net royalty acres as of December 31, 2021, which represents a 32% compound annual growth rate in our mineral and royalty interests over that period. See “—Our Mineral and Royalty Interests” for a discussion of how we calculate net royalty acres.
The following table summarizes certain information regarding our net royalty acreage acquisitions during each year of our operations.
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Total
Net
Royalty Acres (NRAs) Acquired
500
9,700
17,300
7,200
9,800
9,400
14,900
13,400
4,085
6,090
92,375
Number
of Acquisitions
15
313
380
152
121
153
201
216
81
62
1,694
Average
NRAs per Acquisition
33
31
46
47
81
61
74
62
50
98
55
NRAs
at Period End
500
10,200
27,500
34,700
44,500
53,900
68,800
82,200
86,285
92,375
92,375
YoY%
Change
—
1,940
%
170
%
26
%
28
%
21
%
28
%
19
%
5
%
7
%
8
During
2021, our producing well count grew by 2,610 gross horizontal wells largely through acquisitions and the conversions of our DUC and permitted locations, representing an increase of 44% from December 31, 2020. In addition to this activity, 656 gross horizontal wells were spud on our mineral and royalty interests. The Company experienced mild production decline in 2021 with our production volumes declining approximately 5% for the year ended December 31, 2021 as compared to the year ended December 31, 2020. Further, our production volumes are comprised of high-value liquids with 70% of our volumes for the year ended December 31, 2021 composed of crude oil and NGLs, which represents 83% of
our mineral and royalty revenues for the period. We expect to see near term organic conversion of our asset from 850 gross DUCs across our interests and 873 gross horizontal drilling permits as of December 31, 2021, all of which are unburdened by additional capital expenditure outlays. Quarterly gross and net wells spud on our minerals have rebounded since the second quarter of 2020, which was our historic low point due to the dramatic curtailment in operator activity as a result of COVID-19 and the actions of OPEC, Russia, and other oil and gas producing countries ("OPEC+") during March 2020, both of which contributed to a dramatic decline in commodity prices during the first half of 2020. The chart below depicts historical gross and net wells spud on our acreage:
Average Quarterly Wells Spud on Acreage
In
addition to existing near-term development through the completion of our DUCs, we have a further 12,220 gross undeveloped locations providing us with substantial long-term organic drilling inventory on our acreage.
Our Mineral and Royalty Interests
Mineral interests are real-property interests that are typically perpetual and grant both ownership of the oil, natural gas and NGLs under a tract of land and the ability to lease development rights to a third party. When those rights are leased, usually for a three-year primary term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to a percentage of production or revenue. In addition to mineral interests, which represented approximately 93% of our net royalty acres as of December 31, 2021, we also own other similar
types of interests, including nonparticipating royalty interests and overriding royalty interests (“ORRIs”). ORRIs are a contractual arrangement burdening the working interest ownership of a lease and represent the right to receive a fixed percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated lease expires and are therefore not perpetual in nature.
9
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. Mineral and royalty owners only incur their proportionate share of severance and ad valorem taxes,
as well as in some instances, gathering, transportation and marketing costs. As a result, operating margins and therefore free cash flow for a mineral and royalty interest owner are higher as a percentage of revenue than for a traditional exploration and production operating company.
As of December 31, 2021, our mineral and royalty interests consisted of approximately 66,875 net mineral acres, which have been leased to operators to explore for and develop our oil and natural gas rights at a weighted average royalty of 17.3%. Typically, mineral owners standardize ownership to a 12.5% royalty, or 1/8th interest, which is referred to as a “net royalty acre.” Our net mineral acres standardized to a 1/8th interest equate to approximately 92,375 net royalty acres. Our net mineral acres standardized to a 100% royalty, or 8/8th basis, equate to approximately 11,540“100% royalty acres.” Our approximately 92,375 net royalty acres are located within 1,825 drilling spacing units (“DSUs”), which are the areas designated in a spacing order or unit designation as a drilling unit and within which operators drill wellbores to develop our oil and natural gas rights. Our DSUs, in aggregate, consist of a total of approximately 1,836,585 gross acres, which we refer to as our “gross DSU acreage.” Within our gross DSU acreage, we expect to have an interest in wells currently producing or that will be drilled in the future. The following table summarizes our mineral and royalty interest position and the conversion of our interests between net mineral acres, net royalty acres and 100% royalty acres as of December 31, 2021.
Net
Mineral Acres
Weighted Average Royalty
Net Royalty Acres(1)
100% Royalty Acres(2)
Gross DSU Acres
Implied Average Net Revenue Interest per Well(3)
66,875
17.3
%
92,375
11,540
1,836,585
0.6
%
(1) Standardized
to a 1/8th interest (i.e., 66,875 net mineral acres * 17.3% / 12.5%).
(2) Standardized to a 100% interest (i.e., 92,375 net royalty acres * 12.5%).
(3) Calculated as number of 100% royalty acres per gross DSU acre (i.e., 11,540 100% royalty acres /1,836,585 gross DSU acres).
10
Our
Properties
Focus Areas
Our mineral and royalty interests are primarily located in six resource plays, which we refer to as our focus areas. These include the Delaware and Midland Basins in the Permian Basin, the SCOOP and STACK plays in the Anadarko Basin, the DJ Basin and the Williston Basin. The following chart shows our overall exposure to each of our primary focus areas based on our net royalty acres in each focus area as of December 31, 2021
In addition, the following table summarizes certain information
regarding our primary focus areas. Our average daily net production for the year ended December 31, 2021 was comprised 51% of oil production, 30% of natural gas production and 19% of NGL production.
Average Daily Net Production for the Year Ended December 31, 2021(5) (Boe/d)
Average Daily Net Production for the Quarter Ended December 31, 2021(5) (Boe/d)
Resource Play/Basin
Net Mineral Acres
Weighted
Average Royalty
Net Royalty Acres(1)
100% Royalty Acres(2)
Gross DSU Acres
Implied Average Net Revenue Interest per Well(3)
Delaware
19,450
19.1
%
29,735
3,720
377,145
1.0
%
1,562
4,475
4,329
Midland
5,000
15.8
%
6,335
790
141,040
0.6
%
756
1,056
1,235
SCOOP
7,725
18.5
%
11,435
1,430
217,360
0.7
%
637
1,086
1,008
STACK
5,900
17.4
%
8,195
1,020
145,975
0.7
%
383
650
574
DJ
19,750
15.7
%
24,740
3,090
353,490
0.9
%
3,112
1,142
1,450
Williston
6,350
16.1
%
8,155
1,020
527,340
0.2
%
1,983
597
574
Other
2,700
17.5
%
3,780
470
74,235
0.6
%
162
34
—
Total
66,875
17.3
%
92,375
11,540
1,836,585
0.6
%
8,595
9,040
9,170
Note:
Individual amounts may not add up to totals due to rounding.
(1) Standardized to a 1/8th interest.
(2) Standardized to a 100% interest.
(3) Calculated as number of 100% royalty acres per gross DSU acre.
(4) Represents number of horizontal producing wells across all DSUs in which we participate.
(5) Represents actual production plus allocated accrued volumes attributable to the period presented.
11
Permian Basin-Delaware and Midland Basins
The
Permian Basin ranges from West Texas into southeastern New Mexico and is currently the most active area for horizontal drilling in the United States. The Permian Basin is further subdivided into the Delaware Basin in the west and the Midland Basin in the east. Based on our geologic and engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Delaware Basin are prospective for seven or more producing zones of economic horizontal development including the Wolfcamp A, B, C and XY; First, Second and Third Bone Spring; and the Avalon. Our Delaware Basin mineral and royalty interests are located in Reeves, Loving, Ward, Pecos, Culberson and Winkler Counties, Texas with our remaining interests located in Lea and Eddy Counties, New Mexico. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Midland Basin are
prospective for five or more producing zones of economic horizontal development including the Middle Spraberry; Lower Spraberry; and Wolfcamp A, B, C, and D / Cline. Our Midland Basin mineral and royalty interests are located in Martin, Midland, Upton, Howard, Glasscock and Reagan Counties, Texas.
Anadarko Basin-SCOOP and STACK Plays
The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens and McClain Counties. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the SCOOP play are prospective for two or more producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently testing other formations in the area including the Sycamore, Caney
and Osage, which is also referred to as SCORE (Sycamore Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo and Blaine Counties. Based on our geologic and engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the STACK play are prospective for two or more producing zones of economic horizontal development including multiple benches within both the Meramec and Woodford formations.
DJ Basin
The DJ Basin is located in Northeast Colorado and Southeast Wyoming, with the majority of operator horizontal drilling activity located in Weld and Broomfield Counties, Colorado, and Laramie County, Wyoming. Based on our geologic and engineering interpretations as well as current delineation efforts
by operators, we believe our mineral and royalty interests in the DJ Basin are prospective for four or more producing zones of economic horizontal development including the Niobrara A, B and C and Codell formations.
Williston Basin
The Williston Basin stretches from western North Dakota into eastern Montana with the majority of operator horizontal drilling activity located in Mountrail, Williams, and McKenzie Counties, North Dakota. Based on our geologic and engineering interpretations as well as current operator delineation efforts, we believe our mineral and royalty interests are prospective for two or more producing zones of economic horizontal development including the Bakken and multiple Three Forks benches. The majority of our interests are located in Mountrail, Williams and McKenzie Counties with additional interests owned in Divide, Burke, Dunn, Billings and Stark Counties,
North Dakota and Richland County, Montana.
As of December 31, 2021, we have identified 13,093 undeveloped gross proved, probable and possible drilling locations across our gross DSU acreage as identified in our December 31, 2021 reserve report audited by Cawley, Gillespie & Associates, Inc. ("CG&A"), our independent petroleum engineering firm. Furthermore, we believe additional optionality is possible through the delineation of additional formations as well as incremental wells
in existing formations. Approximately 58% of our total net horizontal undeveloped locations are located in the Delaware and Midland Basins, with another 20% located in the DJ Basin in Colorado, as shown in the following table.
Gross Horizontal Undeveloped Locations
Percentage
of Total Portfolio
Net Horizontal Undeveloped Locations
Percentage of Total Portfolio
Delaware Basin
5,304
41
%
53.7
49
%
Midland Basin
1,618
12
%
9.5
9
%
SCOOP
1,026
8
%
8.1
7
%
STACK
1,216
9
%
9.9
9
%
DJ
Basin
1,984
15
%
22.4
20
%
Williston
1,563
12
%
2.9
3
%
Other
382
3
%
2.9
3
%
Total
13,093
100
%
109.4
100
%
Note:
Individual amounts may not total due to rounding.
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Additionally, the following table provides a detailed summary of our inventory of horizontal drilling locations as of December 31, 2021.
(2) Includes all wells in each horizon, including PDP, DUC, permitted and unpermitted locations.
(3) Represents
the aggregate number of DSUs covering any of the applicable productive horizons as identified in the reserve report.
(4) The number of DSUs in each horizon and locations per DSU in each horizon do not total due to differing prospectivity of each horizon across each DSU (i.e., not all horizons are booked in all DSUs).
(5) A net well represents 100% net revenue interest in a single gross well.
Third-Party Operators
Beyond our technical analysis to identify core, highly economic geologic areas, an additional critical aspect of our evaluation process is to acquire mineral and royalty interests that will be drilled and completed by operators we believe will outperform their peers through the application of the latest drilling and completion technologies in
each of our focus areas. The following chart summarizes our exposure to these operators based on the percentage of our net interests in the wells to be drilled by each operator. Net interests per gross location are normalized to 7,500 ft. laterals.
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In addition, the following table shows our exposure to each of these operators broken down by our primary focus areas based on the percentage of our net interests in the wells to be drilled by each operator as of December 31,
2021.
Note:
Individual amounts may not add up to totals due to rounding.
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Business Objectives
Our primary business objective is to deliver an attractive risk-adjusted total return to our stockholders through (i) the organic growth of our free cash flow generated from our existing portfolio of approximately 92,375 net royalty acres, and (ii) the continued sourcing and execution of accretive ground game mineral acquisitions in the core of highly economic, liquids-rich resource plays, and (iii) large scale acquisitions and corporate consolidations..
Our
Corporate Structure
Brigham Minerals, Inc. was incorporated as a Delaware corporation in June 2018 for the purpose of completing the IPO and related transactions. On April 23, 2019, in connection with the IPO, Brigham Minerals became a holding company whose sole material asset consists of units in Brigham LLC (the “Brigham LLC Units”). Brigham LLC wholly owns Brigham Resources, which wholly owns the Minerals Subsidiaries, which own all of our operating assets. The remainder of the Brigham LLC Units are held by affiliates of Pine Brook Road Advisors, LP (“Pine Brook”) and certain of our management members and other prior investors (together with Pine Brook, the “Original Owners”).
As
the sole managing member of Brigham LLC, Brigham Minerals operates and controls all of the business and affairs of Brigham LLC, and through Brigham LLC and its subsidiaries, conducts its business. As a result, we consolidate the financial results of Brigham LLC and its subsidiaries and report non-controlling interest related to the portion of Brigham LLC Units not owned by us, which will reduce net income (loss) attributable to the holders of our Class A common stock. As of February 18, 2022, Brigham Minerals owned 81.0% of Brigham LLC.
Each of the Original Owners holds one share of our Class B common stock, par value $0.01 per share (the "Class B common stock"), for each Brigham LLC
Unit such person holds. Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B common stock on any exchange.
Under the First Amended and Restated Limited Liability Company Agreement of Brigham LLC (the “Brigham LLC Agreement”), each holder of a Brigham LLC Unit (a “Brigham Unit Holder”) has, subject to certain limitations, the 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 one 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. Our decision to make a cash payment upon a Brigham Unit Holder’s redemption election must be made by our independent directors (within the meaning of the New York Stock Exchange and Section 10A-3 of the Securities Act) who do not own Brigham LLC units that are subject to such redemption. 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 the right (the “Call Right”) to, for administrative convenience, acquire each tendered Brigham LLC Unit directly from the redeeming Brigham Unit Holder for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. 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. Under the Registration Rights Agreement we entered into with certain of the Original Owners in connection with the IPO, such Original Owners have the right, under certain circumstances, to cause us to register the
offer and resale of their shares of Class A common stock.
The following diagram indicates our simplified ownership structure as of February 18, 2022. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us.
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(1) Public stockholders include holders of shares of Class A common stock sold to the public,
issued pursuant to awards granted under our 2019 Long Term Incentive Plan ("LTIP") or issued to Brigham Unit Holders in connection with their exercise of the Redemption Right.
(2) Legacy Brigham Unit Holders include members of our management team and investors in our Company prior to our IPO (other than our Sponsors) who continue to hold Brigham LLC Units. Certain of the interests of our management in Brigham LLC are held indirectly through Brigham Equity Holdings, LLC. Brigham Equity Holdings, LLC directly owns 70,909 Brigham LLC Units, representing an approximate 0.1% interest in Brigham LLC. Total voting power does not include any shares of Class A common stock held by such legacy Brigham Unit Holders.
Our Principal Stockholders
We
have a valuable relationship with Pine Brook, a private investment firm focused on investments in the energy sector. As of February 18, 2022, affiliates of Pine Brook (collectively, our “Sponsors”) owned no shares of Class A common stock and 5,175,559 shares of Class B common stock representing approximately 8.7% of the voting power of Brigham Minerals and 5,175,559 Brigham LLC Units.
17
Principal Executive Offices
Our principal executive offices are located at 5914 W. Courtyard Drive, Suite 200, Austin, Texas78730, and our telephone number at that address is (512) 220-6350.
Our website address is www.brighamminerals.com. We make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with
or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report.
Oil, Natural Gas and NGLs Data
Proved, Probable and Possible Reserves
Evaluation and Audit of Proved, Probable and Possible Reserves. Our proved, probable and possible reserve estimates as of December 31, 2021, 2020 and 2019
were audited by CG&A, our independent petroleum engineers. Within CG&A, the technical person primarily responsible for auditing the reserve estimates set forth in the reserve reports incorporated herein is Todd Brooker. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor
of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers (SPEE).
Mr. Brooker meets or exceeds the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. CG&A does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A summary of CG&A’s report with respect to our proved, probable and possible reserve estimates as of December 31, 2021 is included as an exhibit to this Annual Report.
We maintain an internal staff of petroleum engineers and
geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved, probable and possible reserves relating to our properties. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved, probable and possible reserve report to discuss the assumptions and methods used in the proved, probable and possible reserve estimation process. We provide historical information to CG&A for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and our estimates of our operators’ operating and development costs. Hamilton Hogsett is primarily responsible for overseeing the preparation of our reserve estimates. Mr. Hogsett has substantial reservoir and operations experience having worked as a petroleum engineer since 2009 and is supported by our engineering
and geoscience staff. Prior to joining our Company in 2017, Mr. Hogsett worked at Apache Corporation and Antero Resources Corporation.
The preparation of our proved, probable and possible reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
•review and verification of historical production data, which data is based on actual production as reported by our operators;
•review by Mr. Hogsett, our Vice President of Reservoir Engineering, of all of our reported proved, probable and possible reserves, including the review of all significant reserve changes and all PUD additions
or reductions;
•verification of property ownership by our land department;
•review of reserve estimates by Mr. Hogsett or under his direct supervision; and
•direct reporting responsibilities by Mr. Hogsett to our Chief Executive Officer.
Estimation of Proved Reserves. In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, 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. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our proved reserves as of December 31, 2021, 2020 and 2019 were estimated using a deterministic method. The
18
estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination
results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high
degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for our properties, due to the abundance of analog data.
To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable
technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.
Estimation of Probable Reserves. Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil, natural
gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. All of our probable reserves as of December 31, 2021, 2020
and 2019 were estimated using a deterministic method, which involves two distinct determinations: an estimation of the quantities of recoverable oil and natural gas and an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of probable reserves, the recoverable reserves cannot be said to have a “high degree of confidence that the quantities will be recovered” but are “as likely as not to be recovered.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet
an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the probable location of over one mile but under three miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our probable reserves came from a combination of these factors depending upon the applicable basin. Many of the probable locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other probable locations had uncertainties related to not only distance from commercial production, but also related to well spacing
and development timing. In general, we did not book probable locations if there was geologic uncertainty or if there was not commercial production to support such locations.
Estimation of Possible Reserves. Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable
plus possible reserves. When probabilistic methods are used, there should be at least a 10%
19
probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. All of our possible reserves as of December 31, 2021, 2020 and 2019 were estimated using a deterministic method, which involves two distinct determinations: an estimation of the quantities of recoverable oil and natural gas and an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under
SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of possible reserves, the recoverable reserves cannot be said to be “as likely as not to be recovered”, but “might be achieved, but only under more favorable circumstances than are likely.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the possible location of over one mile but under five miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies
that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our possible reserves came from a combination of these factors depending upon the applicable basin. Many of the possible locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other possible locations had uncertainties related to not only distance from commercial production, but also related to well spacing and development timing. In general, we did not book possible locations if there was geologic uncertainty or if there was not commercial production to support such location.
Summary of Reserves. The following table presents our estimated net proved, probable and possible reserves
as of December 31, 2021, 2020 and 2019, based on our proved, probable and possible reserve estimates as of such dates, which have been audited by CG&A, our independent petroleum engineering firm, in accordance with the rules and regulations of the SEC. All of our proved, probable and possible reserves are located in the United States.
Our
estimated net proved, probable and possible reserves were determined using average first-day-of-the month prices for the prior 12 months in accordance with SEC guidance, as presented in the table below. These prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. For oil volumes, the average West Texas Intermediate ("WTI") posted prices were adjusted for quality, transportation fees and a regional price differentials (“SEC oil price”). For NGL volumes, the average WTI posted prices were adjusted for quality, transportation fees and a regional price differentials. For gas volumes, the average Henry Hub spot prices were adjusted for energy content, transportation fees and a regional price differentials (“SEC gas price”). The table below represents also the average adjusted product prices weighted by production over the remaining lives of the properties as of December
31, 2021, 2020 and 2019.
NGL
prices as a percent of the WTI posted prices, by basin
29% - 41%
10% - 25%
13% - 30%
Average adjusted product prices weighted by production over the remaining lives of the properties:
Oil price
$
64.46
$
36.35
$
51.01
NGL
price
$
26.65
$
8.19
$
14.39
Gas Price
$
3.22
$
1.03
$
1.51
Reserve
engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Item 1A—Risk Factors.”
Additional information regarding our proved, probable and possible
reserves can be found in the notes to our consolidated financial statements included elsewhere in this Annual Report and the proved, probable and possible reserve reports as of December 31, 2021 and December 31, 2020 and 2019, which are included as exhibits to this Annual Report.
PUDs
As of December 31, 2021, we estimated our PUD reserves to be 3,762 MBbls of oil, 9,800 MMcf of natural gas and 1,499 MBbls of NGLs, for a total of 6,894 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
The following tables summarize our changes in PUDs during the year ended December 31,
2021 (in MBoe):
Proved Undeveloped Reserves
Balance, Dec 31, 2020
6,922
Acquisition of reserves
520
Extensions and discoveries
875
Revisions
of previous estimates
(669)
Transfer to estimated proved developed
(754)
Balance, Dec 31, 2021
6,894
Changes in PUDs that occurred during 2021 were primarily due to:
•the acquisition of additional mineral and royalty interests located
in the Permian, Williston and DJ Basins in multiple transactions, which included 520 MBoe of additional PUD reserves;
•well additions, extensions and discoveries of approximately 875 MBoe, as 67 horizontal well locations were converted from probable, possible and contingent resource to PUDs due to continuous activity and delineation of additional zones on our mineral and royalty interests;
•total revisions of 669 MBoe driven by positive revisions of 805 MBoe attributable to an increase in SEC pricing offset by a negative revision of 159 MBoe attributable to estimated ultimate recovery ("EUR") adjustments, refined gas and
21
NGL
processing assumptions, and unit configuration changes; as well as a reclassification of 1,315 MBoe to non-proved, as a result of operator activity in the Anadarko Basin; and
•the conversion of approximately 754 MBoe in PUD reserves into proved developed reserves as 183 horizontal locations were drilled.
As a mineral and royalty interests owner, we do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the operator. As a result, during the year ended December 31, 2021, we did not have any expenditures to convert PUDs to proved developed reserves.
We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes DSU formation
and current well spacing information derived from state agencies and the operations of the exploration and production companies drilling our mineral and royalty interests. We generally do not have evidence of approval of our operators’ development plans, however, we use a deterministic approach to define and allocate locations to proved reserves. While many of our locations qualify as geologic PUDs, we limit our PUDs to the quantities of oil and gas that are reasonably certain to be recovered in the next five years. As of December 31, 2021 and 2020, approximately 19% and 28%, respectively, of our total proved reserves were classified as PUDs.
Oil, Natural Gas and NGL Production Prices and Costs
Production and Price History
The
following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:
(2) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
(3) General and administrative expenses exclude share-based compensation expenses.
Productive Wells
Productive wells consist of producing horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. As of December 31, 2021, we owned mineral and royalty interests in 8,595 gross productive horizontal wells, which consisted of 7,909 oil wells and
688 natural gas wells.
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We do not own any working interests in any wells. Accordingly, we do not own any net wells as such term is defined by Item 1208(c)(2) of Regulation S-K.
Acreage
The following table sets forth information relating to our acreage for our mineral and royalty interests as of December 31, 2021:
Basin
Gross
DSU Acreage
Net Royalty Acreage
100% Royalty Acreage
Delaware
377,145
29,735
3,720
Midland
141,040
6,335
790
SCOOP
217,360
11,435
1,430
STACK
145,975
8,195
1,020
DJ
353,490
24,740
3,090
Williston
527,340
8,155
1,020
Other
74,235
3,780
470
Total
1,836,585
92,375
11,540
The
vast majority of our mineral and royalty interests are leased to our operators with greater than 90% of our approximately 88,145 leased net royalty acres being held by production as of December 31, 2021. In addition, we had approximately 4,230 net royalty acres that were not leased as of December 31, 2021.
Drilling Results
The following table sets forth information with respect to the number of wells turned to production on our properties during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons,
whether or not they produce a reasonable rate of return. As a mineral and royalty interest owner, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory.
(1) We
are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
Regulation of Environmental and Occupational Safety and Health Matters
Oil, natural gas and NGL exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, including requirements to:
•obtain permits to conduct regulated activities;
•limit or prohibit drilling activities on certain lands
lying within wilderness, wetlands and other protected areas;
•restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;
•initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;
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•apply specific health and safety criteria addressing worker protection; and
•impose substantial liabilities for
pollution resulting from operations.
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement
policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to our operators of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to
which operations on our properties are subject.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency ("EPA") and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes generated. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of
oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil, natural gas and NGL drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of our operators’ operations.
Certain of our properties have been used for oil and natural gas exploration and production for many years. Although the operators may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under our properties, or on or under other offsite locations
where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. Our properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the owner or operator could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.
