UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ց Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2024
or
տ Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition Period from to
Commission File Number: 000-50175
DORCHESTER MINERALS, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
81-0551518
(I.R.S. Employer Identification No.)
3838 Oak Lawn Avenue, Suite 300
Dallas, Texas 75219
(Address of principal executive offices) (Zip Code)
(214) 559-0300
(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
Common Units Representing Limited Partnership Interest
DMLP
NASDAQ Global Select Market
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Title of Class
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes տ No ց
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes տ No ց
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. Yes ց No տ
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).Yes ց No տ
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.
Large accelerated filer ց
Accelerated filer տ
Non-accelerated filer տ
Smaller reporting company տ
Emerging growth company տ
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. տ
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. ց
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements. տ
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). տ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.). Yes տ No ց
The aggregate market value of the common units held by non-affiliates of the registrant (treating all managers, executive officers and
10% unitholders of the registrant as if they may be affiliates of the registrant) was approximately $1,148,558,065 as of the last business
day of the registrant’s most recently completed second fiscal quarter, based on $30.85 per unit, the closing price of the common units as
reported on the NASDAQ Global Select Market on such date.
Number of Common Units outstanding as of February 20, 2025: 47,339,756
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant's 2025 Annual Meeting of Unitholders are incorporated by reference in Part
III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2024.
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TABLE OF CONTENTS
PART I
ITEM 1.
BUSINESS ...........................................................................................................................
1
ITEM 1A. RISK FACTORS ...................................................................................................................
7
ITEM 1B. UNRESOLVED STAFF COMMENTS ...................................................................................... 26
ITEM 1C. CYBERSECURITY ............................................................................................................... 26
ITEM 2.
PROPERTIES ....................................................................................................................... 27
ITEM 3.
LEGAL PROCEEDINGS ........................................................................................................ 31
ITEM 4.
MINE SAFETY DISCLOSURES ............................................................................................. 31
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES .......................................................... 32
ITEM 6.
[RESERVED] ....................................................................................................................... 33
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS .............................................................................................. 34
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ....................... 41
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .................................................. 42
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE ................................................................................................ 43
ITEM 9A. CONTROLS AND PROCEDURES .......................................................................................... 43
ITEM 9B.
OTHER INFORMATION ....................................................................................................... 43
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURSIDICTIONS THAT PREVENT INSPECTIONS ......... 43
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE ............................... 44
ITEM 11.
EXECUTIVE COMPENSATION ............................................................................................. 44
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED UNITHOLDER MATTERS ................................................................................. 44
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE .............................................................................................................. 44
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES ................................................................ 44
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES ........................................................ 45
ITEM 16.
FORM 10-K SUMMARY ....................................................................................................... 46
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS ................................................................ 47
SIGNATURES ....................................................................................................................................... 50
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS ..................................................................... F-1
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1
PART I.
ITEM 1. BUSINESS
General
Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that commenced operations on January 31,
2003, upon the combination of Dorchester Hugoton, Ltd., Republic Royalty Company, L.P. and Spinnaker Royalty
Company, L.P. Dorchester Hugoton was a publicly traded Texas limited partnership, and Republic and Spinnaker were
private Texas limited partnerships. We have established a website at www.dmlp.net that contains the last annual meeting
presentation and a link to the NASDAQ website. You may obtain all current filings free of charge at our website. We will
provide electronic or paper copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and amendments to those reports filed or furnished to the Securities and Exchange Commission (“SEC”) free of
charge upon written request at our executive offices. In this report, the term "Partnership," as well as the terms "us," "our,"
"we," and "its" are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals,
L.P. and its related entities.
Our general partner is Dorchester Minerals Management LP, which is managed by its general partner, Dorchester
Minerals Management GP LLC. As a result, the Board of Managers of Dorchester Minerals Management GP LLC
exercises effective control of the Partnership. In this report, the term "General Partner" is used as an abbreviated reference
to Dorchester Minerals Management LP. Our General Partner also controls and owns, directly and indirectly, all of the
Partnership interests in Dorchester Minerals Operating LP and its general partner. Dorchester Minerals Operating LP owns
working interests and other properties underlying our Net Profits Interest (or “NPI”), provides day-to-day operational and
administrative services to us and our General Partner, and is the employer of all the employees who perform such services.
In this report, the term "Operating Partnership" is used as an abbreviated reference to Dorchester Minerals Operating LP.
Our General Partner and the Operating Partnership are Delaware limited partnerships, and the general partners of their
general partners are Delaware limited liability companies.