Water Discharges and NORM
The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants
into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The scope of federal jurisdictional reach over waters of the United States (“WOTUS”) has been subject to substantial revision in recent years. In January 2020, the EPA and the U.S. Army Corps of Engineers (the “Corps”) replaced a prior 2015 rule with the narrower Navigable Waters Protection Rule; challenges are pending
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against these rulemakings, and the Biden Administration has announced plans to establish its own definition of WOTUS. Most recently, the EPA and the Corps published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is
proposed, which the Biden Administration has announced is underway. Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the Clean Water Act and the definition of WOTUS. Therefore, the scope of jurisdiction under the Clean Water Act is uncertain at this time, and any increase in scope could result in increased costs or delays with respect to obtaining permits for certain activities for our operators. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean
Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.
In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.
Air
Emissions
The Clean Air Act of 1963 (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and regulations may require our operators to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, in December 2019, the EPA reclassified Colorado’s ozone nonattainment areas under the National Ambient Air Quality Standards ("NAAQS") from moderate to serious nonattainment. At times, the EPA may consider revising these NAAQS. For example, the Biden Administration
has announced plans to formally review a prior EPA decision to retain, without revision, the 2015 NAAQS for ozone. Also, the Colorado Air Quality Control Commission has approved new rules to reduce emissions from oil and gas operations in the state, including requirements for more extensive emissions monitoring and reporting. These revisions could increase the costs of development and production on our properties, potentially impairing the economic development of our properties. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Climate Change
The threat of climate change continues to attract considerable
attention in the United States and in foreign countries, numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit existing emissions of greenhouse gasses (“GHGs”) as well as to restrict or eliminate such future emissions.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG
emissions from certain petroleum and natural gas system sources in the United States, and together with the U.S. Department of Transportation (the “DOT”), implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. For more information, see our regulatory disclosure titled “Hydraulic Fracturing Activities.”
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined
Contributions (“NDCs”) every five years after 2020. Although the United States had withdrawn from the Paris Agreement, President Biden recommitted the United States to the agreement by executive order and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the 26th conference of parties (“COP26”) in
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Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. However, the impacts of these actions
remain unclear at this time.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including action taken by President Biden with respect to his climate change related pledges. On January 27, 2021, President Biden issued an executive order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also called for restrictions on leasing on federal land, including the Department of Interior’s publication of a report recommending various changes to the federal leasing program,
though many such changes would require Congressional action. Substantially all of our mineral interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas (“LNG”) export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against certain oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of
climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulting in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally
require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve joined the Network for Greening the Financial System ("NGFS"), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring
liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may adversely impact
the production or attractiveness of our assets.
Hydraulic Fracturing Activities
A substantial portion of the production on our properties involved the use of hydraulic fracturing techniques. Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense
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subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production.
Hydraulic fracturing typically is
regulated by state oil and natural gas commissions or similar agencies, but the EPA has asserted federal regulatory authority pursuant to the U.S. Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued permitting guidance that applies to such activities. Additionally, the EPA issued final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions of methane and volatile organic compounds released during hydraulic fracturing. In September 2020, the Trump Administration revised these regulations to remove the transmission and storage segments from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments. In November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time
existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirements, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year.
Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.
In
addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. Separately, in Texas, there has been increased pressure on the Railroad Commission (“RRC”) to impose more stringent limitations on the flaring of gas from oil wells to prevent waste and because of increased concerns related to the environmental effects of flaring. The RRC continues to approve flaring permits, but at least one lawsuit has been filed
by a pipeline operator challenging the RRC’s flaring approval practices. Additionally, the RRC has approved a new flaring request form, which may result in reducing approvals for flaring. Any future requirements limiting flaring could adversely affect exploration and production activities on our properties and result in increased costs to connect wells to pipelines. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. For more information on such restrictions in Colorado, see “Item 1A—Risk Factors—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.” If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements
could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil, natural gas and NGL exploration and production activities and, therefore, adversely affect the development of our properties.
Endangered Species Act
The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause our operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat
includes the Permian Basin, and Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states, and to reconsider listing the species under the ESA. In July 2020, the US Fish and Wildlife Service ("FWS") determined that sufficient information had been presented to warrant a 12-month review for listing of the Dunes Sagebrush Lizard, which review is ongoing; the agency is also reviewing a candidate conservation agreement with assurances for the species. In June 2021, the FWS proposed to list two distinct population segments of the Lesser Prairie Chicken, whose range extends to areas where we may hold mineral interests, under the ESA. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species
protection measures and face delays or limitations with respect to production activities thereon.
Employee Health and Safety
Operations on our properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and
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safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained
concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.
Judicial and Legislative Matters
Muscogee (Creek) Nation Reservation
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 the 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 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. 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 has 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. 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 jurisdictional issues may ultimately be resolved. 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. 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. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access has 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. The pipeline continues to operate pending completion of the Environmental Impact Statement which the Corps now estimates will be complete by the end of 2022. 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.
Implementation
of Colorado SB 19-181 (“SB 181”)
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 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
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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. These and other developments related to the implementation of SB 181 could adversely impact our revenues and future production from our properties.
Title to Properties
Prior to completing an acquisition of mineral and royalty interests, we perform a title review on each tract to be acquired. Our title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related burdens. For our Texas properties, we obtain a limited title memorandum rendered by an oil and gas law firm.
As a result, title examinations have been obtained on a significant portion of our properties.
In addition to our initial title work, operators often will conduct a thorough title examination prior to leasing and/or drilling a well. Should an operator’s title work uncover any further title defects, either we or the operator will perform curative work with respect to such defects. An operator generally will not commence drilling operations on a property until any material title defects on such property have been cured. We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of oil and gas interests, non-participating royalty interests and other burdens, easements, restrictions or minor encumbrances customary in the oil and natural gas industry,
we believe that none of these encumbrances will materially detract from the value of these properties or from our interest in these properties.
Competition
The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases and personnel required to find and produce reserves. Many of our competitors not only own and acquire mineral and royalty interests but also explore for and produce oil and natural gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, certain of our competitors may possess financial or other resources
substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
In addition, oil and natural gas products compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Seasonality of Business
Weather conditions affect the demand for, and prices of, natural
gas and can also delay drilling activities, disrupting our overall business plans. Additionally, some of the areas in which our properties are located are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, our operators may be unable to move their equipment between locations, thereby reducing their ability to operate our wells, reducing the amount of oil and natural gas produced from the wells on our properties during such times. For example, the prior winter storms in February 2021 adversely affected operator activity and production volumes in the southern United States, including in the Permian Basin. Additionally, extended drought conditions in the areas in which our properties are located could impact our operators’ ability to source sufficient water or increase the cost for such water. Furthermore, demand for natural gas is typically higher during the winter, resulting in higher natural
gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
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Human
Capital Resources
Culture
Our employees are one of our most valuable assets.Our small size and organizational structure promote a highly collaborative working environment and shared sense of purpose that differentiates us from our competitors. In addition, we rely on the strength of our technical expertise, particularly those individuals engaged in our engineering and geology departments, to inform our investment decisions and portfolio construction and management. Given our team’s understanding of oil and gas operations, we are able to better assess risk inherent in the mineral and royalty assets we acquire.
Headcount and Demographics
As of December 31, 2021, we had 44 full-time
employees and six temporary employees. All of our employees are located in our Austin, Texas office. In addition to our two founders, we currently have approximately 12 full-time employees in our engineering and geology departments, seven full-time employees dedicated to our ground game acquisition and business development departments, eight full-time employees in our land department, and 14 full-time employees in our finance, accounting, information technology and legal departments. The vast majority of our temporary employees are part-time employees that assist the ground game acquisition and business development departments. Approximately 46% of our employees are female and approximately 34% of our employees identify as minorities. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory. We hire independent contractors on an as needed basis.
Competitive Compensation
and Benefits
Our compensation programs are designed to align the compensation of our employees with our performance and to provide the proper incentives to attract, retain and motivate our employees to achieve top-quality results. Specifically:
•We engage a nationally recognized outside compensation and benefits consulting firm to provide benchmarking against our peers within the industry for executive compensation.
•Our executive compensation program is designed to attract, motivate and retain high-quality leadership and incentivize our executive officers to achieve performance goals over the short- and long-term, which also aligns the interests of our executive officers with those of our stockholders. As such, our compensation program for our executive officers is heavily weighted toward
equity-based compensation and does not include an annual cash bonus. Equity-based compensation generally includes both restricted stock units subject to time-based vesting and restricted stock units subject to performance-based vesting.
•All full-time employees are eligible for health insurance paid for 100% by us, paid and unpaid leaves, including parental leave, a retirement plan and disability/accident coverage.
•We have a corporate philanthropy program that provides matching gifts by us for both monetary gifts by employees and time volunteered by employees during their personal time, along with group opportunities for employees to volunteer together once a quarter during company time.
•We have an education reimbursement program to assist our employees in developing
knowledge, skills and job effectiveness through higher education.
•We provide onsite fitness classes four days a week, providing our employees with the opportunity to be active, boost their mental health and interact with others from different departments.
Training and Development
In light of our small size and collaborative working environment, we currently do not have a need to implement a formal in-house training and development program. Instead, we emphasize on-the-job training, informal mentoring and encourage our employees to participate in external training and development courses, programs and professional organizations. Our employees are encouraged to take responsibility for their development, and we are committed to ensuring that they have the resources they need to succeed.
Retention
and Tenure
The combination of our culture, competitive compensation, career growth and development opportunities foster employee tenure and reduce voluntary turnover rates. The average tenure of our employees is approximately four years.
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Workplace Safety
We care about the safety of our colleagues and all visitors to our workplace. During 2021, our continued focus on workplace safety from 2020 enabled us to keep our offices open in spite of the ongoing COVID-19 pandemic.Once COVID-19 vaccines were available, we provided vaccination encouragement payments to those employees that
chose to get vaccinated and boosted. As a result, approximately 85% of our employees have received at least two doses of the COVID-19 vaccine.
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Item 1A. Risk Factors
Summary of Risk Factors
An investment in our shares of Class A common stock involves a significant degree of risk. Below is a summary of certain risk factors that you should consider in evaluating us and our Class A common stock. However, this list is not exhaustive. Before you invest in our Class A common
stock, you should carefully consider the risk factors discussed or referenced below and under Item 1A. “Risk Factors” in this Annual Report on Form 10-K. If any of the risks discussed below and under Item 1A. “Risk Factors” were actually to occur, our business, financial condition, results of operations and cash flows could be adversely affected and our results could differ materially from expected and historical results, and of which may also adversely affect the holders of our Class A common stock.
Risks Related to Our Business
•The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.
•Substantially
all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold.
•We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests.
•Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.
•Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
•Our
operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
•We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.
•Acquisitions and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
•Our
future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.
•We have little to no control over the timing of future drilling with respect to our mineral and royalty interests.
•Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.
•The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
•The
marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators’ control.
•Our estimated reserves are based on many assumptions that may turn out to be inaccurate.
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•If oil, natural gas and NGL prices decline significantly, we could be required to record additional impairments of our proved oil, natural gas and NGL properties that would constitute a charge to earnings and reduce our stockholders’ equity.
Risks
Related to Environmental and Regulatory Matters
•Conservation measures, technological advances, general concern about the environmental impact of the production and use of fossil fuels and increasing attention to environmental, social and governance (“ESG”) matters could materially reduce demand for oil, natural gas and NGLs and adversely affect our results of operations, availability of capital and the trading market for shares of our Class A common stock.
•Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may
impact our operators’ willingness to develop our interests.
•Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.
Risks Related to Our Financial and Debt Arrangements
•Our derivative activities could result in financial losses and reduce earnings.
•Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.
Risks Related to Our Class A Common Stock
•Brigham
Minerals is a holding company. Brigham Minerals’ sole material asset is its equity interest in Brigham LLC and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other overhead expenses and pay any dividends on our Class A common stock.
•The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
•If we fail to develop or maintain an effective
system of internal controls, we may not be able to accurately report our financial results or prevent fraud.
•Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
•Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Sponsors to benefit from corporate opportunities that might otherwise be available
to us.
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Risk Factors
The following are certain risk factors that affect our business, financial condition, results of operations and cash flows. Many of these risks are beyond our control. These risk factors are not exhaustive and investors are encouraged to perform their own investigation with respect to our business, financial condition and prospects. You should carefully consider the following risk factors in addition to the other information included in this Annual Report, including matters
addressed under “Cautionary Statement Regarding Forward-Looking Statements.” If any of the events described below were to actually occur, our business, financial condition, results of operations and cash flows could be adversely affected, and our results could differ materially from expected and historical results, any of which may also adversely affect the holders of our Class A common stock.
Risks Related to Our Business
The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside
of our control, and could significantly disrupt our operations and adversely affect our financial condition. For example, the continuing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a disruption to the oil and natural gas industry and to our business. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. Furthermore, the COVID-19 pandemic has affected our operations by (i) rendering our personnel unable to access company facilities for an extended period of time, (ii) contributing to a steep decline in commodities prices in 2020, which reduced activity by our operators and the amounts of royalty payments we received, (iii) causing some of the Company’s operators to shut
in and curtail production from wells on the Company’s properties for a period of time, (iv) limiting our access to the capital markets on terms favorable to us and adversely affected our capital resources and (v) reducing the level of potential acquisition opportunities we have been able to identify, limiting our ability to execute on our growth strategy of acquiring additional mineral and royalty interests. Additionally, the steps taken by national, state and local governments to curb the spread of the COVID-19 pandemic, including stay-at-home orders, quarantines, travel restrictions and business shutdowns, and the implications on our operators’ workforce of a COVID-19 infection, have limited our operators’ ability to maintain production from our properties. Such orders and the other impacts of the COVID-19 pandemic may have limited the ability of our operators to access our properties
and maintain their existing production and development activities, and any similar or more restrictive measures taken in the future could have similar effects.
While our business and operations have experienced certain effects of the COVID-19 pandemic as described above, the full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to operating production activities by our operators and the impact of potential governmental restrictions on travel, transportation
and operations. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations, financial results and dividend policy will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the pandemic, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. For example, there has been a recent significant increase in cases of COVID-19 in the U.S. that could lead to re-implementation of certain governmental restrictions. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.
Substantially
all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests are sold. Prices of oil, natural gas and NGLs are volatile due to factors beyond our control. A significant drop in the price of oil or a substantial or extended decline in commodity prices in the future may adversely affect our business, financial condition or results of operations.
Our revenues, operating results, free cash flow and the carrying value of our mineral and royalty interests depend significantly upon the quantities of oil, natural gas and NGLs produced from our properties and the prevailing prices at which such production is sold. Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety
of additional factors that are beyond our control, including:
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•the domestic and foreign supply of and demand for oil, natural gas and NGLs;
•market expectations about future prices of oil, natural gas and NGLs;
•the level of global oil, natural gas and NGL exploration and production;
•the cost of exploring for, developing, producing and delivering oil, natural gas and NGLs;
•the price and quantity of foreign imports and U.S. exports
of oil, natural gas and NGLs;
•the level of U.S. domestic production;
•the availability of storage for hydrocarbons;
•political and economic conditions in the U.S. and other oil producing regions, including the Middle East, Africa, South America and Russia;
•the ability of members of OPEC and other countries that produce oil, natural gas, and NGLs to agree to and maintain oil price and production controls;
•trading in oil, natural gas and NGL derivative contracts;
•the
level of consumer product demand;
•weather conditions and natural disasters;
•technological advances affecting energy consumption, energy storage and energy supply;
•domestic and foreign governmental regulations and taxes;
•the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran;
•global or national health concerns, including health epidemics such as the ongoing COVID-19 pandemic;
•the proximity,
cost, availability and capacity of oil, natural gas and NGL pipelines and other transportation facilities;
•the price and availability of alternative fuels; and
•overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, during the past five years, the posted price for WTI light sweet crude oil has ranged from a historic, record low price of negative $36.98 per barrel in April 2020 to a high of $85.64 per barrel in October 2021. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Certain actions by OPEC+ in the first half
of 2020, combined with the impact of the continued outbreak of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the U.S., contributed to the historic low price for oil in April 2020. While the prices for oil have generally stabilized and also increased, such prices have historically remained volatile, which may adversely affect the prices at which production from our properties is sold as well as the production activities of operators on our properties. This, in turn, may materially affect the amount of royalty payments that we receive from such operators.
Any substantial decline in the price of oil, natural gas and NGLs or a prolonged period of low commodity prices will also materially adversely affect our business, financial condition, results of operations and free cash flow. In addition, the quantities of oil, natural gas and NGLs produced from our properties has a significant impact on our
operating results and financial condition. Lower oil, natural gas and NGL prices may reduce the amount of oil, natural gas and NGLs that can be produced economically by our operators, which may reduce our operators’ willingness to develop and/or continue to produce our properties. For example, partially due to the decrease in prices for oil in 2020, many operators on our properties substantially reduced their development activities and capital expenditures in 2021. Additionally, lower commodity prices resulted in some of the Company's operators temporarily shutting in or curtailing production from wells on its properties during the second quarter of 2020.
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A
deterioration in commodity prices, decrease in production levels, or reduction in operator production activities may result in our having to make substantial downward adjustments to our estimated proved, probable or possible reserves. If this occurs or if production estimates change or exploration or development results deteriorate, the full cost method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. In addition, the borrowing base under our revolving credit facility is determined based on our estimated proved reserves, and any negative revisions to our estimated proved reserves would in turn reduce our borrowing base, reducing the amount available to fund our operations through borrowings under our revolving credit facility.
We depend on various unaffiliated operators for all of the exploration,
development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in 2020, many of our operators substantially reduced their development activities and capital expenditures in 2021. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may occur again in the future.
Our assets consist of mineral and royalty interests. Because we depend on third-party operators for all of the exploration, development and production on our properties, we
have little to no control over the operations related to our properties. For the year ended December 31, 2021, we received revenues from over 178 operators with approximately 67% of our royalty revenues coming from the top ten operators on our properties, four of which each accounted for more than 10% of such royalty revenues. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Furthermore, in response to the significant decrease in prices for oil in 2020, many of our operators substantially reduced their development activities, capital expenditures, rig count and completion crews in 2021. Additionally, certain investors have requested operators adopt initiatives to return capital to investors, which could also reduce the capital available to our operators for investment in exploration,
development and production activities. Our operators may further reduce capital expenditures devoted to exploration, development and production on our properties in the future, which could negatively impact revenues we receive. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may continue in the future, especially as a consequence of any reductions in operators’ capital expenditures. Moreover, over the last two years, many of our operators have announced that they plan to drill fewer wells per section than previously anticipated, due in part to greater well-interference between parent and child wells than previously anticipated and an increased focus on overall capital efficiency.
If production on our mineral and royalty interests decreases due to decreased development activities, as a result of the low commodity price environment, limited
availability of development capital, production-related difficulties or otherwise, our results of operations may be adversely affected. For example, in 2020, the amount of royalty payments we received from our operators decreased due to the lower prices at which our operators were able to sell production from our properties and reduced production activities by our operators. Further, depressed commodity prices caused some of our operators to voluntarily shut in and curtail production from wells on our properties earlier in 2020. Although most of these have come back online, an additional or extended period of depressed commodity prices may cause additional operators to take similar action or even to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions, both of which would decrease the amount of royalty payments we receive from our operators. Our operators are often not
obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states). Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that are largely outside of our control, including:
•the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;
•the ability of our operators
to access capital;
•prevailing commodity prices;
•the operators' expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
•the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
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•the availability of storage for hydrocarbons;
•the operators’ expertise, operating efficiency and financial resources;
•approval
of other participants in drilling wells;
•the selection of technology;
•the selection of counterparties for the marketing and sale of production; and
•the rate of production of the reserves.
The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and free cash flow. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and free cash flow. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have
a material adverse impact on our cash flows.
Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.
We depend partly on acquisitions to grow our reserves, production and free cash flow. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:
•recoverable reserves;
•future
oil, natural gas and NGL prices and their applicable differentials;
•development plans;
•the operating costs our operators would incur to develop and operate the properties; and
•potential environmental and other liabilities that operators of the properties may incur.
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to
assess fully their deficiencies and capabilities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time as volatile commodity prices drive ever changing market dynamics, which can constrain our ability to capture these opportunities Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing. In addition, these acquisitions may be in geographic regions in which we do not currently hold properties, which could subject us to additional and unfamiliar legal and regulatory requirements. Further,
the success of any completed acquisition will depend on our ability to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and free cash flow. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions
and current operations, which, in turn, could negatively impact our growth, results of operations and free cash flow.
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Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
Even if we do make acquisitions that we believe will increase our cash generated from operations, any acquisition involves potential risks, including, among other things:
•the validity of our assumptions about estimated proved,
probable and possible reserves, future production, prices, revenues, capital expenditures, the operating expenses and costs our operators would incur to develop the minerals;
•a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
•the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
•mistaken assumptions
about the overall cost of equity or debt;
•our ability to obtain satisfactory title to the assets we acquire;
•an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
•the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, inclement weather, regulatory changes and approvals, oil, natural gas and NGL prices, costs, drilling results and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural
gas exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.
We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Additionally, actual production from wells
may be less than expected. For example, a number of operators have previously announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation and free cash flow.
Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our interpretation of such data. As a result, our operators may have reached different conclusions about the potential drilling locations on our properties,
and our operators control the ultimate decision as to where and when a well is drilled.
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We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.
A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess
the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. For example, certain of our operators have recently commenced bankruptcy proceedings under the Bankruptcy Code and their future operations and ability to make royalty payments to us may be adversely affected by such proceedings. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately
reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced. Additionally, in low commodity price environments, such as that experienced in 2020, some operators have attempted to make improper deductions by netting negative gas price realizations against positive oil royalties and other operators may attempt to do so in the future. We have taken action and will continue to take action to protect our rights; however, we cannot predict whether we will ultimately be successful.
Acquisitions
and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures primarily with funding from capital contributions, cash generated by operations, proceeds from our IPO and from the December 2019 Offering and borrowings under our debt arrangements.
In the future, we may need capital in excess of the amounts we retain in our business or borrow under our revolving credit facility. The level of borrowing base available under our revolving
credit facility is largely based on our estimated proved reserves and our lenders' price decks and will be reduced to the extent commodity prices decrease. Furthermore, we cannot assure you that we will be able to access other external capital on terms favorable to us or at all. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and free cash flow.
Most
of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests may decline.
Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties. Unless we replace the oil, natural gas and NGLs produced from our properties, our results of operations and financial position could be adversely affected.
Producing oil and natural gas wells are characterized by declining production rates that vary depending upon
reservoir characteristics and other factors. Our future oil, natural gas and NGL reserves and our operators’ production thereof and our free cash flow are highly dependent on the successful development and exploitation of our current reserves and our ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire or develop additional reserves to replace the current and future production of our properties at economically acceptable terms. Aside from acquisitions, we have little to no control over the exploration and development of our properties. If we are not able to replace or grow our oil, natural gas and NGL reserves, our business, financial condition and results of operations would be adversely affected.
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We
have little to no control over the timing of future drilling with respect to our mineral and royalty interests.
As of December 31, 2021, only 28,911 MBoe of our total estimated reserves were proved developed reserves. The remaining 6,894 MBoe, 48,394 MBoe and 25,996 MBoe of our total estimated reserves as of December 31, 2021 were PUDs, probable undeveloped reserves and possible undeveloped reserves, respectively, and may not ultimately be developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of an undeveloped drilling location will be made by the operator and not by us. We generally do not have access to the estimated costs of development
of these reserves or the scheduled development plans of our operators. The reserve data included in the reserve report audited by CG&A assumes that our operators must incur substantial capital expendituresto develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved undeveloped reserves as unproved reserves.
Project areas
on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.
Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and free cash flow may be adversely affected.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
The
oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. In addition, the economy has begun to experience elevated inflation levels as a result of global supply and demand imbalances resulting from the ongoing COVID-19 pandemic, resulting in increased costs of the goods, services and labor used by our operators, which has increased their operating
costs. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of, or an increase in costs for, drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.
The marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators' control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production
and could harm our business.
The marketability of our or our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities, and the shipment of our or our operators’ oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising
from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity could reduce our or our operators’ ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and free cash flow. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation-including regulation of oil, natural gas and NGL production, transportation and pipeline safety-
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as
well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil, natural gas and NGL reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGL prices, production levels, ultimate recoveries
and operating and development costs. As a result, estimated quantities of proved, probable and possible reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our estimates of proved, probable and possible reserves and related valuations as of December 31, 2021, 2020 and 2019 were audited by CG&A. CG&A conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. For example, due to the deterioration in commodity prices and operator activity in 2020 as a result of the COVID-19 pandemic and other factors, the commodity price assumptions used to calculate our
reserves estimates declined, which in turn lowered our proved reserve estimates. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs that are ultimately recovered being different from our reserve estimates.
Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial
Accounting Standards Board, we base the estimated discounted future net cash flows from our proved reserves on the trailing twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
SEC
rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production
data and permit trends, as well as investor presentations and other public statements of our operators. Although we believe that our approach in making such determinations is conservative, the accuracy of any such determination is inherently uncertain and subject to a number of assumptions and factors outside of our control, including but not limited to those described under “We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in 2020, many of our
operators substantially reduced their development activities and capital expenditures in 2021. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may occur again in the future.” Any significant variance between our estimates and the actual drilling schedules of our operators may require us to write down our proved undeveloped reserves.