On July 12, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties,
the Partnership acquired mineral and royalty interests totaling approximately 900 net royalty acres located in 13 counties
and parishes across Louisiana, New Mexico, and Texas in exchange for 343,750 common units representing limited
partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
On August 31, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third
parties, the Partnership acquired mineral and royalty interests totaling approximately 568 net royalty acres located in three
counties in Texas in exchange for 374,000 common units representing limited partnership interests in the Partnership issued
pursuant to the Partnership’s registration statement on Form S-4.
On September 29, 2023, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party,
the Partnership acquired mineral and royalty interests totaling approximately 716 net royalty acres located in three counties
in Texas in exchange for 494,000 common units representing limited partnership interests in the Partnership issued
pursuant to the Partnership’s registration statement on Form S-4.
On March 28, 2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third
parties, the Partnership acquired mineral interests totaling approximately 1,485 net royalty acres located in two counties in
Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership issued
pursuant to the Partnership’s registration statement on Form S-4.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party,
the Partnership acquired overriding royalty interests totaling approximately 1,204 net royalty acres located in Weld
County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership
issued pursuant to the Partnership’s registration statement on Form S-4.
2
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals
LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton
Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership,
Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited
partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and
Carrollton Royalty, LP, a Texas limited partnership, the Partnership acquired mineral, royalty, and overriding royalty
interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres
located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited
partnership interests in the Partnership issued pursuant to the Partnership’s registration statements on Form S-4.
Our primary business objective is to provide an attractive yield to our unitholders by focusing on strategically
managing our assets and protecting our balance sheet, while maintaining a best-in-class cost structure. We intend to
accomplish this objective by executing the following strategies:
Ɣ
Capitalize on the development of the properties underlying our mineral interests. Production from our
mineral interests could increase as operators continue to drill, complete and develop our acreage. We expect to
benefit from continued operator development and believe the new production will help offset other mature
property production declines.
Ɣ
Seek to acquire from time to time, accretive mineral or other interests in producing oil and natural gas
properties that meet our acquisition criteria. Since our formation, we have acquired, and may have additional
opportunities from time to time in the future to acquire, mineral, royalty, or net profits interests in producing or
non-producing oil and natural gas properties. We prefer to issue equity as consideration in contribution and
exchange transactions.
Ɣ
Maintain a conservative capital structure. Since our formation, we have maintained a conservative capital
structure that has allowed us to opportunistically purchase accretive mineral and royalty interests. Our partnership
agreement prohibits leverage which aids in our ability to successfully operate in challenging business and
commodity price environments.
We are currently focused on the acquisition, ownership, and administration of Royalty Properties and NPI. The NPI
represents a net profits overriding royalty interest burdening various properties owned by the Operating Partnership. We
receive monthly payments equaling 96.97% of the net profits realized by the Operating Partnership from these properties in
the preceding month. The Royalty Properties consist of producing and nonproducing mineral, royalty, overriding royalty,
net profits, and leasehold interests located in 594 counties and parishes in 28 states (“Royalty Properties”).
Our partnership agreement requires that we make a quarterly distribution in an amount equal to 100% of available
cash. Available cash is defined as all cash and cash equivalents of the Partnership on hand at the end of that quarter
(including any previously reserved cash for acquisitions that has not been used on or prior to the last business day of that
quarter other than cash proceeds received by the Partnership from a public or private offering of securities of the
Partnership and cash proceeds from a sale of assets of the Partnership that the Partnership intends to use in an asset swap or
other similar transaction), less the amount of any cash reserves that our General Partner determines is necessary or
appropriate to provide for the conduct of the Partnership’s business or to comply with applicable laws or agreements or
obligations to which we may be subject, provided, however, that cash reserves for acquisitions may only be excluded from
the calculation of available cash to the extent such reservation does not exceed the cash reserve limitation. The cash reserve
limitation is defined as 10% of the Partnership's aggregate cash distributions for the two immediately prior quarters,
provided that any cash reserved for acquisitions in any prior period (other than a reservation made in the immediately prior
quarter) that has not been used for, or otherwise committed to, an acquisition on or prior to the last business day of such
quarter shall no longer be reserved from available cash. Our practice is to accrue funds quarterly for amounts incurred
throughout the year but invoiced and paid annually or semi-annually (e.g. ad valorem taxes and professional services).
These amounts generally are not held for periods over one year.
3
Our partnership agreement allows us to grow by acquiring additional oil and natural gas properties, subject to the
limitations described below. The approval of the holders of a majority of our outstanding common units is required for our
General Partner to cause us to acquire or obtain any oil and natural gas property interest, unless the acquisition is
complementary to our business and is made either:
Ɣ
in exchange for our limited partner interests, including common units, not exceeding 40% of the common units
outstanding after issuance; or
Ɣ
in exchange for cash proceeds of any public or private offer and sale of limited partner interests, including
common units, or options, rights, warrants, or appreciation rights relating to the limited partner interests, including
common units; or
Ɣ
in exchange for other cash from our operations, if the aggregate cost of any acquisitions made for cash during the
twelve-month period ending on the first to occur of the execution of a definitive agreement for the acquisition or
its consummation is no more than the cash reserve limitation, as defined above; or
Ɣ
in exchange for any combination of the foregoing clauses
Credit Facilities and Financing Plans
We do not have a credit facility in place, nor do we anticipate doing so. We do not anticipate incurring any debt, other
than trade debt incurred in the ordinary course of our business. To the extent necessary to avoid unrelated business taxable
income, our partnership agreement prohibits us from incurring indebtedness, excluding trade payables, in excess of $50,000
in the aggregate at any given time or which would constitute "acquisition indebtedness" (as defined in Section 514 of the
Internal Revenue Code of 1986, as amended). We may finance any growth of our business through acquisitions of oil and
natural gas properties by issuing additional limited partnership interests or with cash, subject to the limits described above
and in our partnership agreement.
Under our partnership agreement, we may also finance our growth through the issuance of additional partnership
securities, including options, rights, warrants and appreciation rights with respect to partnership securities from time to time
in exchange for the consideration and on the terms and conditions established by our General Partner in its sole discretion.
However, we may not issue limited partnership interests that would represent over 40% of the outstanding limited
partnership interests immediately after giving effect to such issuance or that would have greater rights or powers than our
common units without the approval of the holders of a majority of our outstanding common units. Except in connection
with qualifying acquisitions, we do not currently anticipate issuing additional partnership securities. We have an effective
registration statement registering 10,000,000 common units that may be offered and issued by the Partnership from time to
time in connection with asset acquisitions or other business combination transactions. At present, 7,340,018 units remain
available under the Partnership’s registration statement.
Regulation
Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state
agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which
frequently increases the regulatory burden on affected members of the industry. These laws and regulations have the
potential to impact production on our properties, which could materially adversely affect our business and our prospects.
Numerous federal, state, and local governmental agencies issue regulations that carry substantial administrative, civil, and
criminal penalties and may result in injunctive obligations for non-compliance. Such regulation includes:
Ɣ
permits for the drilling of wells;
Ɣ
bonding requirements in order to drill or operate wells;
Ɣ
the location and number of wells;
Ɣ
the method of drilling and completing wells;
Ɣ
the surface use and restoration of properties upon which wells are drilled;
4
Ɣ
the plugging and abandonment of wells;
Ɣ
numerous federal and state safety requirements;
Ɣ
environmental requirements;
Ɣ
property taxes and severance taxes; and
Ɣ
specific state and federal income tax provisions.
The strict, joint, and several liability nature of such laws and regulations could impose liability on our operators
regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste
products into the environment. The long-term trend in environmental regulation has been towards more stringent
regulations, and any changes that impact our operators and result in more stringent and costly pollution control could
materially adversely affect our business and prospects.
Oil and natural gas operations are also subject to various conservation laws and regulations. These regulations govern
the size of drilling and spacing units or proration units and the density of wells that may be drilled and the unitization or
pooling of oil and natural gas properties. In addition, state conservation laws establish a maximum allowable production
from oil and natural gas wells. These state laws also generally prohibit the venting or flaring of natural gas and impose
certain requirements regarding the ratability of production. These regulations can limit the amount of oil and natural gas
that the operators of our properties can produce.
The transportation of oil and natural gas after sale by operators of our properties is sometimes subject to regulation by
state authorities. The interstate transportation of oil and natural gas is subject to federal governmental regulation, including
regulation of tariffs and various other matters, primarily by the Federal Energy Regulatory Commission.