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If oil, natural gas and NGL prices decline significantly, we could be required to record additional impairments of our proved oil, natural gas and NGL properties that would constitute a charge to earnings and reduce our stockholders’ equity.
Accounting
rules require that we review the carrying value of our oil, natural gas and NGL properties for possible impairment at the end of each quarter. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development activities, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of our proved oil, natural gas and NGL properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of our proved oil, natural gas and NGL reserves, the excess capitalized costs are charged to expense. Impairments would occur if we were to experience sufficient
downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. The risk that we will be required to recognize impairments of our oil, natural gas and NGL properties increases during periods of low commodity prices, such as those experienced in 2020. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil, natural gas and NGL prices increase the cost center ceiling applicable to the subsequent period. If we incur impairment charges in the future, our results of operations for the periods in which such charges are taken may be materially and adversely affected.
The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our
operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations.
Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production
profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and free cash flow could be adversely affected.
Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities. In addition, our ORRIs may be lost if the underlying acreage is not drilled before the expiration
of the applicable lease or if the lease otherwise terminates.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.
Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of our mineral interests expires or terminates, all mineral rights revert back to us and we will have to seek
new lessees to explore and develop such mineral interests. If the lease underlying any of our ORRIs expires or terminates, our ORRIs that are derived from such lease will also
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terminate. Any such expirations or terminations of our leases or our ORRIs could materially and adversely affect the growth of our financial condition, results of operations and free cash flow.
Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition and results of operations.
The
drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our stockholders that wells drilled by the operators of our properties will be productive. Drilling for oil, natural gas and NGLs often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil, natural gas or NGLs to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil, natural gas or NGL is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators’ drilling and producing operations may be curtailed, delayed,
canceled or otherwise negatively impacted as a result of other factors, including:
•unusual or unexpected geological formations;
•loss of drilling fluid circulation;
•title problems;
•facility or equipment malfunctions;
•unexpected operational events;
•shortages or delivery delays of equipment and services;
•compliance with environmental and other governmental requirements; and
•adverse weather conditions, including the
prior winter storms in February 2021 that adversely affected operator activity and production volumes in the southern United States, including in the Permian Basin.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and free cash flow may be materially adversely affected.
Operating hazards and uninsured risks may result in substantial losses to us
or our operators, and any losses could adversely affect our results of operations and free cash flow.
The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of oil, natural gas and NGLs, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of oil, natural gas, NGLs and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to
our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators’ ability to succeed.
The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil, natural gas and NGLs, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these
companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and
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NGL market prices. Our operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Furthermore, the oil and gas industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of
combined companies with larger resources. Such combined companies may compete against our operators or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties. In addition, we face competition in identifying and acquiring additional properties and reserves. See “Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results of operations.”
Title to the properties in which we have an interest may be impaired by title defects.
We are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to examine the title to our royalty and mineral interests. In such cases, we would rely upon the judgment of oil and gas lease brokers
or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a specific royalty or mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and free cash flow. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. If there are any title defects in properties in which we hold an interest, we may suffer a financial loss.
We rely on a few key individuals whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number
of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.
Loss of our or our operators’ information and computer systems, including as a result of cyber attacks, could materially and adversely affect our business.
We and our operators rely on electronic systems
and networks to control and manage our respective businesses. If any of such programs or systems were to fail for any reason, including as a result of a cyber attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences could be significant, including loss of communication links and inability to automatically process commercial transaction or engage in similar automated or computerized business activities. Although we have multiple layers of security to mitigate risks of cyber attacks, cyber attacks on business have escalated in recent years. Moreover, our operators are becoming increasingly dependent on digital technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating reserves. The U.S. government has issued public
warnings that indicate that energy assets might be specific targets of cyber security threats. If our operators become the target of cyber attacks of information security breaches, their business operations may be substantially disrupted, which could have an adverse effect on our results of operations. In addition, our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring. Additionally, we regularly enter into transactions directly with individual mineral and royalty interest owners, who may have less sophisticated electronic systems or networks and may be more vulnerable to cyber-attacks. For example, in August 2021, an individual mineral owner’s email account was compromised, which resulted in a fraudulent payment of approximately $165,000 in connection with an acquisition. As a result of this incident,
we have implemented formal procedures and controls to mitigate future occurrences of such incidents, but there can be no assurance that these efforts will be sufficient to prevent similar attacks or breaches from occurring in the future.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.
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If
any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil, natural gas and NGLs, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil, natural gas and NGL related facilities could be direct targets of terrorist attacks, and, if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
A deterioration in general economic, business, political or industry conditions, such as those experienced in 2020, could materially adversely affect our results of operations, financial condition and free cash flow.
In
recent years, concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to significantly reduced economic activity and diminished expectations for the global economy. Additionally, recent acts of protest and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply of crude oil in 2020 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum
products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of our operators to continue operations and ultimately materially adversely impact our results of operations, financial condition and free cash flow.
Risks Related to Environmental and Regulatory Matters
Conservation measures, technological advances and increasing attention to ESG matters could materially reduce demand for oil, natural gas and NGLs, availability of capital and adversely affect our results of operations and the trading market for shares of our Class A common stock.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and
NGLs, technological advances in fuel economy and energy-generation devices could reduce demand for oil, natural gas and NGLs. The impact of the changing demand for oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and free cash flow.
It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own shares of our Class A common stock, adversely affecting the market price of our Class A common stock. For example, certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors
and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to divest from, or not provide funding to, the oil and gas sector based on their social and environmental considerations. Furthermore, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors and other financial institutions to inform their investment, financing and voting decisions, and unfavorable ESG ratings may lead to increased negative sentiment toward us from such institutions. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on
the stock prices of oil and gas companies, including ours and also adversely affect our availability of capital. Additionally, to the extent ESG matters negatively impact our or our operators’ reputation, we or our operators may not be able to compete as effectively to recruit or retain employees, which may adversely affect our or our operators’ operations.
Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.
Our operators’ operations on the properties in which we hold interests are subject to various federal,
state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and
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pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil, natural gas and NGLs. In addition, the production, handling, storage and transportation
of oil, natural gas and NGLs, as well as the remediation, emission and disposal of oil, natural gas and NGL wastes, by-products thereof and other substances and materials produced or used in connection with oil, natural gas and NGL operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker health and safety, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our operators, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operators’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control and waste management.
Laws
and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including, but not limited to:
•provisions related to the unitization or pooling of the oil and natural gas properties;
•the establishment of maximum rates of production from wells;
•the spacing of wells;
•the plugging and abandonment of wells; and
•the removal of related production equipment.
Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety
laws and regulations. For example, in November 2021, the Pipeline and Hazardous Materials Safety Administration issued a final rule significantly expanding reporting and safety requirements for operators of gas gathering pipelines, including previously unregulated pipelines. Compliance with such regulations may require increased capital costs for third-party oil, natural gas and NGL transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on our properties.
Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.
Our
operators may be required to make significant expenditures to comply with the laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. For example, following the election of President Biden and a Democratic majority in both houses of Congress, it is possible that our operators may continue to be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and GHG emissions. Please read “Item 1—Business—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production and may ultimately
impact our operators’ ability and willingness to develop our properties.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.
Our operators engage in hydraulic fracturing, which is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the SDWA Underground Injection Control program and is typically regulated by state oil and gas commissions or
similar agencies.
However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to
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require disclosure of the chemicals used in the hydraulic fracturing process. This or other federal legislation related to hydraulic fracturing
may be considered again in the future, though we cannot predict the extent of any such legislation at this time.
Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. In April 2019, Colorado adopted Senate Bill 19-181, which made sweeping changes in Colorado oil and gas law, including among other matters, requiring the COGCC to prioritize public health and environmental concerns in its decisions, instructing the
COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. In keeping with SB 19-181, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions established more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminated routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict
drilling in general and/or hydraulic fracturing in particular. Additionally, on December 17, 2021, the Colorado Air Quality Control Commission adopted regulations aimed at curbing methane emissions from oil and gas operations to include setting methane emission limits per 1,000 Boe produced, more frequent inspections and limits on emissions during maintenance.
Separately, several state and federal agencies have examined a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. The United States Geological Survey has identified eight states, including Oklahoma and Texas,
with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. To that end, states in which some of our operators operate have introduced protocols or guidance regarding saltwater disposal wells. For example, in September 2021, the RRC issued a notice to operators in the Midland area to reduce saltwater disposal well actions and provide certain data to the commission. Subsequently, the RRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021. Separately, New Mexico has implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. As a result of these developments, our operators may be required to curtail operations or adjust development
plans, which may adversely affect our business.
In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. In some instances, regulators may also order that disposal wells be shut in.
Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater
opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques in areas where we own mineral and royalty interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for our operators in the production of oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult for our operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in our operators’ completion of new oil and natural gas wells on our properties and an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations.
Restrictions
on the ability of our operators to obtain water may have an adverse effect on our financial condition, results of operations and free cash flow.
Water is an essential component of deep shale oil, natural gas and NGL production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country, and in particular the western United States, have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be
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exacerbated
by climate change. If our operators are unable to obtain water to use in their operations from local sources, or if our operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil, natural gas and NGLs from our properties, which could have an adverse effect on our financial condition, results of operations and free cash flow.
A series of risks arising out of the threat of climate change could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the oil, natural gas and NGLs that our operators produce.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a result, our operations as well as the operations
of our operators and our operators’ suppliers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States,
and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have
to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirements, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule, and anticipates the issuance of a final rule by the end of the year. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.
Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs,
carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement" requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions (“NDCs”) every five years after 2020. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at COP26, the United States and the European Union jointly announced the launch of a Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be
adopted or implemented that may have adverse effects upon us and our operators’ operations.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including action taken by President Biden with respect to his climate change related pledges. On January 27, 2021, President Biden issued an executive order that called for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also called for restrictions on leasing on federal
land, including the Department of Interior’s publication of a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. Substantially all of our mineral interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of parties have sought to bring suit against
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certain
oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, GFANZ announced that commitments from over
450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation
of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural
gas, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operatorsrestricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patters, that could adversely impact our operations, as well as those of our operators and their supply chains.
Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes.
Changes to applicable tax laws and regulations or exposure to additional income tax liabilities, including any future legislation that generally affects the taxation of natural gas and oil exploration and development companies such as our operators, could adversely affect ourresults of operation and free cash flow.
We are subject to various complex and evolving U.S. federal, state and local taxes. U.S. federal, state and local tax laws, policies, statutes,
rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us or our operators, in each case, possibly with retroactive effect, and may have an adverse effect on our business and future profitability. For example, several tax proposals have been set forth that would, if enacted, make significant changes to U.S. tax laws. Such proposals have included an increase in the U.S. federal income tax rate applicable to corporations (such as Brigham Minerals) from 21%, the imposition of a minimum tax on book income for certain corporations, the imposition of an excise tax on certain corporate stock repurchases that would be borne by the corporation repurchasing such stock, and the elimination of certain tax subsidies for fossil fuels.Congress could consider, and could include, some or all of these proposals in connection with tax reform that may be undertaken.It
is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws could adversely affect us or our operators’ operations on the properties in which we hold interests, which, in turn, could adversely affect our results of operation and free cash flow.
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Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our operators’ ability to conduct drilling activities.
In
the United States, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where our operators operate, our operators’ abilities to conduct or expand operations could be limited, or our operators could be forced to incur material additional costs. Moreover, our operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.
In addition, as a result of one or more settlements approved by the FWS, the agency was required to make a determination on the listing of numerous other species as endangered or threatened under
the ESA by the end of the FWS’ 2017 fiscal year. The FWS did not make that deadline; however, review is reportedly ongoing. The designation of previously unidentified endangered or threatened species-such as the dunes sagebrush lizard or greater sage grouse-could cause our operators’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. In June 2021, the FWS proposed to list two distinct population segments of the lesser prairie chicken, whose range extend to areas where we may hold mineral interests, under the ESA. The FWS and similar state agencies may also designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands, which may reduce the profitability of our interests to the extent they are associated with such designations.
Risks
Related to Our Financial and Debt Arrangements
Our derivative activities could result in financial losses and reduce earnings.
From time to time in the past we have used, and in the future we may use, derivative instruments for a portion of our future oil, natural gas and NGL production, including fixed price swaps, collars and basis swaps, to mitigate the risk and resulting impact of commodity price volatility. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract,
there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in oil, natural gas and NGL prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract. Further, our hedging activities are not likely to mitigate the entire exposure of our operations to commodity price volatility. We had no natural gas or oil derivative contracts
in place as of December 31, 2021 and 2020. For the year ended December 31, 2019, we recorded a loss on commodity derivative instruments, net of $(0.6) million. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.
Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.
The operating and financial restrictions and covenants in our revolving credit facility restrict, and any future financing agreements likely will restrict,
our ability to finance future operations or capital needs, engage, expand or pursue our business activities or pay dividends. Our revolving credit facility restricts, and any future financing agreements likely will restrict, our ability to, among other things:
•incur indebtedness;
•issue certain equity securities, including preferred equity securities;
•incur certain liens or permit them to exist;
•engage in certain fundamental changes, including mergers or consolidations;
•make certain investments, loans, advances, guarantees and acquisitions;
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•sell
or transfer assets;
•enter into sale and leaseback transactions;
•pay dividends to or redeem or repurchase shares from our stockholders;
•make certain payments of junior indebtedness;
•enter into transactions with our affiliates;
•enter into certain restrictive agreements; and
•enter into swap agreements and hedging arrangements.
Our revolving credit facility restricts our ability to pay dividends to our stockholders or to repurchase shares of our Class A common stock. We also are required under our revolving
credit facility to comply with, as of the most recently completed fiscal quarter, (i) a ratio of total net funded debt to consolidated EBITDA not to exceed 3.50 to 1.00, and (ii) a current ratio of not less than 1.00 to 1.00 and (iii) leverage (maximum 3.00x) and liquidity (minimum 10% of total revolving commitments) conditions with respect to the ability to pay dividends or distributions (other than permitted tax distributions). Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. If we violate any of the restrictions, covenants, ratios or tests in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to pay dividends to our stockholders will be inhibited and our
lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders can seek to foreclose on our assets.
The borrowings under our revolving credit facility expose us to interest rate risk.
We are exposed to interest rate risk associated with borrowings under the our revolving credit facility. Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted London Inter-Bank Offered Rate ("LIBOR") rate plus an applicable margin. The applicable
margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. If interest rates increase, so will our interest costs, which may have a material adverse effect on our business, financial conditions and results of operations.
In 2017, the U.K. Financial Conduct Authority announced that it will no longer persuade or compel banks to submit LIBOR rates after 2021. At the end of 2021, the ICE Benchmark Administration (the current LIBOR administrator) ceased publishing one-week and two-month
U.S. dollar LIBOR tenors and announced that it will cease publishing all remaining U.S. dollar LIBOR tenors in June 2023. The Federal Reserve Bank of New York, in conjunction with the Alternative Reference Rates Committee, has recommended that U.S. dollar LIBOR be replaced by the Secured Overnight Financing Rate (“SOFR”) SOFR is an overnight rate backed by U.S. Treasury, rather than a term rate, making it an inexact replacement for LIBOR. Whether or not SOFR or any other potential alternative reference rate attains market traction as a LIBOR replacement rate remains in question.
The current provisions in our revolving credit facility to change the benchmark rate for LIBOR loans from LIBOR to SOFR require calculations of a spread. Industry organizations are attempting to structure the spread calculation in a manner that
minimizes the possibility
of value transfer between borrowers, lenders and contractual counterparties as a result of the switch to
SOFR, but there can be no assurance that the calculated spread will be fair and accurate. We cannot predict the effect of any such changes, any establishment of alternative reference rates or any other reforms that may be required and/or implemented given the developments with respect to LIBOR. The potential effect of the cessation of LIBOR or our future borrowing costs for any borrowings under our revolving credit facility cannot yet be determined
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Our
debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
Our existing and future indebtedness could have important consequences to us, including:
•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us;
•covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
•our access to the capital markets
may be limited;
•our borrowing costs may increase;
•we will need a substantial portion of our free cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payment of dividends to our stockholders; and
•our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of
which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
Risks Related to Our Class A Common Stock
Brigham Minerals is a holding company. Brigham Minerals’ sole material asset is its equity interest in Brigham LLC and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other overhead expenses and pay any dividends on our Class A common stock.
Brigham
Minerals is a holding company and has no material assets other than its equity interest in Brigham LLC. Please see “Item 1—Business—Overview—Our Corporate Structure.” Brigham Minerals has no independent means of generating revenue. To the extent Brigham LLC has available cash, Brigham LLC is required to make (i) pro rata distributions to all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities and (ii) non-pro rata payments to Brigham Minerals in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Brigham LLC, we will cause Brigham LLC to make pro rata distributions to all of
its unitholders, including to Brigham Minerals, in an amount sufficient to allow us to fund dividends to our stockholders in accordance with our dividend policy, to the extent our Board of Directors declares such dividends. Therefore, although we have paid dividends to our stockholders in the past and expect to pay dividends on our Class A common stock in amounts determined from time to time by our Board of Directors in the future, our ability to do so may be limited to the extent Brigham LLC and its subsidiaries are limited in their ability to make these and other distributions to us, including due to the restrictions under our revolving credit facility. To the extent that we need funds and Brigham LLC or its subsidiaries are restricted from making such distributions under applicable law
or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.
The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company, we need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the New York Stock Exchange (the "NYSE"), with which we were not required to comply
as a private company. Complying with these requirements occupies a significant amount of time of our Board of Directors and management and significantly increases our costs and expenses. We
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are required to, among other things, institute a more comprehensive compliance function, comply with rules promulgated by the NYSE; prepare and distribute periodic public reports in compliance with federal securities laws; establish new internal policies, such as those relating to insider trading, and involve and retain to a greater degree outside counsel and accountants in the above activities.
Furthermore, we are required to comply with the provisions of
Section 404 of the Sarbanes Oxley Act, including the requirement to have our independent registered public accounting firm attest to the effectiveness of our internal controls. Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
In addition, being a public company subject to these rules and regulations makes it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage.
As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.
Effective internal
controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future, that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act, or that we will not identify material weaknesses related to our financial reporting. If one or more material weaknesses emerge related to financial reporting in the future, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our operating results and ability to meet our reporting obligations may be adversely affected and we may be subject to adverse regulatory consequences.
Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. See "Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls andProcedures.”
Our Sponsors have the ability to direct the voting of a substantial portion of the voting power of our common stock, and their interests may conflict with those of our other stockholders.
Holders of shares of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our
certificate of incorporation. As of December 31, 2021, our Sponsors beneficially own, on a combined basis, none of our outstanding shares of Class A common stock and approximately 45.5% of our shares of Class B common stock, representing 8.7% of our combined economic interest and voting power. As a result, this concentration of ownership allows our Sponsors to have significant influence over matters requiring stockholder approval, may deter hostile takeovers and may make it less likely that other holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of our Sponsors with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with
the interests of our other stockholders.
Furthermore, we are party to a stockholders’ agreement with our Sponsors. The stockholders’ agreement provides each of our Sponsors with the right to designate a certain number of nominees to our Board of Directors, subject to certain ownership requirements in our common stock. Our Sponsors’ concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.
Furthermore, while we believe that our Sponsor’s ownership interests in us provide them with an economic incentive to assist us to be successful, our Sponsors are not subject to any obligation to maintain their ownership interest in us. Our
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Sponsors
may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce their ownership interest in us, such as in the case of certain sales of our stock by our Sponsors in 2020 and 2021. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our business, financial condition and results of operations.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions
of responsibility with other entities (including Pine Brook-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, one of our directors (Mr. Stoneburner) is a Managing Director of Pine Brook, which is in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. In addition, Mr. Brigham, our executive chairman, is involved with certain other entities involved in the oil and gas industry, including Brigham Exploration Company, Atlas Permian Water, Atlas Permian Sand, Brigham Development, Anthem Ventures, Langford Energy Partners I, LLC and Brigham Oil & Gas, L.P., and Mr. Langford, one of our directors, is also involved with entities involved in the oil and gas industry, including Langford Energy Partners I, LLC and Brigham Oil & Gas, L.P. The existing positions held by these directors may give rise to fiduciary
or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Item 13—Certain Relationships and Related Transactions, and Director Independence.”
Our
Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Sponsors to benefit from corporate opportunities that might otherwise be available to us.
Our governing documents provide that our Sponsors and their affiliates (including portfolio investments of our Sponsors and their affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and that we renounce any interest or expectancy in any business opportunity that may be from time to time presented to our Sponsors or their respective affiliates. In particular, subject to the limitations of applicable law, our amended and restated certificate
of incorporation, among other things:
•permits our Sponsors and their affiliates and our directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
•provides that if our Sponsors or their affiliates or any director or officer of one of our affiliates, our Sponsors or their affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.
Our Sponsors or their affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may
not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our Sponsors and their affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Sponsors and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please see Exhibit 4.7 to this Annual Report on Form 10-K “Description of Brigham Minerals, Inc.’s Class A common stock.”
Each
of our Sponsors is an established participant in the oil and natural gas industry and has resources greater than ours, which may make it more difficult for us to compete with our Sponsors with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand,
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and our Sponsors, on the other hand, will be resolved in our favor. As a result, competition from our Sponsors and their affiliates could adversely impact our results of operations.
Our amended and restated certificate
of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their shares.
Our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and
liquidation preferences of such series. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:
•establish
advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders;
•provide that the authorized number of directors constituting our Board of Directors may be changed only by resolution of the Board of Directors;
•provide that all vacancies, including newly created directorships, may, except as otherwise required by law, the terms of the stockholders’ agreement or, if applicable, the rights of holders of a series of our preferred stock, be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum;
•provide
that our bylaws can be amended by the Board of Directors;
•provide that any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of our preferred stock with respect to such series;
•provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the
holders of not less than 66 2/3% of our then outstanding shares of common stock;
•provide that special meetings of our stockholders may only be called by our Board of Directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the Board of Directors serving at the time of such vote;
•provide for our Board of Directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms, other than directors that may be elected by holders of our preferred stock, if any;
•provide that the affirmative vote of the holders of not less than 66 2/3% in voting power of all then
outstanding shares of common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office, and such removal may only be for “cause”; and
•prohibit cumulative voting on all matters.
Furthermore, the terms of our amended and restated certificate of incorporation and amended and restated bylaws are subject to the terms of the stockholders’ agreement. See “Item 13—Certain Relationships and Related Transactions, and Director Independence.”
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Our
amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf,
(ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our amended and restated certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate
of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Our ability to pay dividends to our stockholders may be limited by our holding company
structure, contractual restrictions and regulatory requirements.
Brigham Minerals is a holding company and has no material assets other than its ownership of Brigham LLC Units, and Brigham Minerals does not have any independent means of generating revenue. To the extent Brigham LLC has available cash, Brigham LLC is required to make (i) pro rata distributions to all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow Brigham Minerals to satisfy its actual tax liabilities and (ii) non-pro rata payments to Brigham Minerals in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the
sole managing member of Brigham LLC, Brigham Minerals will cause Brigham LLC to make pro rata distributions to all of its unitholders, including to Brigham Minerals, in an amount sufficient to allow it to fund dividends to its stockholders in accordance with its dividend policy, to the extent its Board of Directors declares such dividends. Brigham LLC is a distinct legal entity and may be subject to legal or contractual restrictions that, under certain circumstances, may limit Brigham Minerals ability to obtain cash from it. If Brigham LLC is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect our free cash flow and financial position and our ability to fund any dividends.
Although we have paid dividends on our Class A common stock and expect to pay dividends on our Class A common stock in the future, our Board of Directors
will take into account general economic and business conditions, including our financial condition and results of operations, capital requirements, contractual restrictions, including restrictions and covenants contained in our debt agreements, business prospects and other factors that our Board of Directors considers relevant in determining whether, and in what amounts, to pay such dividends. In addition, our revolving credit facility limits the amount of distributions that Brigham LLC can make to us and the purposes for which distributions could be made. Accordingly, we may not be able to pay dividends even if our Board of Directors would otherwise deem it appropriate. See “Item 5—Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy,”“Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity” and Exhibit
4.7 to this Annual Report on Form 10-K, “Description of Brigham Minerals, Inc.’s Class A common stock.”
In certain circumstances, Brigham LLC will be required to make tax distributions to the Brigham Unit Holders, including Brigham Minerals, and such tax distributions may be substantial. To the extent Brigham Minerals receives tax distributions in excess of its actual tax liabilities and retains such excess cash, the Original Owners that hold Brigham LLC Units would benefit from such accumulated cash balances if they exercise their Redemption Right.