Significant Customers
If we were to lose a significant customer, such loss could impact revenue. The loss of any single customer is mitigated
by our diversified customer base and individually insignificant properties, and we do not believe that the loss of any single
customer would have a long-term material adverse effect on our financial position or results of operations. Royalty
revenues from properties operated by Exxon Mobil Corporation and Diamondback Energy, Inc., together, represented
approximately 31% of total operating revenues for the year ended December 31, 2024.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater
resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and
refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies
may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid
for and purchase a greater number of properties and prospects than our financial or human resources permit. Our larger or
more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, and local laws
and regulations more easily than we can, which would adversely affect our competitive position.
Our ability to acquire additional mineral, royalty, overriding royalty, net profits and similar interests in the future will
be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly
competitive environment mainly by issuing equity. In addition, because we have fewer financial and human resources than
many companies in our industry, we may be at a disadvantage in bidding for these and other oil and natural gas properties.
Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. 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.
5
Business Opportunities Agreement
Pursuant to a business opportunities agreement among us, our General Partner, the general partner of our General
Partner, and the owners of the general partner of our General Partner (the “GP Parties”), we have agreed that, except with
the consent of our General Partner, which it may withhold in its sole discretion, we will not engage in any business not
permitted by our partnership agreement, and we will have no interest or expectancy in any business opportunity that does
not consist exclusively of the oil and natural gas business within a designated area that includes portions of Texas County,
Oklahoma and Stevens County, Kansas. All opportunities that are outside the designated area or are not oil and natural gas
business activities are called renounced opportunities.
The parties also have agreed that, as long as the activities of the General Partner, the GP Parties and their affiliates or
manager designees are conducted in accordance with specified standards, or are renounced opportunities:
Ɣ
our General Partner, the GP Parties and their affiliates or the manager designees will not be prohibited from
engaging in the oil and natural gas business or any other business, even if such activity is in direct or indirect
competition with our business activities;
Ɣ
affiliates of our General Partner, the GP Parties and their affiliates and the manager designees will not have to
offer us any business opportunity;
Ɣ
we will have no interest or expectancy in any business opportunity pursued by affiliates of our General Partner,
the GP Parties or their affiliates and the manager designees; and
Ɣ
we waive any claim that any business opportunity pursued by our General Partner, the GP Parties or their
affiliates and the manager designees constitutes a corporate opportunity that should have been presented to us.
The standards specified in the business opportunities agreement generally provide that the GP Parties and their
affiliates and manager designees must conduct their business through the use of their own personnel and assets and not with
the use of any personnel or assets of us, our General Partner or Operating Partnership. A manager designee or personnel of
a company in which any affiliate of our General Partner or any GP Party or their affiliates has an interest or in which a
manager designee is an owner, director, manager, partner or employee (except for our General Partner and its general
partner and their subsidiaries) is not allowed to usurp a business opportunity solely for his or her personal benefit, as
opposed to pursuing, for the benefit of the separate party an opportunity in accordance with the specified standards.
In certain circumstances, if a GP Party or any subsidiary thereof, any officer of the general partner of our General
Partner or any of their subsidiaries, or a manager of the general partner of our General Partner that is an affiliate of a GP
Party signs a binding agreement to purchase oil and natural gas interests, excluding oil and natural gas working interests,
then such party must notify us prior to the consummation of the transactions so that we may determine whether to pursue
the purchase of the oil and natural gas interests directly from the seller. If we do not pursue the purchase of the oil and
natural gas interests or fail to respond to the purchasing party's notice within the provided time, the opportunity will also be
considered a renounced opportunity.
In the event any GP Party or one of their subsidiaries acquires an oil and natural gas interest, including oil and natural
gas working interests, in the designated area, it will offer to sell these interests to us within one month of completing the
acquisition. This obligation also applies to any package of oil and natural gas interests, including oil and natural gas
working interests, if at least 20% of the net acreage of the package is within the designated area; however, this obligation
does not apply to interests purchased in a transaction in which the procedures described above were applied and followed
by the applicable affiliate.
6
Operating Hazards and Uninsured Risks
Our operations do not directly involve the operational risks and uncertainties associated with drilling for, and the
production and transportation of, oil and natural gas. However, we may be indirectly affected by the operational risks and
uncertainties faced by the operators of our properties, whose operations may be materially curtailed, delayed or canceled as
a result of numerous factors, including:
Ɣ
the presence of unanticipated pressure or irregularities in formations;
Ɣ
accidents;
Ɣ
title problems;
Ɣ
weather conditions;
Ɣ
compliance with governmental requirements; and
Ɣ
shortages or delays in the delivery of equipment.