Pursuant to the Brigham LLC Agreement, to the extent Brigham LLC has available cash (taking into account existing and projected capital expenditures), Brigham LLC is required to make generally pro rata distributions (which we refer to as “tax
distributions”), to all its unitholders, including Brigham Minerals, in an amount generally intended to allow the Brigham Unit
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Holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain assumptions and conventions, provided that tax distributions will be made sufficient to allow Brigham Minerals to satisfy its actual tax liabilities. The amount of such tax distributions will be determined based on certain assumptions, including an assumed individual income tax rate, and will be calculated after taking into account other distributions (including other tax distributions) made by Brigham LLC. Because tax distributions will be made pro rata based
on ownership and due to, among other items, differences between the tax rates applicable to Brigham Minerals and the assumed individual income tax rate used in the calculation and requirements under the applicable tax rules that Brigham LLC’s net taxable income be allocated disproportionately to its unitholders in certain circumstances, tax distributions may significantly exceed the actual tax liability for many of the Brigham Unit Holders, including Brigham Minerals. If Brigham Minerals retains the excess cash it receives, the Original Owners that hold Brigham LLC Units would benefit from any value attributable to such accumulated cash balances upon their exercise of the Redemption Right. However, we expect to use such accumulated cash balances to pay dividends in respect of our Class A common stock or to take other steps to eliminate any material cash balances. In addition, the tax distributions Brigham LLC will be required to make may be substantial and may exceed
the tax liabilities that would be owed by a similarly situated corporate taxpayer. Funds used by Brigham LLC to satisfy its tax distribution obligations will not be available for reinvestment in our business, except to the extent Brigham Minerals uses the excess cash it receives to reinvest in Brigham LLC for additional units.
The U.S. federal income tax treatment of distributions on our Class A common stock to a holder will depend upon our tax attributes and the holder’s tax basis in our stock, which are not necessarily predictable and can change over time.
Distributions of cash or other property on our Class A common stock, if any, will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal
income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the holder’s tax basis in our Class A common stock and thereafter as capital gain from the sale or exchange of such common stock. Also, if any holder sells our Class A common stock, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A common stock.
To the extent that the amount of our distributions is treated as a non-taxable return of capital as described above, such distribution will reduce a holder’s tax basis in the Class A common stock. Consequently, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by
the holder upon the sale of the Class A common stock or subsequent distributions with respect to such stock. Additionally, with regard to U.S. corporate holders of our Class A shares, to the extent that a distribution on our Class A shares exceeds both our current and accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the corporate dividends-received deduction (to the extent it would otherwise be applicable to such holder) with respect to the gain resulting from such excess distribution.
Investors in our Class A common stock are encouraged to consult their tax advisors as to the tax consequences of receiving distributions on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.
Future sales of shares
of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Certain of our Original Owners own shares of our Class A common stock and, subject to certain limitations and exceptions, the Original Owners that hold Brigham LLC Units may require Brigham LLC to redeem their Brigham LLC Units for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions), and our Original Owners may sell any of such shares of Class A common stock. As of February 18, 2022, we had outstanding 48,360,253 shares of Class A common stock and 11,371,517 shares
of Class B common stock, representing approximately 19.0% of our total outstanding shares. The Sponsors are party to a registration rights agreement, which requires us to effect the registration of their shares in certain circumstances. See “Item1—Business—Overview—Our Corporate Structure” and “Item 13—Certain Relationships and Related Transactions, and Director Independence.”
We have previously filed a registration statement with the SEC on Form S-8 providing for the registration of 5,999,600 shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, shares registered under the registration statement on Form S-8 will be available for resale
immediately in the public market without restriction.
57
We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.
Our organizational structure confers certain benefits upon the Original Owners
that hold Brigham LLC Units that will not benefit the holders of our Class A common stock to the same extent as it will benefit those Original Owners.
Our organizational structure confers certain benefits upon the Original Owners that hold Brigham LLC Units that do not benefit the holders of our Class A common stock to the same extent as it will benefit those Original Owners. Brigham Minerals is a holding company and has no material assets other than its ownership of Brigham LLC Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock is subject to the ability of Brigham LLC to provide distributions to us. If Brigham LLC makes such distributions, the Original Owners that hold Brigham LLC Units will be entitled to receive equivalent distributions from Brigham LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately
distributed as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Brigham LLC to the Original Owners on a per unit basis. This and other aspects of our organizational structure may adversely impact the future trading market for our Class A common stock.
We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.
Our amended and restated certificate of incorporation authorizes our Board of Directors to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including
preferences over our Class A common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our Class A common stock.
If securities or industry analysts adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.
The
trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.
58
Item
1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is contained in "Item 1—Business" and is incorporated by reference here.
Item 3. Legal Proceedings
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 4. Mine Safety Disclosures
Not applicable.
59
PART II
Item
5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our Class A common stock began trading on the NYSE under the symbol “MNRL” on April 18, 2019. Prior to that, there was no public market for our Class A common stock.
There is no market for our Class B common stock. As of February 18, 2022, we had 42 holders of record of our Class B common stock. Each share of Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the stockholders generally. Please see "Item 1—Business—Overview—Our Corporate Structure."
Holders
of Record
On February 18, 2022, the closing price of our Class A common stock on the NYSE was $22.12 per share. As of February 18, 2022, we had approximately 52 holders of record of our Class A common stock. This number excludes owners for whom Class A common stock may be held in “street” name.
Dividend Policy
We paid our first quarterly cash dividend on our Class A common stock on August 29, 2019 to our Class A stockholders and have continued to pay quarterly cash dividends to date. The amount of our dividend has varied quarter to quarter from a high of $0.45 per share to a low of $0.14 per share. Our current dividend structure, implemented
during the third quarter of 2021, consists of a base dividend of $0.14 per share of Class A common stock plus a variable dividend. We expect to pay future dividends on our Class A common stock in amounts determined from time to time by our Board of Directors. However, the declaration and payment of any future dividends by us will be at the sole discretion of our Board of Directors, which may change our dividend policy at any time. Our Board of Directors will take into account:
•general economic and business conditions;
•our financial condition and operating results;
•our free cash flow and current anticipated cash needs;
•our capital requirements;
•legal,
tax, regulatory, and contractual (including under our revolving credit facility) restrictions and implications on the payment of dividends by us to our stockholders or by our subsidiaries (including Brigham LLC) to us; and
•such other factors as our Board of Directors may deem relevant.
We are a holding company and have no material assets other than our ownership of Brigham LLC Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock is subject to the ability of Brigham LLC to provide distributions to us. If Brigham LLC makes such distributions, the Original Owners will be entitled to receive equivalent distributions from Brigham LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed
as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Brigham LLC to the Original Owners on a per unit basis.
Assuming Brigham LLC makes distributions to us and the Original Owners in any given year, we expect to pay dividends in respect of our Class A common stock out of the portion, if any, of such distributions remaining after our payment of taxes and our expenses (any such portion, an “excess distribution”). However, because our Board of Directors may determine to pay or not pay dividends in respect of shares of our Class A common stock based on the factors described above, our holders of Class A common stock may not necessarily receive dividend distributions relating to excess distributions, even if Brigham LLC makes such distributions to us.
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Securities
Authorized for Issuance Under Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in "Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
Issuer Purchases of Equity Securities
We did not purchase any shares of our common stock during the three months ended December 31, 2021.
Performance Graph
The performance graph below compares the cumulative total returns of our Class A common stock over the period from April 18, 2019,
the date our Class A common stock began trading on the NYSE, through December 31, 2021 with the cumulative total returns for the same period for the S&P 500 index and S&P Oil and Gas Exploration & Production index. The cumulative stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our Class A common stock on April 18, 2019, and in the S&P 500 index and S&P Oil and Gas Exploration & Production index on the same date.
***$100 invested on 4/18/19 in stock or 3/31/19 in index, including reinvestment of dividends. Fiscal year ending December 31.
The
preceding performance graph and related information is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically request that such information be treated as soliciting material or specifically incorporate it by reference into a filing under the Securities Act or the Exchange Act.
Item 6. [Reserved]
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Item
7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Brigham Minerals, Inc. (the "Company,""we,""us," or "our") is the managing member of Brigham Minerals Holdings, LLC (“Brigham LLC”) and is responsible for all operational, management and administrative decisions related to Brigham LLC and its operating subsidiaries’ business. The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report.
The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties
that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved, probable and possible reserves, mineral acquisition capital, economic and competitive conditions, including those resulting from the ongoing COVID-19 pandemic, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Item 1A—Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable
law.
Overview
Brigham Minerals was formed to acquire and actively manage a portfolio of mineral and royalty interests in the core of what we view as the most active, highly economic, liquids-rich resource plays across the continental United States. Our primary business objective is to maximize risk-adjusted total return to our stockholders through (i) the growth of our free cash flow generated from our existing mineral portfolio and (ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. As of December 31, 2021, we owned 92,375 net royalty acres across 36 counties within the Delaware and Midland Basins in West Texas and New Mexico,
the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota.
Financial and Operational Overview:
•Our production volumes decreased 5%, to 9,040 Boe/d (70% liquids, 51% oil), for the year ended December 31, 2021 as compared to the prior year.
•Our mineral and royalty revenues composed of crude oil, natural gas and NGL sales increased 82%, to $156.7 million, for the year ended December 31, 2021 as compared to the prior year.
•Our net income for the year ended December 31, 2021 was $68.0 million. Our
net loss for the twelve months ended December 31, 2020 was $58.0 million. Adjusted Net Income for December 31, 2020 was $7.1 million, excluding an after-tax impairment to oil and gas properties of $65.1 million. Adjusted EBITDA and Adjusted EBITDA ex lease bonus increased 103% to $132.3 million, and 115% to $127.8 million, respectively, for the year ended December 31, 2021 as compared to the prior year. Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP financial measures. For a definition of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation to our most directly comparable measure calculated and presented in accordance with GAAP, please read "How We Evaluate Our Operations—Adjusted EBITDA and Adjusted EBITDA Ex Lease Bonus."
•As
of December 31, 2021, Brigham Minerals had a cash balance of $20.8 million and $137.0 million of capacity on our revolving credit facility, providing the Company with total liquidity of $157.8 million.
•On February 18, 2022, the Board of Directors of Brigham Minerals declared a dividend of $0.45 per share of Class A common stock payable on March 25, 2022 to stockholders of record at the close of business on March 18, 2022. This brings the total capital returned to stockholders related to financial results from fiscal year 2021 to $1.52 per share
62
2021
Acquisition
On December 15, 2021, Rearden Minerals, LLC, ("Rearden"), a wholly owned subsidiary of Brigham Minerals, acquired certain mineral and royalty assets in the DJ Basin from Principle Energy, LLC and Regal Petroleum LLC (D/B/A Regal Royalty, LLC), in each case, an unrelated seller (collectively, the “Sellers”). Upon closing of the acquisition, the Company and Rearden delivered to the Sellers $43.1 million of cash consideration, net of $1.7 million of customary closing adjustments and 2,180,128 shares of the Company’s Class A common stock. The combined cash consideration and acquisition shares issued totaled $89.4 million.
Market Environment
and COVID-19
The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, remains a global pandemic, however, with the gradual easing of COVID-19 lockdown restrictions globally, primarily due to the increase in accessibility of vaccines and demand for the commodities produced by the oil and natural gas industry have continued to improve. In addition, commodity prices have continued to improve substantially from historic lows in 2020 and the current outlook on commodity prices is generally favorable. However, the duration of COVID-19 pandemic and potential future impact to our business and industry continues to be unpredictable and dynamic.
In connection with the previously mentioned COVID-19 pandemic and resulting market and commodity price challenges experienced during 2020, we saw reduced levels of potential acquisition opportunities. With an
improvement in commodity prices in 2021 and into 2022, along with our financial strength, we believe we are well positioned to capture attractive opportunities that will generate stockholder value. Given that our capital allocation is within our control, we believe that the liquidity provided by our cash flow from operations, proceeds from portfolio rationalizations and borrowings under our revolving credit facility will provide us with sufficient capital to execute our current strategy.
Operational Update
Mineral and Royalty Interest Ownership Update
During the year ended December 31, 2021, the Company completed 62 ground game transactions and one marketed transaction
in the DJ Basin acquiring 6,090 net royalty acres (standardized to a 1/8th royalty interest) net of asset sales. The aggregate consideration paid for new assets in 2021 was approximately $150.3 million, including the equity consideration for the DJ Basin acquisition. The Company deployed approximately 35% of its mineral acquisition capital in 2021 to the Permian Basin (18% Delaware and 17% Midland), 1% to the Williston Basin and 64% to the DJ Basin. The acquired minerals are expected to deliver near-term production and cash flow growth with the addition of 231 gross DUCs (3.0 net DUCs) and 292 gross permits (2.2 net permits) to our inventory counts. As of December 31, 2021, the Company owned roughly 92,375 net royalty acres, encompassing 12,220 gross
(109.4 net) undeveloped horizontal locations, across 36 counties in what the Company views as the cores of the Delaware and Midland Basins in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota.
The table below summarizes the Company’s mineral and royalty interest ownership as of the dates indicated and changes in such ownership on an annual basis.
In 2021, the Company identified approximately 495 gross DUCs (2.2 net DUCs) converted to production, representing 69% of its gross DUC inventory (60% of its net DUCs) as of year-end 2020. 2021 conversions of gross wells by status are summarized in the graph below:
Drilling Activity
During 2021 the Company saw 656 gross (5.0 net) wells
spud on its acreage position as of December 31, 2021. 60% of gross (75% net) wells spud were in the Permian Basin, with 34% gross (35% net) wells spud in the Delaware Basin and 26% gross (40% net) wells spud in the Midland Basin:
64
DUC and Permit Inventory
The Company expects any near-term production growth will be driven by the continued
conversion of its DUC and permit inventory. Brigham’s DUC and permit inventory as of December 31, 2021 by basin is outlined in the table below:
Development
Inventory by Basin (1)
Delaware
Midland
SCOOP
STACK
DJ
Williston
Other
Total
Gross Inventory
DUCs
221
218
25
11
221
139
15
850
Permits
298
57
18
6
248
232
14
873
Net
Inventory
DUCs
2.3
2.2
0.1
0.1
2.4
0.3
0.1
7.4
Permits
2.5
0.2
0.1
0.1
2.1
0.5
—
5.5
(1)
Individual amounts may not total due to rounding.
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
•volumes of oil, natural gas and NGLs produced;
•number of rigs on location, permits, spuds, completions and wells turned-in-line;
•commodity prices; and
•Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus.
Volumes
of Oil, Natural Gas and NGLs Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various resource plays that comprise our portfolio of mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Number of Rigs on Location, Permits, Spuds, Completions and Wells Turned-In-Line
In order to track and assess the performance of our assets, we monitor and analyze the number of permits, rigs, spuds, completions and wells on production that are applicable to our mineral and royalty interests in an effort to evaluate near-term production growth from the various basins and resource plays that comprise our asset base.
Commodity Prices
Historically,
oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a historic, record low price of negative $36.98 per barrel in April 2020 to a high of $85.64 per barrel in October 2021. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. As of December 31, 2021, the posted price for oil was $75.33 per barrel and the Henry Hub spot market price of natural gas was $3.82 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically as well as the amount of capital they are willing to spend.
The prices we receive for oil, natural gas and NGLs vary by geographical area. The relative
prices of these products are determined by factors affecting global and regional supply and demand dynamics, such as economic and geopolitical conditions, the effects of health pandemics such as COVID-19, production levels, availability of transportation and storage, weather cycles and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.
65
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors
that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the
produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities
in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.
NGLs. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.
Oil and Gas Properties
Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated
properties, less related income tax effects (full cost ceiling limitation). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. A ceiling limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using an unweighted arithmetic average of oil prices ("SEC oil price") and natural gas prices ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, adjusted by area for energy content, transportation fees and regional price differentials, as required under the guidelines established by the SEC. As of December 31, 2021, 2020 and 2019, the SEC gas prices
were $66.56, $39.57, and $55.65, respectively, per barrel for oil, adjusted by area for energy content, transportation fees and regional price differentials, and the SEC gas prices were $3.64, $2.00, and $2.60, respectively, per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. As a result of the decline in the SEC oil prices and SEC gas prices during the twelve months ended December 31, 2020, and taking into consideration certain reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020, as a result of a slowdown in operator activity, the net book value of oil and natural gas properties exceeded the ceiling limitation as of September 30, 2020 and December 31,
2020, resulting in an impairment charge of $79.6 million to oil and gas properties, net during the year ended December 31, 2020. There were no impairment charges during the years ended December 31, 2021 and 2019.
A significant and prolonged decline in the SEC oil price or the SEC gas price could cause many of our operators to reduce substantially their development activities and capital expenditures, which could lead to additional impairment charges in the future and such impairment charges could be material. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require
revisions to estimates of total proved reserves which would impact the amount of any impairment charge. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development activities, production data, economics and other factors, we may be required to write down the carrying value of our properties in future periods. The risk that we will be required to recognize impairments of our oil, natural gas and NGL properties increases during sustained periods of low
66
commodity prices. In addition, impairments could occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.
If we incur impairment charges in the future, our results of operations for the periods in which such charges are taken may be materially and adversely affected.
Hedging
We may enter into certain derivative instruments to partially mitigate the impact of commodity price volatility on our cash flow generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars and other contractual arrangements. The impact of these derivative instruments could affect the amount of cash flows we ultimately realize. Historically, we have only entered into minimal fixed-price swap contracts. Under fixed-price swap contracts,
a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts may partially mitigate the effect of lower prices on our future revenue.
Our revolving credit facility allows us to hedge up to 85% of our reasonably anticipated projected production from our proved reserves of oil and natural gas, calculated separately, for up to 60 months in the future. We had no natural gas
or oil derivative contracts in place as of December 31, 2021 and 2020. For the year ended December 31, 2019, we recorded a loss on commodity derivative instruments, net of $0.6 million.
Non-GAAP Financial Measures
Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.
We
define Adjusted Net Income as Net Income (Loss) before impairment of oil and gas properties, after tax, and loss on extinguishment of debt, after tax. We define Adjusted EBITDA as Adjusted Net Income before depreciation, depletion and amortization, share based compensation expense, interest expense, gain or loss on derivative instruments and income tax expense, less other income. We define Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to eliminate the impacts of lease bonus and other revenues we receive due to the unpredictability of timing and magnitude of the revenue.
Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus do not represent and should not be considered alternatives to, or more meaningful than, net income or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Adjusted Net Income, Adjusted EBITDA and Adjusted
EBITDA ex lease bonus have important limitations as analytical tools because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our computation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus may differ from computations of similarly titled measures of other companies.
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The following table presents a reconciliation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus to the most directly comparable GAAP financial measure for the periods indicated.
Years
Ended December 31,
(In Thousands)
2021
2020
2019
Reconciliation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus to Net Income (Loss):
Net Income (Loss)
$
68,026
$
(57,994)
$
21,639
Add:
Impairment
of oil and gas properties, after tax (1)
—
65,132
—
Loss on extinguishment of debt, after tax (2)
—
—
6,134
Adjusted Net Income
$
68,026
$
7,138
$
27,773
Add:
Depreciation,
depletion, and amortization
36,677
48,238
30,940
Share-based compensation expense
9,703
7,529
10,049
Interest expense, net
1,701
890
5,609
Loss
on derivative instruments, net
—
—
568
Income
tax expense
16,253
1,675
3,437
Less:
Other
income, net
53
428
169
Adjusted EBITDA
$
132,307
$
65,042
$
78,207
Less:
Lease
bonus and other revenues
4,518
5,478
3,629
Adjusted EBITDA ex lease bonus
$
127,789
$
59,564
$
74,578
(1) Tax effect
of $14.4 million tax benefit for the year ended December 31, 2020.
(2) Tax effect of $0.8 million tax benefit for the year ended December 31, 2019.
Sources of Our Revenues
Our revenues are primarily derived from the mineral and royalty payments we receive from our operators based on the sale of oil, natural gas and NGLs produced from our properties, as well as from lease bonus payments. Mineral and royalty revenues may vary significantly from period to period as a result of changes in volumes of production sold by our operators, production mix and commodity prices. Lease bonus and other revenues vary from period to period as a result of leasing activity on our mineral
interests.
The following table presents the breakdown of our revenues for the following periods:
Years Ended December 31,
Royalty revenues
2021
2020
2019
Oil
sales
69
%
74
%
81
%
Natural gas sales
17
%
11
%
9
%
NGL sales
11
%
9
%
6
%
Total
royalty revenues
97
%
94
%
96
%
Lease bonus and other revenues
3
%
6
%
4
%
Total revenues
100
%
100
%
100
%
Principle
Components of Our Cost Structure
The following is a description of the principle components of our cost structure. However, as an owner of mineral and royalty interests, we are not obligated to fund drilling and completion capital expenditures to bring a horizontal well on line, lease operating expenses to produce our oil, natural gas and NGLs nor the plugging and abandonment costs at the end of a well’s economic life. All the aforementioned costs are borne entirely by the exploration and production companies that have leased our mineral and royalty interests.
68
Gathering, Transportation and Marketing Expenses
Gathering, transportation and
marketing expenses include the costs to process and transport our production to applicable sales points. Generally, the terms of the lease governing the development of our properties permits the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.
Severance and Ad Valorem Taxes
Severance taxes are paid on sold oil, natural gas or NGLs based on either a percentage of revenues from production sold or the number of units of production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues, which is driven by our production volumes and prices received for our oil, natural gas and NGLs. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes
are generally based on the state or local government’s appraisal of the value of our oil, natural gas and NGL properties, which also trend with anticipated production, as well as oil, natural gas and NGL prices. Rates, methods of calculating property values and timing of payments vary across the different counties in which we own mineral and royalty interests.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire evaluated oil and natural gas properties. We use the full cost method of accounting, and, as such, all acquisition-related costs to acquire evaluated properties are capitalized and amortized in aggregate based on the estimated economic productive lives of our properties. Depletion is the expense recorded based on the cost basis of our properties and
the volume of hydrocarbons extracted during each respective period, calculated on a units-of-production basis. Estimates of proved reserves are a major component of our calculation of depletion. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports. The year-end reserve reports are audited by CG&A.
General and Administrative
General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our staff, share-based compensation expense, costs of maintaining our headquarters, costs of managing our properties, annual and quarterly reports to stockholders, tax return preparation, independent and internal auditor fees, investor relations activities, incremental director and officer liability insurance costs, independent director compensation, other fees for professional services
and legal compliance.
Interest Expense
We finance a portion of our working capital requirements and acquisitions with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest and loan commitment fees paid to the lenders under our debt arrangements (currently, our revolving credit facility) and amortization of debt issuance costs in interest expense.
Income Tax Expense
Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of up to 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A
portion of our mineral and royalty interests are located in Texas basins.
The following table provides the components of our revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes:
Years Ended December 31,
(Dollars
in Thousands, Except for Realized Prices)
2021
2020
Variance
Production
Oil (MBbls)
1,677
1,823
(146)
(8)
%
Natural
gas (MMcf)
5,886
5,809
77
1
%
NGLs (MBbls)
642
680
(38)
(6)
%
Equivalents
(MBoe)
3,300
3,471
(171)
(5)
%
Equivalents per day (Boe/d)
9,040
9,483
(443)
(5)
%
Revenues
Oil
sales
$
110,791
$
67,909
$
42,882
63
%
Natural gas sales
27,070
10,443
16,627
159
%
NGL
sales
18,838
7,893
10,945
139
%
Total mineral and royalty revenues
$
156,699
$
86,245
$
70,454
82
%
Lease
bonus and other revenue
4,518
5,478
(960)
(18)
%
Total revenue
$
161,217
$
91,723
$
69,494
76
%
Realized
prices, without derivatives:
Oil ($/Bbl)
$
66.08
$
37.26
$
28.82
77
%
Natural gas ($/Mcf)
4.60
1.80
2.80
156
%
NGLs
($/Bbl)
29.35
11.61
17.74
153
%
Equivalents ($/Boe)
$
47.49
$
24.85
$
22.64
91
%
Operating
expenses
Gathering, transportation and marketing
$
6,818
$
6,985
$
(167)
(2)
%
Severance and
ad valorem taxes
9,320
5,606
3,714
66
%
Depreciation, depletion, and amortization
36,677
48,238
(11,561)
(24)
%
Impairment
of oil and gas properties
—
79,569
(79,569)
***
General and administrative (before share-based compensation)
12,772
14,090
(1,318)
(9)
%
Total
operating expenses (before share-based compensation)
$
65,587
$
154,488
$
(88,901)
(58)
%
General and administrative, share-based compensation
9,703
7,529
2,174
29
%
Total
operating expenses
$
75,290
$
162,017
$
(86,727)
(54)
%
Other expense
Interest
expense, net
$
(1,701)
$
(890)
$
(811)
91
%
Unit Expenses ($/Boe)
Gathering,
transportation and marketing
$
2.07
$
2.01
$
0.06
3
%
Severance and ad valorem taxes
2.82
1.62
1.20
74
%
Depreciation,
depletion, and amortization
11.12
13.90
(2.78)
(20)
%
General and administrative (before share-based compensation)
3.87
4.06
(0.19)
(5)
%
General
and administrative, share-based compensation
2.94
2.17
0.77
35
%
Interest expense, net
0.52
0.26
0.26
100
%
*** A
percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300.
70
Revenues
Total revenues for the year ended December 31, 2021 increased by 76%, or $69.5 million, compared to the year ended December 31, 2020. The increase was attributable to a $70.5 million increase in mineral and royalty revenues during the period, partially offset by a $1.0 million
decrease in lease bonus revenue. The increase in mineral and royalty revenues was primarily the result of an increase in realized commodity prices of 91% resulting in a $74.7 million increase in mineral and royalty revenues. A decrease in drilling and completion activity on our mineral and royalty interests during the year ended December 31, 2021 compared to the year ended December 31, 2020, partially offset by acquisitions of proved developed producing reserves resulted in a 5% decrease in production volumes to 9,040 Boe/d and a corresponding decrease in mineral and royalty revenues of $4.2 million. The decrease in production volumes was primarily due to the reduction in drilling activity which started during the second quarter of 2020 associated with COVID-19 and the OPEC + production dispute as well as Winter Storm Uri's February 2021 production curtailments.
Oil
revenues for the year ended December 31, 2021 increased by 63%, or $42.9 million, compared to the year ended December 31, 2020. The increase in oil revenues was primarily attributable to the 77% increase in realized oil price to $66.08 per barrel resulting in an increase in revenue of $48.3 million. An 8% decrease in oil production volumes to 4,594 barrels per day resulted in a $5.4 million decrease in oil revenues, net of $0.5 million in oil revenues from the DJ Acquisition.
Natural gas revenues for the year ended December 31, 2021 increased by 159%, or $16.6 million compared to the year ended December 31, 2020. The increase in natural gas revenues was primarily attributable to a 156% increase in realized natural gas price to
$4.60 per Mcf resulting in an increase in revenue of $16.4 million as well as a $0.2 million increase of natural gas revenues from the DJ Acquisition.
NGL revenues for the year ended December 31, 2021 increased by 139%, or $10.9 million compared to the year ended December 31, 2020. The increase in NGL revenues was primarily attributable to the 153% increase in NGL prices to $29.35 per barrel resulting in an increase in revenue of $11.4 million. A 6% decrease in NGL volumes to 1,759 Boe/d resulted in a $0.4 million decrease in NGL sales, net of NGL revenues from the DJ Acquisition of $0.2 million, was primarily attributable to a decrease in drilling and completion activities on our properties in the Permian Basin, the Anadarko Basin and the Williston Basin.
Lease Bonus and Other
Revenues
When we lease our minerals, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenues for the year ended December 31, 2021 decreased by 18%, or $1.0 million compared to the year ended December 31, 2020. The decrease in revenues from lease bonus payments is primarily attributable to a $2.2 million decrease in leasing activity in the Permian Basin partially offset by the $0.8 million and $0.4 million increases in leasing activity in the DJ and Anadarko Basins, respectively. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.
Operating and other expenses
Gathering, transportation, and marketing expenses. For the year
ended December 31, 2021 decreased by 2%, or $0.2 million, as compared to the year ended December 31, 2020, which was largely driven by the 5% decrease in our production volumes.
Severance and ad valorem taxes. For the year ended December 31, 2021 increased by 66%, or $3.7 million, as compared to the year ended December 31, 2020, primarily due to the 82% increase in mineral and royalty revenues which was primarily due to an increase in realized commodity prices of 91%, partially offset by a 5% decrease in production volumes.
Depreciation, depletion and amortization. For the year ended December 31,
2021 decreased by 24%, or $11.6 million, compared to the year ended December 31, 2020, which was primarily due to a decrease in depletion expense of $10.9 million. Lower production volumes decreased our depletion expense by $2.3 million, and a lower depletion rate decreased our depletion expense by $8.6 million. The depletion rate was $11.05 per Boe and $13.63 per Boe for the years ended December 31, 2021 and 2020, respectively. The decrease in the depletion rate was a result of the impairment charge of $79.6 million for the year ended December 31, 2020, resulting in lower depletable cost (or amortizable base) in the calculation of the depletion rate for the year ended December 31, 2021. In addition, an increase in total
proved reserves of 43% from December 31, 2020 to December 31, 2021, which was primarily a result of acquisitions and 68% higher SEC oil price and 82% higher SEC gas prices, contributed to the decrease in depletion rate. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.
71
Impairment. In determining the full cost ceiling impairment at December 31, 2021, we estimated the PV-10 of our total proved oil and natural gas reserves using the SEC oil price and the SEC gas price of $66.56 per Bbl and $3.64 per MMBtu, respectively.
There was no impairment for the year ended December 31, 2021. As of September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and gas properties exceeded the full cost ceiling limitation primarily due to the decline in oil and gas prices and reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020 as a result of a slowdown in operator activity. As a result, we recorded impairments of our oil and gas properties, net of $79.6 million for the year ended December 31, 2020. In determining the full cost ceiling impairment at December 31, 2020, we estimated the PV-10 of our total proved
oil and natural gas reserves using the SEC oil price and the SEC gas price of $39.57 per Bbl and $2.00 per MMBtu, respectively, which is a decrease of 29% and 23%, respectively, from the December 31, 2019 SEC oil price and SEC gas price of $55.65 per Bbl and $2.60 per MMBtu, respectively.
General and administrative before share-based compensation. For the year ended December 31, 2021 decreased by 9% or $1.3 million, compared to the year ended December 31, 2020. Decreases to G&A expense are a result of a $2.0 million decrease in incremental legal, professional, and tax fees, partly due to the absence of equity offerings in 2021, partially offset by $0.2 million increase in rent expense and $0.3 million increase in salary and compensation expense.
Share-based
compensation. For the year ended December 31, 2021 share-based compensation expense was $9.7 million, net of $3.6 million of share-based compensation expense capitalized to unevaluated property and $4.4 million of share-based compensation expense capitalized to evaluated property. Share-based compensation expense for the year ended December 31, 2020 was $7.5 million, net of $3.0 million of share-based compensation expense capitalized to unevaluated property and $3.1 million of share-based compensation cost capitalized to evaluated property. The increase in share-based compensation expense of $2.2 million was primarily due to additional RSU and PSU grants made during the year ended December 31, 2021. See table below and "Note 10—Share-Based Compensation" to the consolidated financial statements
of Brigham Minerals included elsewhere in this Annual Report for further discussion.
Years Ended December 31,
(In Thousands)
2021
2020
Variance
Incentive
Units
$
712
$
712
$
—
RSAs
623
1,254
(631)
RSUs
10,128
7,390
2,738
PSUs
6,288
4,259
2,029
Capitalized
share-based compensation
(8,048)
(6,086)
(1,962)
Total share-based compensation expense
$
9,703
$
7,529
$
2,174
Interest expense, net for the year
ended December 31, 2021 increased by 91%, or $0.8 million, compared to the year ended December 31, 2020 due to higher average outstanding borrowings and higher average interest rates. See table below and “Note 6—Long-Term Debt” and “Note 1—Business and Basis of Presentation” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion of this transaction.
The following table provides the components of our revenues and expenses for the periods
indicated, as well as each period’s respective average prices and production volumes:
Years Ended December 31,
(Dollars in Thousands,
Except for Realized Prices)
2020
2019
Variance
Production
Oil (MBbls)
1,823
1,515
308
20
%
Natural
gas (MMcf)
5,809
4,707
1,102
23
%
NGLs (MBbls)
680
407
273
67
%
Equivalents
(MBoe)
3,471
2,706
765
28
%
Equivalents per day (Boe/d)
9,483
7,414
2,069
28
%
Revenues
Oil
sales
$
67,909
$
82,048
$
(14,139)
(17)
%
Natural gas sales
10,443
9,724
719
7
%
NGL
sales
7,893
6,114
1,779
29
%
Total mineral and royalty revenues
$
86,245
$
97,886
$
(11,641)
(12)
%
Lease
bonus and other revenues
5,478
3,629
1,849
51
%
Total revenue
$
91,723
$
101,515
$
(9,792)
(10)
%
Realized
prices, without derivatives:
Oil ($/Bbl)
$
37.26
$
54.16
$
(16.90)
(31)
%
Natural gas ($/Mcf)
1.80
2.07
(0.27)
(13)
%
NGLs
($/Bbl)
11.61
15.03
(3.42)
(23)
%
Equivalents ($/Boe)
$
24.85
$
36.17
$
(11.32)
(31)
%
Realized
prices, with derivatives(1):
Oil ($/Bbl)
$
37.26
$
54.47
$
(17.21)
(32)
%
Equivalents ($/Boe)
24.85
36.35
(11.50)
(32)
%
Operating
expenses
Gathering, transportation and marketing
$
6,985
$
4,985
$
2,000
40
%
Severance and
ad valorem taxes
5,606
6,409
(803)
(13)
%
Depreciation, depletion, and amortization
48,238
30,940
17,298
56
%
Impairment
of oil and gas properties
79,569
—
79,569
***
General and administrative (before share-based compensation)
14,090
11,914
2,176
18
%
Total
operating expenses (before share-based compensation)
$
154,488
$
54,248
$
100,240
185
%
General and administrative, share-based compensation
7,529
10,049
(2,520)
(25)
%
Total
operating expenses
$
162,017
$
64,297
$
97,720
152
%
Other income (expense)
(Loss) gain on
derivative instruments, net
$
—
$
(568)
$
568
(100)
%
Loss on extinguishment of debt
—
(6,892)
6,892
(100)
%
Interest
expense, net
(890)
(5,609)
4,719
(84)
%
Total other income (expense), net
$
(890)
$
(13,069)
$
12,179
(93)
%
Unit
Expenses ($/Boe)
Gathering, transportation and marketing
$
2.01
$
1.84
$
0.17
9
%
Severance
and ad valorem taxes
1.62
2.37
(0.75)
(32)
%
Depreciation, depletion, and amortization
13.90
11.43
2.47
22
%
General
and administrative (before share-based compensation)
4.06
4.40
(0.34)
(8)
%
General and administrative, share-based compensation
2.17
3.71
(1.54)
(42)
%
Interest
expense, net
0.26
2.07
(1.81)
(87)
%
(1) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.
*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change
greater than 300.
73
Revenues
Total revenues for the year ended December 31, 2020 decreased by 10%, or $9.8 million, compared to the year ended December 31, 2019. The decrease was attributable to a $11.6 million decrease in mineral and royalty revenues during the period, partially offset by a $1.8 million increase in lease bonus revenue. The decrease in mineral and royalty revenues was primarily the result of a decrease in realized commodity prices of 31% resulting in a $39.3 million decrease in mineral and royalty revenues.
This was partially offset by an increase in drilling and completion activity on our mineral and royalty interests, and to a lesser degree by acquisitions of proved developed producing reserves, which resulted in a 28% increase in production volumes to 9,483 Boe/d and a corresponding increase in mineral and royalty revenues of $27.7 million.
Oil revenues for the year ended December 31, 2020 decreased by 17%, or $14.1 million, compared to the year ended December 31, 2019. The decrease in oil revenues was primarily attributable to the 31% decrease in realized oil price to $37.26 per barrel resulting in a decrease in revenue of $30.8 million. This was partially offset by a 20% increase in oil production volumes to 4,980 barrels per day resulting in a $16.7 million increase in oil revenues. The increase in oil production volumes
for the period was primarily attributable to increased drilling and completion activity on our properties in the Permian Basin, and to a lesser degree by acquisitions of proved developed producing reserves.
Natural gas revenues for the year ended December 31, 2020 increased by 7%, or $0.7 million compared to the year ended December 31, 2019. The increase in natural gas revenues was primarily attributable to the 23% increase in natural gas production volume to 15,871 Mcf/d resulting in a $2.3 million increase in natural gas sales. The increase in natural gas production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in the Permian Basin, and to a lesser degree by acquisitions of proved developed producing reserves. This was partially offset by a 13% decrease in
realized natural gas price to $1.80 per Mcf resulting in a decrease in revenue of $1.6 million.
NGL revenues for the year ended December 31, 2020 increased by 29%, or $1.8 million compared to the year ended December 31, 2019. The increase in NGL revenues was primarily attributable to the 67% increase in NGL volumes to 1,858 Boe/d resulting in a $4.1 million increase in NGL sales was primarily attributable to increased drilling and completion activities on our properties in the Permian Basin, and to a lesser degree by acquisitions of proved developed producing reserves. This was partially offset by a 23% decrease in NGL prices to $11.61 per barrel resulting in a decrease in revenue of $2.3 million.
Lease bonus revenues for the year ended December 31,
2020 increased by 51%, or $1.8 million compared to the year ended December 31, 2019. The increase was primarily attributable to an increase in leasing activity on our interests in Texas, partially offset by a decrease in leasing activity in Colorado and Oklahoma. Other revenues include payments for right-of-way and surface damages and were not a significant portion of the overall amount.
Operating and other expenses
Gathering, transportation, and marketing expenses for the year ended December 31, 2020 increased by 40%, or $2 million, as compared to the year ended December 31, 2019, which was largely driven by the 28% increase in our production volumes as well as an increase in gathering, transportation and marketing
rates.
Severance and ad valorem taxes for the year ended December 31, 2020 decreased by 13%, or $0.8 million, as compared to the year ended December 31, 2019, primarily due to the 12% decrease in mineral and royalty revenues.
DD&A expense for the year ended December 31, 2020 increased by 56%, or $17.3 million, compared to the year ended December 31, 2019, which was primarily due to an increase in depletion expense of $17.0 million. Higher production volumes increased our depletion expense by $8.6 million, and a higher depletion rate increased our depletion expense by $8.4 million. The depletion rate was $13.63 per Boe and $11.22 per Boe for the years ended December 31,
2020 and 2019, respectively. The increase in the depletion rate was a result of recent acquisition efforts focused on largely de-risked acreage with an increased likelihood of near-term production and development, as well as reclassification of proved undeveloped reserves to probable and possible reserves due to changes in assumptions of the development timing as a result of reduced activity by our operators. We adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.
As of September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and gas properties exceeded the full cost ceiling limitation primarily due to the decline in oil and gas prices and reclassification of proved undeveloped reserves to probable and
possible reserves during the three months ended December 31, 2020 as a result of a slowdown in operator activity. As a result, we recorded impairments of our oil and gas properties, net of $79.6 million for the year ended December 31, 2020. In determining the full cost ceiling impairment at December 31, 2020, we estimated the PV-10 of our total proved oil and natural gas reserves using the SEC oil price and the SEC gas price of $39.57 per Bbl and $2.00 per MMBtu, respectively, which is a decrease of 29% and 23%, respectively, from the December 31, 2019 SEC oil price and SEC gas price of $55.65 per Bbl and $2.60 per MMBtu, respectively. No impairment charge was recorded for the year ended December 31, 2019.
74
G&A
before share-based compensation for the year ended December 31, 2020 increased by 18%, or $2.2 million, compared to the year ended December 31, 2019. Increases to G&A expense are a result of: (i) $0.7 million in incremental legal, professional, audit, and tax fees as a result of the Company's June 2020 Secondary Offering and September 2020 Secondary Offering, (ii) $0.5 million in additional rent expense, (iii) $0.4 million of incremental directors and officers insurance expenses, and (iv) $0.3 million of additional salaries due to an increase in headcount.
Share-based compensation expense for the year ended December 31, 2020 decreased by 25%, or $2.5 million compared to the year ended December 31,
2019. The decrease in share-based compensation expense was due to a cumulative effect adjustment of $5.2 million pertaining to the period from the grant date to the IPO, which consists of a $2.0 million cumulative effect adjustment related to the estimated fair value of the Incentive Units and a $3.2 million cumulative effect adjustment related to the estimated fair value of the RSAs, partially offset by share-based compensation expense related to awards granted during the year ended December 31, 2020. Brigham Minerals capitalizes a portion of the share-based compensation expense incurred after the IPO. See table below and "Note 10—Share-Based Compensation" to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion.
Years
Ended December 31,
(In Thousands)
2020
2019
Variance
Incentive Units
$
712
$
2,904
$
(2,192)
RSAs
1,254
3,972
(2,718)
RSUs
7,390
4,630
2,760
PSUs
4,259
2,361
1,898
Capitalized
share-based compensation
(6,086)
(3,818)
(2,268)
Total share-based compensation expense
$
7,529
$
10,049
$
(2,520)
Interest expense, net for the year
ended December 31, 2020 decreased by 84%, or $4.7 million, compared to the year ended December 31, 2019 due to lower average outstanding borrowings and lower average interest rates. For the year ended December 31, 2020, our weighted average debt outstanding on our revolving credit facility was $2.8 million compared to our weighted average debt outstanding on our credit facilities of $55.0 million for the year ended December 31, 2019. Our weighted average interest was 1.91% and 7.29% for the years ended December 31, 2020 and 2019, respectively. In December 2019, a portion of the net proceeds received from the December 2019 Offering were used to fully repay the outstanding borrowings
under our revolving credit facility. See table below and “Note 1—Business and Basis of Presentation” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion of this transaction.
Years Ended December 31,
(In
Thousands, Except for Interest Rate)
2020
2019
Variance
Interest expense - credit facilities
$
55
$
5,828
$
(5,773)
Commitment
fees
600
356
244
Amortization of loan closing costs
605
433
172
Interest income
(370)
(1,008)
638
Total
interest expense, net
$
890
$
5,609
$
(4,719)
Total weighted average interest rate
1.91
%
7.29
%
Total
weighted average debt balance
$
2,814
$
55,000
Loss on extinguishment of debt. We recognized a loss on extinguishment of debt of approximately $6.9 million for the year ended December 31, 2019. The loss on extinguishment of debt consisted of a $4.0 million write-off of capitalized debt issuance costs, a $2.1 million prepayment fee and legal fees of $0.8 million.
Loss on derivative instruments, net. Brigham Minerals did not have any derivative
contracts in place as of December 31, 2020 and 2019. Prior to December 31, 2019, we had certain oil swap contracts based on the NYMEX futures index. For the year ended December 31, 2019, we recognized a loss on derivative instruments, net of $0.6 million, which is attributable to oil derivative instruments. We realized $0.5 million of gains on our settled derivative instruments during the year ended December 31, 2019.
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Factors
Affecting the Comparability of Our Results of Operations to Our Historical Results of Operations
Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.
Corporate Reorganization and Transactions
The historical consolidated financial statements included in this Annual Report for periods on or before April 23, 2019 are based on the financial statements of Brigham Resourcse, LLC, our predecessor, and Brigham Minerals prior to our corporate reorganization consummated in connection with our IPO. As a result, such historical consolidated financial data may not give you an accurate indication of what our actual results would have been if the corporate reorganization had been completed
at the beginning of the periods presented or of what our future results of operations are likely to be.
In April 2019, Brigham Minerals completed the IPO of 16,675,000 shares of Class A common stock at a price to the public of $18.00 per share. As a result of the IPO, Brigham Minerals became a holding company whose sole material asset consisted of a 43.3% interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to wholly own the Minerals Subsidiaries, which own all of Brigham Resources’ operating assets. In connection with the IPO, Brigham Minerals became the sole managing member of Brigham LLC and is responsible for all operational, management and administrative decisions relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its wholly-owned subsidiary, Brigham
Resources.
On December 16, 2019, Brigham Minerals completed an offering of 12,650,000 shares of its Class A common stock (the "December 2019 Offering"), including 6,000,000 shares issued and sold by Brigham Minerals and an aggregate of 6,650,000 shares sold by certain stockholders of the Company, of which 5,496,813 represents shares issued upon redemption of an equivalent number of their Brigham LLC units, at a price to the public of $18.10 per share.
On June 12, 2020, Brigham Minerals completed an offering of 6,600,000 shares of its Class A common stock (the "June 2020 Secondary Offering"), all of which were sold by certain stockholders of the
Company (the “June 2020 Selling Stockholders”), and 4,872,669 of which represented shares issued upon redemption of an equivalent number of the June 2020 Selling Stockholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $13.75 per share. Brigham Minerals did not sell any shares of its common stock in the June 2020 Secondary Offering and did not receive any proceeds pursuant to the June 2020 Secondary Offering.
On September 15, 2020, Brigham Minerals completed an offering of 5,021,140 shares of its Class A common stock, including 654,931 shares issued pursuant to the option granted to the underwriter to purchase additional shares to cover over-allotments (the "September 2020 Secondary Offering"), all of which were sold by certain stockholders of the
Company (the "September 2020 Selling Stockholders"), and 3,062,011 of which represented shares issued upon redemption of an equivalent number of the September 2020 Selling Stockholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $8.20 per share. Brigham Minerals did not sell any shares of its Class A common stock in the September 2020 Secondary Offering and did not receive any proceeds pursuant to the September 2020 Secondary Offering. In addition, in connection with the September 2020 Secondary Offering, Brigham Minerals repurchased 436,630 shares of its Class A common stock from the September 2020 Selling Stockholders in a privately negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from the September 2020 Selling Stockholders in the September 2020 Secondary Offering (and Brigham LLC redeemed a corresponding
number of Brigham LLC Units held by Brigham Minerals). The repurchased shares are presented in the Company's consolidated balance sheet as Treasury Stock, at cost.
As of December 31, 2021, Brigham Minerals owned a 81.0% interest in Brigham LLC and the Original Owners owned 19.0% of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Company's Original Owners, collectively owned 8.7% of the outstanding voting stock of Brigham Minerals as of December 31, 2021. Yorktown ceased to be an affiliate of the
Company on January 20, 2022 in connection with the resignation of W. Howard Keenan, Jr. from the Board of Directors.
The corporate reorganization that was completed contemporaneously with the closing of the IPO provided a mechanism by which the Brigham LLC Units to be allocated amongst the Original Owners, including the holders of our management incentive units, was determined. As a result, the satisfaction of all conditions relating to the vesting of certain management incentive units held in Brigham Equity Holdings, LLC (“Brigham Equity Holdings”) by our management and employees became probable. Accordingly, at IPO, we recognized a cumulative effect adjustment to share-based compensation expense of approximately $2.0 million pertaining to the period from the grant date through the IPO date, related to the estimated fair value
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of
the Incentive Units (as defined in “Note 10—Share-Based Compensation—LLC Incentive Units” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report) at grant, all of which was non-cash.
Income Taxes
Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Our predecessor was treated as a flow-through entity, and is currently treated as a disregarded entity, for U.S. federal income tax purposes and, as such, is generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income is passed through to its members, including Brigham Minerals. Accordingly, the financial data of our predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas).
Capital
Requirements and Sources of Liquidity
Our current primary sources of liquidity are cash flows from operations, asset sales, borrowings under our revolving credit facility and proceeds from any primary issuances of equity securities. Future sources of liquidity may also include other credit facilities or increases to our current revolving credit facility we may enter into in the future and additional issuances of debt or equity securities. Even with the gradual easing of lockdown restrictions globally and the increase in commodities prices in 2021, COVID-19 remains a global pandemic. As a result, our revenues and cash flows from operations may be negatively impacted and we may not have access to capital markets on terms favorable to us or at all.
Our primary uses of capital are for the payment of dividends to our stockholders for investing in our business, specifically the acquisition
of additional mineral and royalty interests and for repaying amounts borrowed under our revolving credit facility. As discussed above, COVID-19 remains a global pandemic. Our cash flows from operations may be negatively impacted, and as a result, the dividend amount we are able to pay our stockholders may be negatively impacted.
As a mineral and royalty interest owner, we incur the initial cost to acquire our interests, but thereafter do not incur any development capital expenditures or lease operating expenses, which are entirely borne by the operator. As a result, the vast majority of our capital expenditures are related to our acquisition of additional mineral and royalty interests. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operations,
investing and financing activities and our ability to assimilate acquisitions. For the year ended December 31, 2021, we deployed approximately $158.4 million for acquisition-related capital expenditures, inclusive of a $8.0 million capitalized share-based compensation expense and $46.3 million of equity. In addition to acquisitions, we have certain contractual long-term capital requirements associated with the our office lease and with our revolving credit facility. See "Note 8 – Leases” and "Note 7 – Long-Term Debt” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report. We periodically assess changes in current and projected free cash flows, acquisition and divestiture activities, debt requirements and other factors to determine the effects on our liquidity. Based upon our current oil, natural gas and NGL price expectations for the year ended December
31, 2022, we believe that our retained cash flow from operations, lease bonus, portfolio optimization activities and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through additional borrowings, joint venture partnerships, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us.
Our working capital, which we define as
current assets minus current liabilities, totaled $33.1 million as of December 31, 2021, as compared to $22.6 million at December 31, 2020. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant.
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When new wells are turned to sales, our collection of receivables has lagged approximately six months from initial production as operators complete the division order process, at which point we are paid in arrears and then kept current. Our cash and cash equivalents balance totaled $20.8 million and $9.1 million at December 31,
2021 and December 31, 2020, respectively. The increase in cash and cash equivalents was primarily due to increase in cash provided by operating activities, borrowings from our revolving credit facility and sales of mineral and royalty interests offset primarily by acquisitions made and payment of dividends to our stockholders and distributions to the holders of non-controlling interestsduring the year ended December 31, 2021. See "Note 4—Acquisitions and Divestitures" to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion. We expect that our cash flows from operations and additional borrowings under our revolving credit facility will be sufficient to fund our working capital needs. We expect that the pace of our operators’
drilling and completion of our undeveloped locations, production volumes, commodity prices and differentials to WTI and Henry Hub prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.
Dividends
The following table sets forth information with respect to cash dividends declared by our Board of Directors during 2021:
(1) Dividends
paid to holders of Class A common stock.