Also, the ability of the operators of our properties to market oil and natural gas production depends on numerous
factors, many of which are beyond their control, including:
Ɣ
capacity and availability of oil and natural gas systems and pipelines;
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effect of federal and state production and transportation regulations;
Ɣ
changes in supply and demand for oil and natural gas; and
Ɣ
creditworthiness of the purchasers of oil and natural gas.
The occurrence of an operational risk or uncertainty that materially impacts the operations of the operators of our
properties could have a material adverse effect on the amount that we receive in connection with our interests in production
from our properties, which could have a material adverse effect on our financial condition or result of operations.
In accordance with customary industry practices, we maintain insurance against some, but not all, of the risks to which
our business exposes us. While we believe that we are reasonably insured against these risks, the occurrence of an
uninsured loss could have a material adverse effect on our financial condition or results of operations.
Human Capital Resources
Employees
As of February 20, 2025, the Operating Partnership had 27 full-time employees in our Dallas, Texas corporate office.
Our workforce is our most important asset, and we structure compensation and benefit programs to attract and retain high
quality colleagues while providing a flexible hybrid work environment. Our compensation and benefit programs include but
are not limited to cash and equity bonuses, a SEP IRA plan, insurance plans, and long-term incentives. We support
employees in continual training and professional skill development. We offer annual training on compliance, safety, and
leadership.
Diversity and Inclusion
We are committed to and value hiring employees with varied personal and professional backgrounds, perspectives and
experiences, promoting a culture of diversity and inclusion. The diversity of our employees is a tremendous asset, and we
are firmly committed to providing equal opportunity in all aspects of employment and will not tolerate acts of
discrimination or harassment. We are committed to employing and advancing in employment all persons without regard to
their race, color, sex, religion, national origin, citizenship, age, gender identity, sexual orientation, marital status, genetic
information, veteran status, disability, or other protected categories.
7
ITEM 1A. RISK FACTORS
Risks Related to Our Business
Our cash distributions are highly dependent on oil and natural gas prices, which have historically been very volatile.
Our quarterly cash distributions depend significantly on the prices realized from the sale of natural gas and, in
particular, oil. Historically, the markets for oil and natural gas have been volatile and may continue to be volatile in the
future. Various factors that are beyond our control will affect prices of oil and natural gas, such as:
Ɣ
the worldwide and domestic supplies of oil and natural gas;
Ɣ
the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and
maintain oil prices and production controls;
Ɣ
political instability or armed conflict in oil-producing regions;
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the price and level of foreign imports;
Ɣ
the level of consumer demand;
Ɣ
the price and availability of alternative fuels;
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the availability of pipeline capacity;
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technological advances affecting energy consumption;
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weather conditions;
Ɣ
domestic and foreign governmental regulations and taxes; and
Ɣ
the overall economic environment.
Lower oil and natural gas prices may reduce the amount of oil and natural gas that is economic to produce and may
reduce our revenues and operating income. The volatility of oil and natural gas prices reduces the accuracy of estimates of
future cash distributions to unitholders.
We do not control operations and development of the Royalty Properties or the properties underlying the NPIs that the
Operating Partnership does not operate, which could impact the amount of our cash distributions.
As the owner of a fractional undivided mineral or royalty interest, we do not control the development of the Royalty or
NPI properties or the volumes of oil and natural gas produced from them, and our ability to influence development of
nonproducing properties is severely limited. Also, since one of our stated business objectives is to avoid the generation of
unrelated business taxable income, we are prohibited from participation in the development of our properties as a working
interest or other expense-bearing owner. The decision to explore or develop these properties, including infill drilling,
exploration of horizons deeper or shallower than the currently producing intervals, and application of enhanced recovery
techniques will be made by the operator and other working interest owners of each property (including our lessees) and may
be influenced by factors beyond our control, including but not limited to oil and natural gas prices, interest rates, budgetary
considerations and general industry and economic conditions.
Our unitholders are not able to influence or control the operation or future development of the properties underlying the
NPIs. The Operating Partnership is unable to influence the operations or future development of properties that it does not
operate. The current operators of the properties underlying the NPIs are under no obligation to continue operating the
underlying properties. Our unitholders do not have the right to replace an operator.
8
Our lease bonus revenue depends in significant part on the actions of third parties, which are outside of our control.
Significant portions of the Royalty Properties are unleased mineral interests. With limited exceptions, we have the right
to grant leases of these interests to third parties. We anticipate receiving cash payments as bonus consideration for granting
these leases in most instances. Our ability to influence third parties' decisions to become our lessees with respect to these
nonproducing properties is severely limited, and those decisions may be influenced by factors beyond our control, including
but not limited to oil and natural gas prices, interest rates, budgetary considerations, and general industry and economic
conditions.