Our current dividend structure, implemented during the third quarter of 2021, consists of a base dividend of $0.14 per share of Class A common stock plus a variable dividend. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board of Directors. Our Board of Directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our results of operations, financial condition, capital requirements, contractual restrictions, credit agreement restrictions, restrictions imposed by applicable law and other factors that the Board of Directors deems relevant at the time of such determination. See "Item 5—Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend
Policy" for further discussion of our dividend policy.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Years Ended December 31,
(In Thousands)
2021
2020
2019
Net
cash provided by operating activities
$
109,199
$
75,260
$
69,025
Net cash used in investing activities
(89,983)
(65,425)
(216,832)
Net cash (used in)/provided
by financing activities
(7,341)
(51,824)
166,481
Analysis of Cash Flow Changes Between the Years Ended December 31, 2021, 2020 and 2019
Net cash provided by operating activities
Net cash provided by operating activities is primarily affected by production volumes, the prices of oil, natural gas and NGLs, lease bonus revenue and changes in working capital. The increase in net cash provided by operating
activities for the year ended December 31, 2021 as compared to the year ended December 31, 2020 is primarily due to 91% increase in realized commodity prices partially offset by the 5% decrease in production volumes and an increase in operating expenses during these periods discussed above. The increase in net cash provided by operating activities for the year ended December 31, 2020 as compared to the year ended December 31, 2019 is primarily due to improved collections of receivables and reduced payments for interest and income taxes, partly offset by increased payments for operating expenses.
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Net
cash used in investing activities
Net cash used in investing activities is primarily composed of acquisitions of mineral and royalty interests, net of dispositions. For the year ended December 31, 2021, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $103.5 million, offset by sales of mineral and royalty interests totaling $13.6 million.
For the year ended December 31, 2020, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $66.5 million and other fixed assets totaling $0.5 million, offset by sales of mineral and royalty interests totaling $1.6 million.
For the year
ended December 31, 2019, our net cash used in investing activities was primarily a result of acquisitions of mineral and royalty interests totaling $219.5 million and additions to other fixed assets of $0.4 million, offset by sales of mineral and royalty interests totaling $3.1 million.
Net cash (used in)/provided by financing activities
Net cash used in financing activities for the year ended December 31, 2021 was primarily a result of dividends paid to holders of our Class A common stock of $60.6 million, distributions to holders of non-controlling interest of $17.9 million, partial repayment of our revolving credit facility of $4.0 million, payment of employee tax withholding for settlement of equity compensation awards of $1.1 million and payments of loan
closing costs of $0.7 million, related to the December 15, 2021 borrowing base redetermination. This was partially offset by borrowings under our revolving credit facility of $77.0 million.
Net cash used in financing activities for the year ended December 31, 2020 was primarily due to the dividends paid to holders of our Class A common stock of $42.2 million, distributions to holders of temporary equity (or non-controlling interest as of February 19, 2021) of $24.7 million, and the repurchase of shares of our Class A common stock from the September 2020 Selling Stockholders for an aggregate purchase price of approximately $3.5 million, partially offset by borrowings under our revolving credit facility of $20.0 million.
Net cash provided
by financing activities for the year ended December 31, 2019 included the combined net proceeds generated from the IPO and December 2019 Offering of $379.8 million offset by the combined full repayment of the outstanding long-term debt of $175.0 million (net of additional borrowings of $105.0 million incurred during the year), dividends paid to holders of our Class A common stock of $14.7 million, distributions to holders of temporary equity of $20.1 million, payment of debt extinguishment fees of $2.1 million and payment of loan closing costs of $1.3 million.
Revolving Credit Facility
On May 16, 2019 (the “closing date”), Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A., as administrative agent for the various lenders
from time to time party thereto, providing for a revolving credit facility (our “revolving credit facility”). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is collateralized by a lien on substantial portion of Brigham Resources and its domestic subsidiaries’ assets, including substantial portion of their respective royalty and mineral properties.
Availability under our revolving credit facility is governed by a borrowing base, which is subject to redetermination semi-annually in May and November of each year. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. Brigham Resources can also request one additional redetermination
each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time. The weighted average interest rate for the year ended December 31, 2021 was 2.31%. As of December 31, 2021, the elected borrowing base on our revolving credit facility was $230.0 million, with outstanding borrowings of $93.0 million, resulting in $137.0 million availability for future borrowings.
Our revolving credit facility bears interest
at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions.
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Our
revolving credit facility matures on May 16, 2024. Loans drawn under our revolving credit facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full the commitments under our revolving credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our revolving credit facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at
such time may accelerate outstanding loans and terminate all commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances
or additional information may result in revised estimates, and actual results may differ from these estimates.
A complete list of our significant accounting policies are described in the notes to our audited consolidated financial statements for the year ended December 31, 2021 included elsewhere in this Annual Report.
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates
are recorded prospectively.
Our consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGL reserves that are the basis for the calculations of DD&A and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are audited by CG&A, an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of
oil and natural gas properties, share-based compensation expenses, and revenue accruals.
Accounts Receivable
Receivables consist of mineral and royalty revenues due from operators for their oil and gas sales to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Receivables from third parties for which we did not receive actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. Volume estimates for wells with available historical actual data are based upon (i) the historical actual data for the months the data is available, or (ii) engineering estimates for the months the historical actual data is not available. We do not recognize revenues for wells with no historical actual data because we cannot conclude that it is probable
that a significant revenue reversal will not occur in future periods. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.
We routinely review outstanding balances, assess the financial strength of our operators and record a reserve for amounts not expected to be fully recovered, using a current expected credit loss model. We recorded credit losses of $0.5 million, $0.3 million and $0.6 million for the years ended December 31, 2021, 2020 and 2019, respectively, which was included in general and administrative expenses.
Oil and Gas Properties
We use the full cost method of accounting
for our oil and natural gas properties. Under this method, all acquisition costs incurred for the purpose of acquiring mineral and royalty interests and certain related employee costs are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred.
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Capitalized costs are amortized using the units-of-production method. Under this method, the provision for depletion is calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by the net equivalent proved reserves at the beginning of the period.
Costs associated with unevaluated properties
are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated properties primarily consist of acquisition and leasehold costs and capitalized interest. Unevaluated properties are assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition costs incurred to date for such property
are transferred to the full cost pool and are then subject to amortization. There was no impairment recorded for unevaluated properties for the years ended December 31, 2021, 2020 and 2019.
Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.
Natural gas volumes are converted to Boe at the rate of six thousand Mcf of natural gas to one Bbl of oil. This convention
is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.
Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax effects (full cost ceiling limitation). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. A ceiling limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using the unweighted
arithmetic average of oil price ("SEC oil price") and natural gas price ("SEC gas price") as of the first day of each month for the trailing 12-month period ended, as required under the guidelines established by the SEC. As of December 31, 2021, 2020 and 2019, the SEC oil prices were $66.56, $39.57, and $55.65, respectively, per barrel for oil, further adjusted by area for energy content, transportation fees and regional price differentials and the SEC gas prices were $3.64, $2.00, and $2.60, respectively, per MMBtu for natural gas, further adjusted by area for energy content, transportation fees and regional price differentials. As a result of the decline in the SEC oil prices and SEC gas prices during the twelve months ended December 31, 2020, and taking
into consideration certain reclassification of proved undeveloped reserves to probable and possible reserves during the three months ended December 31, 2020, as a result of a slowdown in operator activity, the net book value of oil and natural gas properties exceeded the ceiling limitation as of September 30, 2020 and December 31, 2020, resulting in an impairment charge of $79.6 million to oil and gas properties, net during the year ended December 31, 2020. There were no impairment charges during the years ended December 31, 2021 and 2019.
Future significant and prolonged declines in the unweighted arithmetic average SEC oil prices
used in the full cost ceiling test may cause many of our operators to reduce substantially their development activities and capital expenditures, which could result in additional impairment charges in the future and such impairments could be material. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact the amount of any impairment charge.
We engage CG&A, our independent petroleum engineering firm, to audit our total estimated proved, probable and possible reserves. We expect proved, probable and possible reserve estimates will change as additional information becomes available and as commodity prices and costs change. We evaluate and estimate
our proved, probable and possible reserves internally each quarter and CG&A audits our proved, probable and possible reserves annually. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The estimates of proved, probable and possible reserves are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, historical and future operator development plans, and property ownership interests. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, which are considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, are also used.
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As
in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.
It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
It
should not be assumed that the standardized measure included in this report as of December 31, 2021 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2021 standardized measure on the SEC oil price and SEC gas price as of December 31, 2021, and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1—Business—Oil, Natural Gas, and NGLs Data—Proved, Probable and Possible Reserves” and “Item 1A—Risk Factors” for additional information regarding estimates of proved, probable and possible reserves.
Mineral and Royalty Revenues
Mineral and royalty revenues are generally recognized when control of
the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that we will receive for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.
Lease bonus and other income
We earn revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease bonus revenue by leasing our mineral interests to exploration and production companies. A lease agreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. We recognize lease bonus revenues when the lease agreement has been executed, payment has been received, and we have no further obligation to refund the payment. At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such
that we have not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606.
Share-Based Compensation
Brigham Minerals accounts for its share-based compensation, including grants of the Incentive Units, restricted stock awards, time-based restricted stock units and performance-based stock units, in the consolidated statements of operations based on their estimated fair values at grant date. Brigham Minerals uses a Monte Carlo simulation to determine the fair value of performance-based stock units. Brigham Minerals recognizes expense on a straight-line basis over the vesting period of the respective grant, which is generally the requisite service period. Brigham Minerals capitalizes a portion of the share-based compensation expense to oil and gas properties on the consolidated balance sheets. Share-based
compensation expense is included in general and administrative expenses in Brigham Minerals’ consolidated statements of operations included within this Annual Report. There was approximately $16.5 million of unamortized compensation expense relating to outstanding awards at December 31, 2021, a portion of which will be capitalized. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards. Brigham Minerals accounts for forfeitures as they occur.
Income Taxes
Brigham Minerals accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be
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recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets, including net operating losses. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among other
things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends and our outlook for future years.
Temporary Equity
Brigham Minerals accounted for the Original Owners’ 23.2% interest in Brigham LLC as of December 31, 2020 as temporary equity as a result of certain redemption rights held by the Original Owners as discussed in “Note 9—Temporary Equity and Non-controlling Interest” to the consolidated financial statements of Brigham Minerals included elsewhere in this Annual Report. As such, Brigham Minerals adjusted temporary equity to its maximum redemption amount at the balance sheet date, if higher than the carrying amount. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of Class A shares at the end of the
reporting period. Changes in the redemption value are recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to additional paid-in capital. Temporary equity is reclassified to permanent equity (i) upon Conversion of Class B common stock (and an equivalent number of Brigham LLC Units) to Class A common stock, or (ii) when holders of Class B common stock no longer control a majority of the votes of the Board of Directors through direct representation on the Board of Directors, and no longer control the determination of whether to make a cash payment upon a Brigham Unit Holder's exercise of its Redemption Right.
As a result of the appointment of an additional independent member to our Board of Directors on February 19, 2021, the holders of Class B common stock no longer hold a majority
of the votes of the Board of Directors and no longer control the Board of Directors through direct representation on the Board of Directors. Consequently, after February 19, 2021, Class B common stock is presented as non-controlling interest (as discussed below) in the consolidated balance sheets of Brigham Minerals.
Non-Controlling Interest
As of February 19, 2021 and thereafter, the holders of Class B common stock no longer control a majority of the votes of the Company's Board of Directors through direct representation on the Board of Directors, and no longer control the determination of whether to make a cash payment upon each holder of Brigham LLC Unit's (each a "Brigham LLC Unit Holder")
exercise of its Redemption Right (as hereinafter defined). As such, at December 31, 2021, Brigham Minerals accounts for Brigham LLC Unit Holders' 19.0% interest in Brigham LLC not owned by Brigham Minerals as non-controlling interest. For further discussion, see “Note 9—Temporary Equity and Non-controlling Interest.”
Recently Issued Accounting Pronouncements
None that are expected to have a material impact.
Off-Balance Sheet Arrangements
As of December 31, 2021, we did not have any material off-balance sheet arrangements.
Item
7A. 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
83
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 $85.64 per barrel in October 2021, and as of December 31, 2021, the posted price for oil was $75.33 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 December 31, 2021, the Henry Hub spot market price of natural gas was $3.82 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 discussed in “Item 1A—Risk Factors—Risks Related to Our Business—Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the
acreage underlying our interests are sold. Prices of oil, natural gas and NGLs are volatile due to factors beyond our control. The significant drop in the price of oil in 2020 has adversely affected, and any further decline in commodity prices in the future may adversely affect our business, financial condition or results of operations.”
A $1.00 per barrel change in our realized oil price would have resulted in a $1.7 million change in our oil revenues for the year ended December 31, 2021. 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 year ended December 31, 2021. A $1.00 per barrel change in NGL prices would have resulted in a $0.6 million change in our NGL revenues for the year months ended December 31,
2021. Royalty revenues from oil sales contributed 69% of our total revenues for the year ended December 31, 2021. Royalty revenue from natural gas sales contributed 17% and royalty revenue from NGL sales contributed 11% of our total revenues for the year ended December 31, 2021.
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. See "Item 1A—Risk Factors—Risk Related to Our Business—We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties."
Interest
Rate Risk
Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. In conjunction with the transition from LIBOR to SOFR a credit spread adjustment will be applied on top of the legacy LIBOR grid to calculate the new SOFR margin. If Brigham converts to SOFR on June 30, 2023 the credit spread adjustment will be set at 0.644 bps for overnight SOFR contracts and 11.448 bps, 26.161 bps and 42.826 bps for SOFR contracts
of 1 month, 3 month and 6 month tenors, respectively. If Brigham converts to SOFR before June 30, 2023 the credit spread adjustments will be based on market pricing. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facility is subject to other customary fee, interest and expense reimbursement provisions. As of December 31, 2021, the borrowing base on our revolving credit facility was $230.0 million, with outstanding borrowings of $93.0 million,
84
resulting
in $137.0 million availability for future borrowings. A 1-percentage-point increase in our interest rate would have increased our interest expense by $0.4 million for the year ended December 31, 2021.
Item 8. Financial Statements and Supplementary Data
The Company's consolidated financial statements required by this item are included in this Annual Report beginning on page F-1.
Item
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. 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 December 31, 2021. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in 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 December 31, 2021.
Management’s Report on Internal Control over Financial Reporting.
As management,
we are responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that the Company maintained effective internal control over financial reporting as of December 31, 2021, based on criteria in Internal Control—Integrated Framework (2013) issued by COSO.
The independent registered public accounting firm of KPMG LLP, as auditors of the Company’s consolidated financial statements, has issued an attestation report on the effectiveness of the
Company’s internal control over financial reporting, included herein.
Changes in Internal Control over Financial Reporting.
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2021 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Item 9B. Other Information
Not applicable.
85
PART
III
Item 10. Directors, Executive Officers and Corporate Governance
Information as to Item 10 is incorporated by reference from the information in our definitive proxy statement for the 2022 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.
Item 11. Executive Compensation
Information as to Item 11 is incorporated
by reference from the information in our definitive proxy statement for the 2022 Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information as to Item 12 is incorporated by reference from the information in our definitive proxy statement for the 2022 Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31,
2021.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 is incorporated by reference from the information in our definitive proxy statement for the 2022 Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.
Item 14. Principal Accounting Fees and Services
Information
as to Item 14 is incorporated by reference from the information in our definitive proxy statement for the 2022 Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.
86
PART IV
Item
15. Exhibits, Financial Statement Schedules
(1) Financial Statements
The consolidated financial statements of Brigham Minerals, Inc. and the Report of Independent Registered Public Accounting Firm are included in Part II, "Item 8— Financial Statements and Supplementary Data” of this Annual Report. Reference is made to the accompanying Index to Financial Statements.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.
The following financial information from this Annual Report on Form 10-K of Brigham Minerals, Inc. for the year ended December 31, 2021 is formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statement of Operations, (iii) Consolidated Statement of Changes in Stockholders' and Members' Equity, (iv) Consolidated Statement of Cash Flows and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.
104
Cover Page Interactive Data File (formatted
as Inline XBRL and contained in Exhibit 101)
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Austin, State of Texas.
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2022.
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Brigham Minerals, Inc.:
Opinion on
the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Brigham Minerals, Inc. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in stockholders’ and members’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of
the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control
– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made
by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions
on the critical audit matters or on the accounts or disclosures to which they relate.
F-2
Accrued mineral and royalty revenues
As discussed in Note 2 to the consolidated financial
statements, the Company recognizes mineral and royalty revenues when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied, and collectability is reasonably assured. As a non-operator, the Company 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, the Company 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 at each reporting period. Receivables from operators for which the Company did not receive actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated and recorded within the accounts receivable line item in the consolidated balance sheets. Volume estimates for wells with available historical actual data are based upon (i) the historical actual data for the months the data is available, or (ii) engineering estimates for the months the historical actual data is not available. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. The difference between the Company’s estimates and the actual amounts
received for mineral and royalty revenues is recorded in the month that payment is received from the operator. At December 31, 2021, the Company had accrued $30.5 million of mineral and royalty revenues.
We identified the assessment of accrued mineral and royalty revenues as a critical audit matter. A high degree of subjective auditor judgment was required to evaluate the estimated volume of production delivered to the related customers, as well as the price that will be received for the sale of the oil, natural gas, and NGLs produced.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the
operating effectiveness of certain internal controls related to the Company’s mineral and royalty revenues accrual process, including controls related to the development of the estimates of delivered production volumes and the price that will be received for the sale of such volumes. For a sample of transactions and where available, we compared management’s estimate of delivered production to third party evidence, and where not yet available, to internal estimates obtained from the Company’s internal staff of petroleum engineers and geoscience professionals. We compared the Company’s historical production estimates to actual production volumes to assess the
Company’s ability to accurately estimate and we compared the estimated production used by the Company in the current period to historical production. We evaluated the prices used by the Company to estimate the price to be received for the sale of the oil, natural gas, and NGLs produced by independently developing an expectation of price using publicly available prices and historical differentials.
Estimated proved oil and natural gas reserves used in the depletion of evaluated oil and natural gas properties
As discussed in Notes 2 and 3 to the consolidated financial statements, the
Company uses the full cost method of accounting for its oil and natural gas properties and amortizes capitalized costs using the unit-of-production method based upon total production for the period and estimated proved reserves quantities. The Company recorded $732.1 million of net oil and natural gas properties as of December 31, 2021, and recorded depletion expense of evaluated oil and natural gas properties of $36.4 million for the year ended December 31, 2021. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including the quantities of oil and natural gas reserves ultimately recovered, the timing of drilling and development of properties and the associated recovery of oil and natural gas reserves by the
Company’s third-party operators, the amount of operating expenses and future development expenditures incurred by the Company’s third-party operators, and the price received for the production. The Company’s internal staff of petroleum engineers and geoscience professionals prepare an estimate of the proved, probable, and possible oil and natural gas reserves, and the Company engages independent petroleum engineers to evaluate those estimated proved, probable, and possible oil and natural gas reserves.
We identified the assessment of the estimated proved oil and natural gas reserves used in the depletion of evaluated oil and
natural gas properties as a critical audit matter. There was a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves, as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production and oil and natural gas prices, inclusive of price differentials.
F-3
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the
Company’s depletion process, including controls related to the development of the assumptions listed above used to estimate proved oil and natural gas reserves. We evaluated (1) the professional qualifications of the lead internal petroleum engineer as well as the engineer assigned to the Company by the independent petroleum engineering firm engaged by the Company, (2) the knowledge, skills, and ability of the lead petroleum engineer, the engineer assigned to the Company by the independent petroleum engineering firm, as well as the independent petroleum engineering firm engaged by the Company, and (3) the objectivity of the
independent petroleum engineering firm and the engineer assigned to the Company. We assessed the methodology used by the Company’s internal staff of petroleum engineers and geoscience professionals to estimate the proved oil and natural gas reserves and the methodology used by the independent petroleum engineers to evaluate those reserve estimates for consistency with industry and regulatory standards. We compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and we compared the future forecasted production used by the
Company in the current period to historical production. We evaluated the oil and natural gas prices used by the Company’s internal staff of petroleum engineers and geoscience professionals by comparing them to publicly available prices and tested the relevant price differentials. We read the findings of the Company’s independent petroleum engineers in connection with our evaluation of the Company’s reserve estimates. We analyzed the depletion expense calculation for compliance with regulatory standards, and checked the accuracy of the depletion expense calculation.
We
have served as the Company’s auditor since 2013.
Report
of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Brigham Minerals, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Brigham Minerals, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In
our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated
statements of operations, changes in stockholders’ and members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2022 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.
Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining
an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Oil
and gas properties, at cost, using the full cost method of accounting:
Unevaluated property
i338,613
i325,091
Evaluated
property
i633,138
i488,301
Less
accumulated depreciation, depletion, and amortization
(i239,612)
(i189,546)
Oil
and gas properties, net
i732,139
i623,846
Other
property and equipment
i2,060
i5,587
Less
accumulated depreciation
(i1,280)
(i4,632)
Other
property and equipment, net
i780
i955
Operating
lease right-of-use asset
i6,764
i—
Deferred
tax asset
i25,308
i24,920
Other
assets, net
i1,183
i771
Total
assets
$
i820,877
$
i680,961
LIABILITIES
AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities
$
i20,473
$
i7,905
Current
operating lease liability
i1,178
i—
Total
current liabilities
i21,651
i7,905
Long-term
bank debt
i93,000
i20,000
Non-current
operating lease liability
i5,742
i—
Other
non-current liabilities
i810
i1,126
Temporary
equity
i—
i146,280
Equity:
Preferred
stock, $ii0.01/ par value; ii50,000,000/ authorized;
iiiino///
shares issued and outstanding at December 31, 2021 and December 31, 2020
i—
i—
Class
A common stock, $ii0.01/ par value; ii400,000,000/
authorized, i48,796,518 shares issued and i48,359,888 shares outstanding at December 31, 2021; i43,995,124
shares issued and i43,558,494 shares outstanding at December 31, 2020
i488
i440
Class
B common stock, $ii0.01/ par value; ii150,000,000/
authorized, ii11,371,517/ shares issued and outstanding
at December 31, 2021; ii13,167,687/
shares issued and outstanding at December 31, 2020
The
accompanying notes are an integral part of these consolidated financial statements.
F-9
BRIGHAM MINERALS, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
Years
Ended December 31,
(In Thousands)
2021
2020
2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)
$
i68,026
$
(i57,994)
$
i21,639
Adjustments
to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
i36,677
i48,238
i30,940
Impairment
of oil and gas properties
i—
i79,569
i—
Share-based
compensation expense
i9,703
i7,529
i10,049
Loss
on extinguishment of debt
i—
i—
i6,892
Amortization
of debt issue costs
i313
i605
i433
Deferred
income tax expense/(benefit)
i5,766
(i9,942)
i665
Loss
on derivative instruments, net
i—
i—
i568
Net
cash received for derivative settlements
i—
i—
i470
Credit
losses
i475
i299
i669
Changes
in operating assets and liabilities:
(Increase) decrease in accounts receivables
(i13,382)
i12,359
(i10,246)
Decrease
(increase) in other current assets
i442
(i2,005)
i1,787
Decrease
in other deferred charges
i—
i45
i—
Increase
(decrease) in accounts payables and accrued liabilities
i1,288
(i3,608)
i5,112
(Decrease)
increase in other long-term liabilities
(i109)
i165
i47
Net
cash provided by operating activities
$
i109,199
$
i75,260
$
i69,025
CASH
FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties
(i103,547)
(i66,498)
(i219,481)
Additions
to other fixed assets
(i56)
(i492)
(i474)
Proceeds
from sale of oil and gas properties, net
i13,620
i1,565
i3,123
Net
cash used in investing activities
$
(i89,983)
$
(i65,425)
$
(i216,832)
CASH
FLOWS FROM FINANCING ACTIVITIES
Payments of short-term debt
i—
i—
(i4,596)
Payments
of long-term debt
(i4,000)
i—
(i275,404)
Borrowing
of long-term debt
i77,000
i20,000
i105,000
Payment
of debt extinguishment fees
i—
i—
(i2,091)
Proceeds
from issuance of Class A common stock sold in initial public offering, net of offering costs
i—
i—
i277,075
Proceeds
from issuance of Class A common stock, net of offering costs
i—
i—
i102,680
Capital
distributions
i—
i—
(i441)
Purchase
of treasury stock
i—
(i3,527)
i—
Dividends
paid
(i60,614)
(i42,216)
(i14,663)
Distributions
to holders of non-controlling interest and temporary equity
(i17,864)
(i24,670)
(i19,731)
Debt
issuance cost
(i727)
(i208)
(i1,348)
Payment
of employee tax withholding for settlement of equity compensation awards
(i1,136)
(i1,203)
i—
Net
cash (used in) provided by financing activities
$
(i7,341)
$
(i51,824)
$
i166,481
Change
in cash and cash equivalents and restricted cash
i11,875
(i41,989)
i18,674
Cash
and cash equivalents and restricted cash, beginning of period
i9,144
i51,133
i32,459
Cash
and cash equivalents and restricted cash, end of period
$
i21,019
$
i9,144
$
i51,133
The
accompanying notes are an integral part of these consolidated financial statements.
F-10
BRIGHAM MINERALS, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(CONTINUED)
Years
Ended December 31,
(In Thousands)
2021
2020
2019
Supplemental disclosure of non-cash activity:
Accrued
capital expenditures
$
i561
$
i146
$
i63
Capitalized
share-based compensation expense
i8,048
i6,086
i3,818
Issuance
of common stock for acquisitions of oil and gas properties
i46,349
i—
i—
Temporary
equity cumulative adjustment to redemption value
i54,294
(i170,361)
i51,572
Supplemental
cash flow information:
Cash payments for loan commitment fees and interest
$
(i1,318)
$
(i715)
$
(i6,192)
Tax
(payments) refunds received
(i8,030)
i1,211
(i832)
The
accompanying notes are an integral part of these consolidated financial statements.
F-11
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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”) is a Delaware corporation formed in June 2018 to become a holding company. Brigham Minerals acquired an indirect interest in Brigham Resources, LLC (“Brigham Resources”), our predecessor, on July 16, 2018 in a series of restructuring transactions pursuant to which certain entities affiliated with Warburg Pincus LLC (“Warburg Pincus”) contributed all of their respective interests in the entities through which they held interests in Brigham Resources to Brigham Minerals in exchange for all of
the outstanding shares of common stock of Brigham Minerals (the “July 2018 restructuring”). As a result of such restructuring transactions, Brigham Minerals became wholly owned by an entity affiliated with Warburg Pincus, and Brigham Minerals indirectly owned a i16.5% membership interest in Brigham Resources. The remaining outstanding membership interests of Brigham Resources remained with certain other entities affiliated with Warburg Pincus, Yorktown Partners LLC and Pine Brook Road Advisors, LP, Brigham Minerals’ management and its other investors (collectively, the “Original
Owners”).
On November 20, 2018, Brigham Resources underwent a second series of restructuring transactions (the “November 2018 restructuring”). In the November 2018 restructuring, Brigham Resources became a wholly owned subsidiary of Brigham Minerals Holdings, LLC (“Brigham LLC”), which was a wholly owned subsidiary of Brigham Equity Holdings, LLC (“Brigham Equity Holdings”), and Brigham Equity Holdings became wholly owned by the owners of Brigham Resources immediately prior to such restructuring, directly or indirectly, through Brigham Minerals. As a result of the foregoing transactions, there was no change in the control or economic interests of the Original Owners and Brigham Minerals in Brigham Resources, although their ownership became indirect through Brigham Equity Holdings and its wholly owned subsidiary, Brigham LLC. The July 2018 restructuring
and the November 2018 restructuring are collectively referred to herein as the “2018 corporate reorganizations.”
Brigham Resources wholly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals Subsidiaries”), which acquire and actively manage a portfolio of mineral and royalty interests. The Minerals Subsidiaries are Brigham Resources’ sole material assets.
Initial Public Offering
In April 2019, Brigham Minerals completed its' initial public offering (the "IPO") of i16,675,000
shares of Class A common stock at a price to the public of $i18.00 per share. This resulted in net proceeds of approximately $i273.4 million, after deducting underwriting
commissions and discounts and offering expenses, which proceeds were used to repay $i200.0 million of existing indebtedness and to fund mineral and royalty acquisitions. As a result of the IPO and the corporate restructuring described in "Note 9—Temporary Equity and Non-controlling Interest", Brigham Minerals became a holding company whose sole material asset consisted of a i43.3%
interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to wholly own the Minerals Subsidiaries, which own all of Brigham Resources’ operating assets. In connection with the IPO, Brigham Minerals became the sole managing member of Brigham LLC and is responsible for all operational, management and administrative decisions relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its wholly owned subsidiary, Brigham Resources.
December 2019 Offering
On December 16, 2019, Brigham Minerals completed an offering of i12,650,000
shares of its Class A common stock (the "December 2019 Offering"), including i6,000,000 shares issued and sold by Brigham Minerals and an aggregate of i6,650,000
shares sold by certain stockholders of the Company (the "Selling Stockholders"), of which i5,496,813 represents shares issued upon redemption of an equivalent number of their Brigham LLC units, at a price to the public of $i18.10
per share ($i17.376 per share net of underwriting discounts and commissions). After deducting underwriting discounts, commissions and offering expenses, Brigham Minerals received net proceeds of approximately $i102.7
million which were used to repay $i80.0 million of existing indebtedness under our revolving credit agreement and mineral and royalty acquisitions. Brigham Minerals did not receive any proceeds from the sale of shares of Class A common stock by the Selling Stockholders.
F-12
BRIGHAM MINERALS, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
June 2020 Secondary Offering
On June 12, 2020, Brigham Minerals completed an offering of i6,600,000 shares of its Class A common stock (the "June 2020 Secondary Offering"), all of which were sold by certain stockholders of the
Company (the “June 2020 Selling Stockholders”), and i4,872,669 of which represented shares issued upon redemption of an equivalent number of the June 2020 Selling Stockholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $i13.75
per share. Brigham Minerals did not sell any shares of its common stock in the June 2020 Secondary Offering and did inot receive any proceeds pursuant to the June 2020 Secondary Offering.
September 2020 Secondary Offering
On September 15, 2020, Brigham Minerals completed an offering of i5,021,140
shares of its Class A common stock, including i654,931 shares issued pursuant to the option granted to the underwriter to purchase additional shares to cover over-allotments (the "September 2020 Secondary Offering"), all of which were sold by certain stockholders of the Company (the "September 2020 Selling Stockholders"), and i3,062,011
of which represented shares issued upon redemption of an equivalent number of the September 2020 Selling Stockholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in Brigham Minerals), at a price to the public of $i8.20 per share. Brigham Minerals did not sell any shares of its Class A common stock in the September 2020 Secondary Offering and did inot
receive any proceeds pursuant to the September 2020 Secondary Offering. In addition, in connection with the September 2020 Secondary Offering, Brigham Minerals repurchased i436,630 shares of its Class A common stock from the September 2020 Selling Stockholders in a privately negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from the September 2020 Selling Stockholders in the September 2020 Secondary Offering (and Brigham LLC redeemed a corresponding number of Brigham LLC Units held by Brigham Minerals). The
repurchased shares are presented in the Company's consolidated balance sheet as Treasury Stock, at cost.
As of December 31, 2021, Brigham Minerals owned a i81.0% interest in Brigham LLC and the Original Owners owned i19.0%
of the outstanding voting stock of Brigham Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset of the Company's Original Owners, collectively owned i8.7% of the outstanding voting stock of Brigham Minerals as of December 31, 2021. Yorktown ceased to be an affiliate of the
Company on January 20, 2022 in connection with the resignation of W. Howard Keenan, Jr. from the Board of Directors.
Basis of Presentation
The accompanying consolidated financial statements of Brigham Minerals have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair representation. 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 temporary equity at December 31, 2020 and as non-controlling interest at March 31, 2021 and thereafter, which will reduce net income attributable to the holders of Brigham Minerals' Class A common stock. For more information, see "Note 9—Temporary equity and Non-controlling interest.”
2. iSignificant
Accounting Policies
Emerging Growth Company and Large Accelerated Filer Status
As a company with less than $1.07 billion in revenues during its during the twelve months ended December 31, 2020, Brigham Minerals qualified as an “emerging growth company” (“EGC”) as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An EGC may take advantage of specified reduced reporting and other regulatory requirements. As a result of Brigham Minerals’ election to avail itself of certain provisions of the JOBS Act, the information that Brigham Minerals provides for periods prior to January 1, 2021, may be different than the information provided by other public companies.
F-13
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of June 30, 2021 the total market value of Brigham Minerals’ common equity securities held by non-affiliates exceeded $700 million and as a result, Brigham Minerals became a "large accelerated filer" and ceased to be an EGC as of December 31, 2021. Brigham Minerals was required to accelerate the adoption of Accounting Standards Update (“ASU”) 2016-02 Leases (Topic 842) and ASU 2016-13, Financial Instruments—Credit Losses (Topic 326) for the year ended December 31, 2021 as described below under the heading, "Recently Adopted Accounting Standards".
i
Recently
Adopted Accounting Standards
Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), (or "the new lease standard") amending the guidance on the accounting for leasing transactions. The new lease standard requires lessees to recognize a lease liability for the obligation to make lease payments and a right-of-use (“ROU”) asset for the right to use the underlying asset for the lease term. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU replaced most existing lease guidance in GAAP effective upon adoption. The Company adopted the new lease standard during the fiscal year ending December 31, 2021, with a beginning period of adoption of January
1, 2021. The Company made policy elections to apply the following practical expedients as provided in the standards update:
• an accounting policy election to not apply the recognition requirements in the new standards update to short-term leases (a lease that at commencement date has a lease term of twelve months or less) and not to separate non-lease components from lease components for all asset classes; and
• a package of practical expedients to not reassess whether a contract contains a lease, lease classification and initial direct costs prior to January 1, 2021.
In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. The Company enters into land easements as a lessor, on a routine basis as part of its ongoing operations and has many such agreements currently in place; however, the Company did not account for any land easements under Topic 840. As this guidance serves as an amendment to the new lease standard, the Company elected this practical expedient, which became effective upon the date of adoption of the new lease standard. For Brigham Minerals, as a lessor,
the amounts received with respect to term-based land easement payments were immaterial during the fiscal year ending December 31, 2021. The Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease. Perpetual-based land easements are not in scope under the new lease standard.
In July 2018, the FASB issued ASU 2018-11 Leases (Topic 842): Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in
accordance with current GAAP (Topic 840, Leases) and applying the modified retrospective approach, with a cumulative-effect adjustment to the opening balance of retained earnings as of the adoption date. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2021 was immaterial.
Financial Instruments — Credit Losses
In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU 2016-13 was subsequently amended by ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU 2016-13, as amended,
affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaced the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The Company adopted ASU 2016-13 during the fiscal year ending December 31, 2021, with a beginning period of adoption of January 1, 2021. The impact of the adoption of ASU 2016-13 on the consolidated financial statements of Brigham Minerals was immaterial. ASU 2016-13 was applied using a modified retrospective approach, with a cumulative-effect adjustment to the opening balance of retained earnings as of the adoption date, however, the cumulative impact of adoption in the opening balance of retained earnings as of January
1, 2021 was immaterial.
F-14
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
i
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.
The accompanying consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGLs 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’ reserve estimates are audited by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, share-based compensation expenses and revenue accruals.
i
Cash and Cash Equivalents
Brigham Minerals
considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
iAccounts Receivable
Receivables consist of royalty income due from operators for oil and gas sales to purchasers. Those purchasers remit payment for production to the operator of our properties and the operator, in turn, remits payment to us. Receivables from third parties for which we did not receive actual information, either due
to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. Volume estimates for wells with available historical actual data are based upon (i) the historical actual data for the months the data is available, or (ii) engineering estimates for the months the historical actual data is not available. We do not recognize revenues for wells with no historical actual data because we cannot conclude that it is probable that a significant revenue reversal will not occur in future periods. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.
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 recorded
credit losses of $i0.5 million, $i0.3 million and $i0.6
million for the years ended December 31, 2021, 2020 and 2019, respectively, which was included in general and administrative expenses.
iConcentration 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.
(1) ConocoPhillips
Company acquired Royal Dutch Shell's subsidiary, Shell Enterprises LLC, interest in Shell's Permian assets.
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 year ended December 31, 2021, we received revenues from i178 operators with approximately i67%
of revenues coming from the top ten operators on our properties. For the year ended December 31, 2020, we received revenues from i145 operators with approximately i70% of revenues
coming from the top ten operators on our properties.
i
Financial Instruments
Brigham Minerals’ financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities, and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of Brigham
Minerals’ derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments.
The carrying amount of long-term debt associated with borrowings outstanding under Brigham Minerals’ revolving credit facility approximates fair value as borrowings bear interest at variable market rates. See “Note 5—Fair Value Measurements” and “Note 6—Long-Term Debt.”
i
Oil
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 and certain related employee costs are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred.
Capitalized costs are amortized using the units-of-production method. Under this method, the provision for depletion is calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by net equivalent proved reserves at the beginning of the period.
Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has
been made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated properties primarily consist of acquisition costs and capitalized general and administrative costs. Unevaluated properties are assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition
F-16
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. There was no impairment recorded for unevaluated properties in 2021, 2020 and 2019.
Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.
Natural gas volumes are converted to barrels of oil equivalent (Boe) at the rate of six thousand cubic
feet (Mcf) of natural gas to one barrel (Bbl) of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.
Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties less related income tax effects (the ceiling limitation). A ceiling limitation is calculated at each reporting period. If total capitalized costs, net of accumulated DD&A and related deferred income taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full
cost pool 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. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using an unweighted arithmetic average of oil prices ("SEC oil price") and natural gas prices ("SEC gas price") as of the first day of each month for the trailing 12-month period ended December 31, 2021, adjusted by area for energy content, transportation fees and regional price differentials, as required under the guidelines established by the SEC. If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. See “Note 3—Oil and Gas Properties” for further discussion.
i
Leases
The
Company determines if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease, depending on the lease classification guidance. We currently do not have any finance leases. We capitalize our operating leases through an operating lease ROU asset and a corresponding operating lease liability on our consolidated balance sheets. ROU assets represent our right to use an underlying asset for the lease term and operating lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.
Our operating leases are reflected as operating lease right-of-use asset, current operating
lease liability and non-current operating lease liability on our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.
Nature of Leases
We lease certain office space under a non-cancelable lease for our corporate headquarters. Our office agreements are typically structured with non-cancelable terms of one to iten
years. We have concluded our office agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.
Discount Rate
Our office agreement does not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term in an amount equal
to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.
/
F-17
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Practical Expedients and Accounting Policy Elections
Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components
from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component.
In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statements of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statements of operations in the period in which the obligation for those payments is incurred. Lease payments on our short-term leases during the years ended
December 31, 2021, 2020 and 2019 were immaterial.
i
Accounting for Leases as a Lessor
The Company acts as a lessor with respect to amounts received for land easements (also commonly referred to as rights of way). Land easements represent the right to use,
access, or cross another entity's land for a specified purpose. The Company elected to apply the land easement practical expedients and does not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. A land easement may be perpetual or term-based. Perpetual easements are not in scope under the new leasing standard. All term-based land easements granted by the Company during the year ended December 31, 2021 were immaterial in the aggregate.
See "Note 7—Leases" for additional disclosures of the Company's leases.
iShare-Based
Compensation
Brigham Minerals accounts for its share-based compensation including grants of the Incentive Units (as hereinafter defined), restricted stock awards, time-based restricted stock units and performance-based stock units in the consolidated statements of operations based on their estimated fair values at grant date. Brigham Minerals uses a Monte Carlo simulation to determine the fair value of performance-based stock units. Brigham Minerals recognizes expense on a straight-line basis over the vesting period of the respective grant, which is generally the requisite service period. Brigham Minerals capitalizes a portion of the share-based compensation expense to oil and gas properties on the consolidated balance sheets. Share-based compensation expense is included in general and administrative expenses in Brigham Minerals’ consolidated statements of operations included within this Annual Report. There was approximately $i16.5
million of unamortized compensation expense relating to outstanding awards at December 31, 2021, a portion of which will be capitalized. The unrecognized share-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards. Brigham Minerals accounts for forfeitures as they occur.
iEarnings Per Share
Brigham Minerals uses the “if-converted” method to determine
the potential dilutive effect of its Class B common stock and the treasury stock method to determine the potential dilutive effect of outstanding Incentive Units, RSAs, RSUs, and PSUs.
iEmployee Benefit Plan
We sponsor a 401(k) tax-deferred savings plan for our employees. We match i100%
of each employee’s contributions, up to i6% of the employee’s total compensation. Brigham Resources may also contribute additional amounts at its discretion. Brigham Resources contributed $i0.4
million, $i0.4 million and $i0.3 million, to the 401(k) plan for each of the years ended December 31,
2021, 2020, and 2019.
i
Income Taxes
Brigham Minerals accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing
tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Brigham Minerals periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, Brigham Minerals considers
F-18
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
all available positive and negative evidence
and makes certain assumptions. Brigham Minerals considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends and its outlook for future years.
i
Temporary Equity
Brigham Minerals accounted for the Original Owners’ i23.2%
interest in Brigham LLC as of December 31, 2020, as temporary equity as a result of certain redemption rights held by the Original Owners as discussed in “Note 9—Temporary Equity and Non-controlling Interest.” As such, the Company adjusted temporary equity to its maximum redemption amount at the balance sheet date, if higher than the carrying amount. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of Class A shares at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to additional paid-in capital. Temporary equity is reclassified to permanent equity (i) upon Conversion of Class B common stock (and an equivalent
number of Brigham LLC Units) to Class A common stock, or (ii) when holders of Class B common stock no longer control a majority of the votes of the Company's Board of Directors (the "Board of Directors") through direct representation on the Board of Directors, and no longer control the determination of whether to make a cash payment upon a Brigham Unit Holder's exercise of its Redemption Right.
As a result of the appointment of an additional independent member to our Board of Directors on February 19, 2021, the holders of Class B common stock no longer hold a majority of the votes of the Board of Directors and no longer control the Board of Directors through direct representation on the Board of Directors. Consequently, after February 19,
2021, Class B common stock is presented as non-controlling interest (as discussed below) in the consolidated balance sheets of Brigham Minerals.
/i
Non-Controlling Interest
As of February 19, 2021 and thereafter, the holders of Class B common stock no longer control a majority of the votes of the Board of Directors through direct representation on
the Board of Directors, and no longer control the determination of whether to make a cash payment upon each holder of Brigham LLC Unit's (each a "Brigham LLC Unit Holder") exercise of its Redemption Right (as hereinafter defined). As such, at December 31, 2021, Brigham Minerals accounts for Brigham LLC Unit Holders' i19.0% interest in Brigham LLC not owned by Brigham Minerals as non-controlling interest. For further discussion, see “Note 9—Temporary Equity and Non-controlling Interest.”
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, which can extend up to 9 months after initial production from the well. 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.
F-19
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
i
During the twelve months ending December 31, 2021, 2020 and 2019 the disaggregated revenues from sales of oil, natural gas and NGLs are as follows:
For
the Years Ended December 31,
Disaggregated revenues (in thousands)
2021
2020
2019
Oil sales
$
i110,791
$
i67,909
$
i82,048
Natural
gas sales
i27,070
i10,443
i9,724
NGL
sales
i18,838
i7,893
i6,114
Total
mineral and royalty revenues
$
i156,699
$
i86,245
$
i97,886
/
Lease
bonus and other income
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 obligation 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 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 years ended December 31, 2021, 2020 and 2019, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.
Debt Issuance Cost
Other assets include capitalized debt issuance costs of $i1.2
million and $i0.8 million, net of accumulated amortization of $i1.1 million and $i0.8
million as of December 31, 2021 and 2020, respectively. iDebt issuance costs were incurred in connection with establishing and amending credit facilities for Brigham Resources and are amortized over the term of the credit facilities using the straight-line method, which approximates the effective interest rate method. Amortization expense for debt issue costs was $i0.3
million, $i0.6 million and $i0.4 million for the years ended December 31, 2021, 2020,
and 2019. During the year ended December 31, 2020, we wrote off debt issuance cost of $i0.3 million as a result of the reduction of the borrowing base on our revolving credit facility that occurred in May 2020.
F-20
BRIGHAM MINERALS, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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 $i13.0 million, $i10.2
million and $i7.4 million for the years ended December 31, 2021, 2020, and 2019, 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:
December 31,
(In Thousands)
2021
2020
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated
property
$
i338,613
$
i325,091
Evaluated
property
i633,138
i488,301
Total
oil and gas properties, at cost
i971,751
i813,392
Less
accumulated depreciation, depletion, and amortization
(i239,612)
(i189,546)
Total
oil and gas properties, net
$
i732,139
$
i623,846
Costs
not subject to depletion are as follows, by the year in which such costs were incurred:
By
Year:
(In Thousands)
Total
2021
2020
2019
2018
2017
Prior
Property Acquisition costs
$
i338,613
$
i45,885
$
i32,456
$
i71,385
$
i64,582
$
i58,619
$
i65,686
Capitalized
costs are depleted on a unit of production basis based on proved oil and natural gas reserves. Depletion expense was $i36.4 million, $i47.3 million
and $i30.4 million for the year ended December 31, 2021, 2020 and 2019, respectively. Average depletion of proved properties was $i11.05,
$i13.63 and $i11.22 per Boe for the year ended December 31,
2021, 2020 and 2019, 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 December 31, 2021, 2020 and 2019, 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, were $66.56, $39.57, and $55.65 per barrel of oil and $3.64, $2.00, and $2.60 per MMbtu of natural gas, respectively. During the year ended December 31, 2020, Brigham Minerals recorded ceiling test impairment charges of $i79.6
million to oil and gas properties, net, as a result of its quarterly ceiling test analysis. The impairment charges were due to declining SEC oil prices and SEC gas prices, as well as certain reclassification of proved undeveloped reserves to probable and possible reserves, as a result of a slowdown in operator activity. There were iino/
impairment charges during the years ended December 31, 2021 and 2019.
A decline in the SEC oil price or the SEC gas price could lead to impairment charges in the future and such impairment charges could be material, such as occurred in the third and fourth quarters of 2020. In addition to the impact of lower prices, any future changes to assumptions of drilling and completion activity, development timing, acquisitions or divestitures of oil and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact the amount of any impairment charge.
F-21
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. iAcquisitions and Divestitures
DJ Acquisition
On
November 3, 2021, the Company entered into a definitive purchase and sale agreement to acquire approximately i8,400 net royalty acres primarily in Weld County, Colorado, operated by PDC Energy, Inc., Chevron Corporation, Occidental Petroleum and Civitas Resources for i2.2 million
shares of the Company’s common stock and $i43.1 million of cash, net of $i1.7 million
of customary closing adjustments. The DJ Acquisition closed on December 15, 2021. The cash portion of the purchase price was funded through a combination of cash on hand and borrowings under the Company’s revolving credit facility.
i
The following table presents the acquisition consideration paid in the DJ Acquisition (in thousands, except the number of shares and price per share):
Consideration:
Class
A shares of Brigham Minerals, Inc. common stock issued at closing
i2,180,128
Closing price per share of Brigham Minerals, Inc. common stock on the closing date
$
i21.26
Fair
Value of Brigham Minerals, Inc. common stock issued
$
i46,349
Cash consideration
i43,083
Total
consideration (including fair value of Brigham Minerals, Inc. common stock issued)
$
i89,432
/
The DJ Acquisition has been accounted for as an asset acquisition and the allocation of the purchase price
was $i17.9 million to unevaluated properties and $i71.5 million to evaluated properties.
Other
Acquisitions
i
During the years ended December 31, 2021 and 2020, Brigham Minerals entered into a number of acquisitions of mineral and royalty interests from various sellers in Texas, Oklahoma, Colorado, New Mexico, and North Dakota, as reflected in the table below. The change in the oil and natural gas property
balance for the year ended December 31, 2021 is comprised of payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative expenses that were funded with our retained operating cash flow, proceeds from asset sales and our revolving credit facility (hereinafter defined). The changes in the oil and natural gas property balance for the year ended December 31, 2020 were partially funded with proceeds from the December 2019 Offering as well as our retained cash flow and our revolving credit facility.
During
the year ended December 31, 2021, Brigham Minerals divested certain non-core, primarily undeveloped acreage in Oklahoma and received cash of $i13.6 million.
F-22
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5.iFair Value Measurements
i
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
Brigham Minerals had no financial assets or liabilities that were accounted for at fair value on a recurring basis at December 31,
2021 and 2020.
Brigham Minerals had no derivative contracts in place as of December 31, 2021 and 2020. Commodity derivative instruments are valued using a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative
assets and our credit quality for derivative liabilities. As such, these derivative contracts are classified within Level 2.
Brigham Minerals had no transfers into or out of Level 1 and no transfers into or out of Level 2 for the years ended December 31, 2021 and 2020.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Certain nonfinancial 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.
6.iLong-Term
Debt
Revolving Credit Facility
On May 16, 2019 (the “closing date”) Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A., as administrative agent for the various lenders from time to time party thereto, providing for a revolving credit facility (our "revolving credit facility”). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is
F-23
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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 year ended December 31, 2021 was i2.31%. As of December 31, 2021, the borrowing base
on our revolving credit facility was $i230.0 million, with outstanding borrowings of $i93.0 million, resulting in $i137.0 million
availability for future borrowings.
Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our revolving credit facility and ranges from (a) in the case of adjusted base rate loans, i1.500% to i2.500%
and (b) in the case of adjusted LIBOR rate loans, i2.500% to i3.500%. Brigham Resources may elect an interest period of one, two,
three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount ranging from 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 LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full the commitments under our revolving credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must
be prepaid. Upon the occurrence of an event of default under our revolving credit facility, the Administrative Agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.
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 December 31, 2021, we were in compliance with all covenants in accordance with our revolving credit facility.
F-24
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. 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. See "Note 2—Significant Accounting Policies—Leases—Practical Expedients and Accounting Policy Elections" for further discussion. 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 this operating leases is recognized over the term of the lease on a straight-line basis. Rent expense for the years ended December 31, 2021, 2020, and 2019 was $i1.3 million, $i1.1
million, and $i0.6 million, respectively.
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 easements payments received during the year ended December 31,
2021 and determined that all such payments were immaterial in the aggregate.
i
The following table summarizes the Company’s recognition of its operating lease:
The
table below presents the maturity of the Company’s liabilities under the Bridgepoint Lease as of December 31, 2021.
Year
Commitment
2022
$
i1,296
2023
i1,319
2024
i1,340
2025
i1,360
2026
i1,383
Thereafter
i582
Total lease payments
$
i7,280
Less
imputed interest
(i360)
Total lease liabilities
$
i6,920
/
F-25
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. iEquity
Class A Common Stock
Brigham Minerals had approximately i48.4
million shares of its Class A common stock outstanding as of December 31, 2021. 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 i11.4 million shares of its Class B common stock outstanding as of December 31, 2021. 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
Brigham Minerals repurchased i436,630 shares of its Class A common
stock from the September 2020 Selling Stockholders at a price of $i8.08 per share (and Brigham LLC redeemed a corresponding number of Brigham LLC Units held by Brigham Minerals). See "Note 1—Business and Basis of Presentation." As of December 31, 2021, there were ii436,630/
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 Brigham LLC Units), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding RSAs, RSUs, PSUs and unvested Incentive Units as defined in "Note 2 - Significant Accounting Policies - Earnings Per Share". 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 year ended December 31, 2021, the Class B common stock and the Incentive Units were not recognized in the dilutive EPS calculations as the effect would have been antidilutive. For the year ended December 31, 2020, the Class B common stock, the Incentive Units, RSAs and RSUs were not recognized in dilutive EPS calculations as the effect would have been antidilutive, and the PSUs were not included in the computation of EPS because the performance goals had not been met, assuming the end of the reporting period was the end of the contingency period. For the year ended December 31, 2019, Brigham Minerals’ EPS calculation includes only its share of net income for the period subsequent to the IPO, and omits income
or loss prior to the IPO. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding from the IPO through December 31, 2019.
F-26
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
i
The
following table reflects the allocation of net income (loss) to common stockholders and EPS computations for the period indicated based on a weighted average number of common stock outstanding for the period:
Years Ended December 31,
(In Thousands, Except per Share Data)
2021
2020
2019
Basic
EPS
Numerator:
Basic net income (loss) attributable to Brigham Minerals, Inc. stockholders
$
i50,283
$
(i42,412)
$
i6,901
Less
net income attributable to stockholders pre-IPO
i—
i—
(i848)
Basic
net income (loss) attributable to Brigham Minerals, Inc. stockholders post-IPO (1)
$
i50,283
$
(i42,412)
$
i6,053
Denominator:
Basic
weighted average shares outstanding (1)
i44,576
i38,178
i22,870
Basic
EPS attributable to Brigham Minerals, Inc. stockholders
$
i1.13
$
(i1.11)
$
i0.26
Diluted
EPS
Numerator:
Basic net income (loss) attributable to Brigham Minerals, Inc. stockholders post-IPO (1)
$
i50,283
$
(i42,412)
$
i6,053
Diluted
net income (loss) attributable to Brigham Minerals, Inc. stockholders
$
i50,283
$
(i42,412)
$
i6,053
Denominator:
Basic
weighted average shares outstanding (1)
i44,576
i38,178
i22,870
Effect
of dilutive securities:
Unvested equity awards
i1,056
i—
i—
Diluted weighted
average shares outstanding
i45,632
i38,178
i22,870
Diluted
EPS attributable to Brigham Minerals, Inc. stockholders
$
i1.10
$
(i1.11)
$
i0.26
/
(1) Represents
earnings per share of Class A common stock and weighted average shares of Class A common stock for the period following the IPO.
9. iTemporary Equity and Non-controlling Interest
Temporary equity
Temporary equity represented the i23.2%
interest in the units of Brigham LLC not owned by Brigham Minerals, as of December 31, 2020. Class B common stock was classified as temporary equity in the consolidated balance sheet as of December 31, 2020, as pursuant to the Amended and Restated Limited Liability Company Agreement of Brigham LLC (the "Brigham LLC Agreement"), the Redemption Rights of a Brigham LLC Unit Holder for either shares of Class A common stock or an equivalent amount of cash was not solely within Brigham Minerals' control. This was due to the fact that the holders of Class B common stock controlled a majority of the votes of the Board of Directors through direct representation on the Board of Directors, which allowed the holders of Class B common stock to control the determination of whether to make a cash payment upon a Brigham LLC Unit Holder's exercise of its Redemption Right.
As
a result of the appointment of an additional independent member to our Board of Directors on February 19, 2021, the holders of Class B common stock no longer hold a majority of the votes of the Board of Directors and no longer control the Board of Directors through direct representation on the Board of Directors. Consequently, after February 19, 2021, Class B common stock is presented as non-controlling interest (as discussed below) in the consolidated balance sheet of Brigham Minerals.
F-27
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Temporary equity was recorded at the greater of the carrying
value or redemption amount with a corresponding adjustment to additional paid-in capital. iFrom the date of the IPO through February 18, 2021, Brigham Minerals recorded adjustments to the value of temporary equity as presented in the table below:
(1) Based on i28,777,802
shares of Class B common stock outstanding and Class A share price of $i18.00. In connection with the IPO, the balance transferred from additional paid-in capital to temporary equity was the greater of redemption value or carrying value of the shares of Class B common stock at IPO and included an initial upward adjustment to redemption amount totaling $i194.5 million.
(2) Based
on i22,847,045 shares of Class B common stock outstanding and Class A share 10-day VWAP of $i19.89 at December 31, 2019.
(3) Based
on i13,167,687 shares of Class B common stock outstanding and Class A share 10-day VWAP of $i11.11 at December 31, 2020.
(4) Based
on i13,167,687 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $i15.38 at February
18, 2021. The February 18, 2021 redemption value of temporary equity became the carrying value of non-controlling interest, as discussed below.
Non-controlling Interest
Non-controlling interest represents the i19.0% interest in the units of Brigham LLC not owned by Brigham Minerals, as of December 31,
2021. Class B common stock is classified as non-controlling interest in the consolidated balance sheet as of February 19, 2021 and thereafter.
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 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.
F-28
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Non-controlling
interest is recorded at its carrying value. iFor the period from February 19, 2021 to December 31, 2021, the Company recorded adjustments to the value of non-controlling interest as presented in the table below:
(1) Represents
the February 19, 2021, redemption value of temporary equity, prior to its reclassification to non-controlling interest. Based on i13,167,687 shares of Class B common stock outstanding and Class A common stock 10-day volume-weighted average closing price of $i15.38
at February 18, 2021.
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 are subject to vesting as follows: i20%
of the Incentive Units were vested on the date of grant and i20% 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 receive 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; however Brigham Equity Holdings will continue to administer the existing awards that remain outstanding.
As discussed in “Note 9—Temporary Equity and 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 year ended December 31, 2021 is as follows:
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,
F-29
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 December 31, 2021, i3,013,884
shares of Class A common stock remained available for future grants. Currently, all RSAs, RSUs and PSUs granted under the LTIP are entitled to receive dividends (in the case of RSAs) or have 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 dividends and DERs are subject to the same vesting and other terms and conditions as the corresponding unvested RSAs, RSUs, and PSUs. Dividends and DERs are accumulated and paid when the underlying shares vest. The fair value of the RSA awards granted with the right to receive dividends and 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 expense 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 vested immediately. The RSAs generally vested in one-third increments on each of April 23, 2020 and 2021 and will vest as to the final one-third increment on April 23, 2022 and 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 lapse of such restrictions.
iA
summary of the RSA activity for the year ended December 31, 2021 is as follows:
(1) i9,024
of these RSAs were withheld to satisfy employee tax withholding obligations.
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 expense of such RSUs was determined using the closing share price on the applicable date of grant, which is then applied to the total number of RSUs granted. Brigham Minerals accounts for forfeitures as they occur. Brigham
Minerals withheld i181,182 RSUs to satisfy employee tax withholding obligations totaling $i3.8
million, related to the RSUs that vested in 2021.
A summary of the RSU activity for the year ended December 31, 2021 is as follows:
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. Expense related to these PSUs is recognized on a straight-line basis over the length of the applicable performance period. All compensation expense related to the market-based
F-30
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
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 Company granted i753,546 PSUs (based on target) on April 23,
2019, with a performance period that ends on December 31, 2021. On December 31, 2021, i714,350 PSUs vested, based on i94.8%
achievement of target, i39,196 PSUs were forfeited, and i271,521
PSUs totaling $i5.7 million were withheld to satisfy employee tax withholding obligations. During the year ended December 31, 2020, i434,265
PSUs (based on target) were granted with a performance period that ends on December 31, 2022. During the year ended December 31, 2021, i472,378 PSUs (based on target) were granted with a performance period that ends on December 31, 2023.
iUsing the assumptions in the table below, Brigham Minerals estimated the fair value of PSUs to be $i17.02,
$i6.41 and $i12.18,
for PSUs granted in 2021, 2020 and 2019, respectively./
Share-based compensation expense is included in general and administrative expense in the Company’s consolidated statement of operations. iShare-based compensation expense recorded for each type of share-based compensation award, was as follows for the periods indicated:
Years
Ended December 31,
(In Thousands)
2021
2020
2019
Incentive Units (1) (3)
$
i712
$
i712
$
i2,904
RSAs
(2) (3)
i623
i1,254
i3,972
RSUs
(3)
i10,128
i7,390
i4,630
PSUs
(4)
i6,288
i4,259
i2,361
Capitalized
share-based compensation (5) (6)
(i8,048)
(i6,086)
(i3,818)
Total
share-based compensation expense
$
i9,703
$
i7,529
$
i10,049
(1) Includes
a cumulative effect adjustment to share-based compensation expense of $i2.0 million pertaining to the period from the grant date through the IPO date. No compensation expense was recorded prior to the IPO because the IPO was not considered probable.
(2) Includes $i3.2
million recorded at grant date of April 23, 2019, associated with i152,742 RSAs, which vested immediately during the year ended December 31, 2019.
(3) 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.
(4) 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.
(5) During the year ended December 31, 2021, Brigham Minerals capitalized $i3.6
million of the share-based compensation to unevaluated property and $i4.4 million to evaluated property on its consolidated balance sheet.
(6) Brigham Minerals capitalizes a portion of the share-based compensation expense incurred after the IPO.
F-31
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 December 31, 2021, a portion of which will be capitalized:
(In
Thousands)
Incentive Units
RSAs
RSUs
PSUs
Total
Year
2022
$
i534
$
i200
$
i5,815
$
i4,030
$
i10,579
2023
i—
i—
i2,822
i3,063
i5,885
Total
$
i534
$
i200
$
i8,637
$
i7,093
$
i16,464
11. iIncome
Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Brigham Minerals periodically assesses whether it is more likely than not that
it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, Brigham Minerals considers all available positive and negative evidence and makes certain assumptions. Brigham Minerals considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends and its outlook for future years. Brigham Minerals' management believes that it is more likely than not that the results of future operations will generate sufficient taxable income to realize the deferred tax assets and as a result, Brigham Minerals did not record a valuation allowance at December 31, 2021 and 2020.
Brigham Minerals has evaluated all tax positions for which the statute of limitations remains
open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2021 and 2020, Brigham Minerals had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.
Brigham Resources, the Company’s predecessor, is a limited liability company that is not subject to U.S. federal income tax, but is subject to the Texas Margin Tax and state income taxes in Oklahoma, North Dakota, and Colorado. As part of the corporate reorganization, certain entities affiliated with Warburg Pincus contributed all of their respective interests in certain wholly owned “blocker” entities through which they held interests in Brigham Resources
to Brigham Minerals in exchange for all of the outstanding shares of common stock of Brigham Minerals. On the date of the corporate reorganization, a corresponding “first day” tax charge of approximately $i3.1 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of the investment in Brigham Resources. The offset of the deferred tax liability was recorded to additional paid-in-capital.
Brigham Minerals is a corporation and is subject to U.S. federal income tax. In April 2019, Brigham
Minerals completed the IPO of i16,675,000 shares of Class A common stock at a price to the public of $i18.00 per share. The tax implications of the July 2018
restructuring, IPO and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying consolidated financial statements. On IPO date, a corresponding tax benefit of approximately $i13.7 million was recorded associated with the differences between the tax and book basis of the investment in Brigham Resources. The
offset of the deferred tax asset was recorded to additional paid-in capital.
After the December 2019 Offering, as discussed in "Note 1—Business and Basis of Presentation", a corresponding tax benefit of approximately $i9.5 million was recorded associated with the differences between the tax and book basis of the investment in Brigham Resources. After the June 2020 Secondary Offering and September 2020 Secondary Offering,
and corresponding redemptions, as discussed in "Note 1—Business and Basis of Presentation", a corresponding reduction to the tax benefit of approximately $i0.8 million and $i2.8 million,
respectively, was recorded associated with the differences between the tax and book basis of the investment in Brigham Resources. The offset of the deferred tax asset was recorded to additional paid-in capital.
The effective combined U.S. federal and state income tax rate for the year ended December 31, 2021 was i19%. During the year endedDecember 31,
2021, the Company recognized income tax expense of $i16.3 million. During the years ended
F-32
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2020
and 2019, the Company recognized income tax benefit of $i12.8 million and income tax expense of $i2.7
million, respectively. Total income tax expense for the years ended December 31, 2021, 2020 and 2019 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due to the impact of the temporary equity, net income attributable to Predecessor, state taxes (net of the anticipated federal benefit), and percentage depletion in excess of basis.
i
Years
Ended December 31,
(In Thousands)
2021
2020
2019
State Income Tax
Current expense
$
i270
$
i122
$
i692
Deferred
expense/(benefit)
i2,182
(i1,876)
i63
Federal
Income Tax
Current expense/(benefit)
i10,217
(i2,942)
i1,322
Deferred
expense/(benefit)
i3,584
(i8,066)
i602
Totals:
$
i16,253
$
(i12,762)
$
i2,679
Total
current income tax expense/(benefit)
$
i10,487
$
(i2,820)
$
i2,014
Total
deferred income tax expense/(benefit)
i5,766
(i9,942)
i665
Totals:
$
i16,253
$
(i12,762)
$
i2,679
/
i
The
following table reconciles the income tax provision with income tax expense at the federal statutory rate for the periods indicated:
Years Ended December 31,
(In Thousands)
2021
2020
2019
Income
(loss) before income taxes
$
i84,279
$
(i70,756)
$
i24,318
Less:
income before income taxes attributable to predecessor
i—
i—
i5,118
Less:
income (loss) before income taxes attributable to non-controlling interests and temporary equity
i17,851
(i15,270)
i9,858
Income
(loss) before income taxes attributable to stockholders
$
i66,428
$
(i55,486)
$
i9,342
Income
tax at the federal statutory rate
$
i13,950
$
(i11,652)
$
i1,962
State
income taxes, net of federal benefit
i540
(i1,223)
i717
State
rate change (1)
i1,397
i—
i—
Other
federal tax effects
i366
i113
i—
Total
income tax provision
$
i16,253
$
(i12,762)
$
i2,679
(1) We
recorded $i1.4 million in deferred tax expenses to remeasure our deferred tax assets based on the tax rates that are expected to apply as the asset is realized in future periods.
/
Brigham Minerals had $i25.3
million and $i24.9 million recorded as deferred tax asset as of December 31, 2021 and 2020. iThe
tax effects of temporary differences that give rise to significant portions of the deferred tax assets were are follows:
Years Ended December 31,
(In Thousands)
2021
2020
Deferred tax assets:
Loss
carryforwards
$
i441
$
i627
Investment
in subsidiary
i25,102
i24,405
Total
deferred tax assets:
$
i25,543
$
i25,032
Deferred
tax liabilities:
Oil and gas properties
$
(i235)
$
(i112)
Total
deferred tax liabilities
$
(i235)
$
(i112)
F-33
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12.iCommitments and Contingencies
Contingencies
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 December 31, 2021 and December 31, 2020.
13. iRelated-Party
Transactions
Brigham Land Management (“BLM”) occasionally provides us with land brokerage services. The services are provided at market prices and are periodically verified by third-party quotes. BLM is owned by Vince Brigham, an advisor to us and brother of Ben M. Brigham, founder and Executive Chairman of the Board. For the year ended December 31, 2021, 2020 and 2019 the amounts paid to BLM for land brokerage services were immaterial. At December 31, 2021, 2020 and 2019, the liabilities recorded for services performed
by BLM were immaterial.
We provide certain services to Brigham Earth, LLC and affiliated entities. These include IT services and certain software, phone and equipment licenses. The IT services are passed through at our cost, which includes an allocable share of employee salary and administrative expenses. The software, phone and equipment licenses are passed through at our direct costs. Brigham Earth, LLC and its affiliated entities are owned in part by Ben M. Brigham, our founder and Executive Chairman of the Board.
Brigham Exploration Company, partially owned by Ben M. Brigham, on occasion leases some of our acreage at market rates. Brigham Minerals did not lease any acreage to Brigham Exploration Company during the years
ended December 31, 2021 and 2020. We received $i0.4 million for the year ended December 31, 2019 in connection with such leases.
14. iCOVID-19
Pandemic and Impact on Global Demand for Oil and Natural Gas
The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, remains a global pandemic, however, with the gradual easing of COVID-19 lockdown restrictions globally, primarily due to the increase in accessibility of vaccines and demand for the commodities produced by the oil and natural gas industry have continued to improve. In addition, commodity prices in 2021 have improved substantially from historic lows in 2020 and the current outlook on commodity prices is generally favorable. However, the duration of COVID-19 pandemic and potential future impact to our business and industry continues to be unpredictable and dynamic.
Winter Storm Uri
In February 2021, Winter Storm Uri caused severe winter weather and freezing temperatures in the
southern United States, which effected our properties in the Permian and Anadarko Basins, resulting in the curtailment of a portion of our production, delays in drilling and completion of wells, other operational constraints and ultimately adversely impacted our first quarter 2021 production. These curtailments, delay and operational constraints also resulted in increases in commodity prices, primarily natural gas prices. For example, the Henry Hub spot market price for natural gas for the month of February 2021 ranged from a low of $2.66 per MMBtu to a high of $23.86 per MMBtu. Given we do not operate our properties, Brigham Minerals had limited visibility into the timing of when production resumed and was required to estimate the amount of production delivered to the purchaser and the price that would ultimately be received for the sale of the product.
15. iSubsequent
Events
On February 10, 2022, Brigham Minerals entered into a definitive purchase and sale agreement to acquire approximately i1,800 net royalty acres in the Midland Basin largely operated by Pioneer Natural Resources and Endeavor Energy Resources for approximately $i15 million
in cash and approximately i800,000 shares of Class A common stock subject to certain closing adjustments.
On February 18, 2022, Brigham Minerals declared a dividend of $i0.45
per Class A common stock payable on March 25, 2022, to stockholders of record at the close of business on March 18, 2022.
F-34
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16.Reserve and Related Financial Data (SMOG) - Unaudited
Oil and Natural Gas Reserves
Proved
reserves represent quantities of oil, natural gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
i
The
reserves at December 31, 2021, 2020 and 2019 presented below were audited by CG&A. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in various fields in Texas, New Mexico, Oklahoma, Colorado, Wyoming, North Dakota, and Montana. All of the proved reserves are located in the continental United States.
Proved
undeveloped reserves at December 31, 2021 attributable to temporary equity
i715
i1,862
i285
i1,310
/
F-35
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in proved reserves that occurred during 2021 were primarily due to:
•the acquisition of additional mineral interests located in the Permian, DJ and Williston Basins in multiple transactions. The acquired proved reserves of i6,849 MBoe throughout the year were
offset by the divestiture of i275 MBoe of proved reserves;
•well additions, extensions and discoveries of approximately i3,024
MBoe, as gross horizontal well locations were converted from probable, possible and contingent resources to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests;
•positive revision of i3,591 MBoe attributable to an increase in SEC pricing; and
•positive revision of i852
MBoe due to PDP outperformance, estimate ultimate recovery ("EUR") adjustments, refined gas and NGL processing assumptions, and unit configuration.
Changes in proved reserves that occurred during 2020 were primarily due to:
•the acquisition of additional mineral interests located in the Permian, Anadarko, DJ and Williston Basins in multiple transactions. The acquired proved reserves of i2,174
MBoe throughout the year were offset by the divestiture of i48 MBoe of proved reserves;
•well additions, extensions and discoveries of approximately i1,591
MBoe, as approximately i342 gross horizontal well locations were converted from probable, possible and contingent resources to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests;
•negative revisions of i2,645
MBoe attributable to reduction in SEC pricing;
•as a result of decreased operator activity throughout 2020, a reclass of i7,036 MBoe to non-proved due to future locations falling outside the SEC five-year rule for PUDs; and
•positive revision of i1,410
MBoe attributable to estimate ultimate recovery ("EUR") adjustments, refined gas and NGL processing assumptions, and unit configuration.
Changes in proved reserves that occurred during 2019 were primarily due to:
•the acquisition of additional mineral interests located in the Permian, Anadarko, DJ and Williston Basins in multiple transactions, which included i7,242 MBoe
of additional proved reserves which is comprised of i7,651 MBoe of acquired proved reserves and divestiture of i409
MBoe of proved reserves within the year;
•well additions extensions and discoveries of approximately i4,110 MBoe, as approximately i900
gross horizontal well locations were converted from probable, possible and contingent resources to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests; and
•net volume revisions of approximately i2,299 MBoe. These revisions were comprised of i902
MBoe of negative revisions attributable to pricing as well as approximately i1,397 MBoe attributable to operator development timing, unit configuration and EUR adjustments to existing proved locations.
Standardized Measure of Discounted Future Net Cash Flows
Guidelines prescribed in FASB’s Accounting Standards Codification (“ASC”) Topic 932 Extractive Industries—Oil and Gas, have
been followed for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect Brigham Resources’ expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are
the basis for the valuation
F-36
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
i
The
following summary sets forth the future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932:
For the Years Ended December 31,
(In Thousands)
2021
2020
2019
Future
crude oil, natural gas, and NGL sales
$
i1,512,784
$
i562,545
$
i1,042,118
Future
severance tax and ad valorem taxes
(i109,849)
(i39,318)
(i73,627)
Future
income tax expense
(i214,311)
(i46,908)
(i143,599)
Future
net cash flows
i1,188,624
i476,319
i824,892
10%
annual discount
(i549,768)
(i205,551)
(i359,258)
Standardized
measure of discounted future net cash flows
$
i638,856
$
i270,768
$
i465,634
Standardized
measure of discounted future net cash flows attributable to temporary equity
$
i121,383
$
i62,853
$
i186,999
/
i
The
following prices were used in the determination of standardized measure:
These
prices were based on the 12-month arithmetic average first-of-month West Texas Intermediate (“WTI”) price of oil and Henry Hub price of natural gas. The NGL pricing varied by basin at i29% to i41%
of WTI. All p rices have been adjusted for transportation, quality, basis differentials and post-production costs.
i
The principal sources of change in the standardized measure of discounted future net cash flows are:
For
the Years Ended December 31,
(In Thousands)
2021
2020
2019
Standardized measure of discounted future net cash flows, beginning of the year
$
i270,768
$
i465,634
$
i443,459
Changes
in the year resulting from:
Sales, less production costs
(i140,561)
(i73,654)
(i86,492)
Revisions
of previous quantity estimates
i106,664
(i135,926)
(i41,539)
Extensions,
discoveries, and other additions
i74,305
i21,011
i69,057
Net
change in prices and production costs
i268,687
(i131,886)
(i99,660)
Accretion
of discount
i23,763
i54,741
i51,949
Purchase
of reserves in place
i151,547
i27,241
i137,819
Divestitures
of reserves in place
(i2,375)
(i250)
(i5,783)
Net
change in taxes
(i87,960)
i53,786
(i5,739)
Timing
differences and other
(i25,982)
(i9,929)
i2,563
Standardized
measure of discounted future net cash flows, end of the year
$
i638,856
$
i270,768
$
i465,634
/
F-37
BRIGHAM
MINERALS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Capitalized oil and natural gas costs
The aggregate amounts of costs capitalized for oil and natural gas producing activities and related aggregate amounts of accumulated depletion follow:
For the Years Ended December 31,
(In
Thousands)
2021
2020
2019
Oil and gas properties, at cost, using full cost method of accounting:
Unevaluated property
$
i338,613
$
i325,091
$
i291,664
Evaluated
property
i633,138
i488,301
i449,061
Total
oil and gas properties, at cost
i971,751
i813,392
i740,725
Less
accumulated depreciation, depletion, and amortization
(i239,612)
(i189,546)
(i61,103)
Total
oil and gas properties, net
$
i732,139
$
i623,846
$
i679,622
Costs
incurred in oil and natural gas activities
The following costs were incurred in oil and natural gas producing activities:
For the Years Ended December 31,
(In Thousands)
2021
2020
2019
Acquisition
of oil and gas properties
Unevaluated
$
i51,934
$
i35,725
$
i78,093
Evaluated
i98,377
i30,856
i140,025
Total
$
i150,311
$
i66,581
$
i218,118
F-38
Dates Referenced Herein and Documents Incorporated by Reference