The Operating Partnership may transfer or abandon properties that are subject to the NPIs.
Our General Partner, through the Operating Partnership, may at any time transfer all or part of the properties
underlying the NPIs. Our unitholders are not entitled to vote on any transfer; however, any such transfer must also
simultaneously include the NPIs at a corresponding price.
The Operating Partnership or any transferee may abandon any well or property if it reasonably believes that the well or
property can no longer produce in commercially economic quantities. This could result in termination of the NPIs relating
to the abandoned well or property.
Cash distributions are affected by production and other costs, most of which are outside of our control.
The cash available for distribution that comes from our royalty and mineral interests, including the NPIs, is directly
affected by increases in production costs and other costs. Most of these costs are outside of our control, including costs of
regulatory compliance and severance and other similar taxes. Other expenditures are dictated by business necessity, such as
drilling additional wells in response to the drilling activity of others.
Our oil and natural gas reserves and the underlying properties are depleting assets, and there are limitations on our
ability to replace them.
Our revenues and distributions depend in large part on the quantity of oil and natural gas produced from properties in
which we hold an interest. Over time, all of our producing oil and natural gas properties will experience declines in
production due to depletion of their oil and natural gas reservoirs, with the rates of decline varying by property.
Replacement of reserves to maintain production levels requires maintenance, development or exploration projects on
existing properties, or the acquisition of additional properties.
The timing and size of maintenance, development or exploration projects will depend on the market prices of oil and
natural gas and on other factors beyond our control. All of the decisions regarding implementation of such projects,
including drilling or exploration on any unleased and undeveloped acreage, will be made by third parties.
Our ability to increase reserves through future acquisitions is limited by restrictions on our use of operating cash and
limited partnership interests for acquisitions and by our General Partner's obligation to use all reasonable efforts (such as
limiting acquisitions to acquisitions of NPIs and royalty interests) to avoid unrelated business taxable income. In addition,
the ability of affiliates of our General Partner to pursue business opportunities for their own accounts without tendering
them to us in certain circumstances may reduce the acquisitions presented to us for consideration.
Acreage must be drilled before lease expiration, generally within three 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 terminate 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 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.
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Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the
unavailability of equipment, services, or supplies, could result in the expiration of existing leases. If the lease governing any
of our mineral interests expires or terminates, all development rights typically revert back to us, and we may seek new
lessees to explore and develop such mineral interests or in some states remain unleased. If the lease underlying any of our
ORRIs expires or terminates, our ORRIs that are derived from such lease will also terminate. Any such expirations or
terminations of our leases or our ORRIs could materially and adversely affect our financial condition, results of operations
and cash flow.
If our operators suspend our right to receive royalty payments due to title or other issues, our business, financial
condition, results of operations and cash flows may be adversely affected.
Our business depends, in part, on acquisitions which contribute to the growth of our reserves, production and cash
generated from operations. In connection with these acquisitions, we are conveyed record title to mineral and royalty
interests. Due to such changes in ownership of mineral interests, the operator of the underlying property has the right, at
such operator’s discretion, to investigate and verify the title and ownership of mineral and royalty interests with respect to
the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with
customary industry standards, the operator has the right to suspend payment of the related royalty. If an operator of our
properties is not satisfied with the documentation we provide to validate our ownership, such operator may suspend our
royalty payment until such issues are resolved, at which time we would receive the full royalty payment which we would
have otherwise received if not for the payment being suspended, without interest. Certain of our operators impose
burdensome documentation requirements for title transfer and may keep royalty payments in suspense for significant
periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable
mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty
interest. If a significant amount of our royalty interests are placed in suspense, our results of operations and cash flow may
be materially affected.
Title to the properties in which we have an interest may be impaired by title defects.
In our discretion, 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 have a significant adverse effect on the value of an interest and can
further materially adversely affect our results of operations, financial condition and cash flows.
We may experience delays in received royalty payments 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 experience delays in receiving royalty payments from our operators, including as a result of delayed division
orders received by our operators. Typically, the failure of an operator to make royalty payments to which we are entitled,
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 cannot guarantee finding a suitable
replacement operator in such a circumstance 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 bankruptcy 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 at risk. In general, in a proceeding
under the Bankruptcy Code, the bankrupt operator would have an extended period of time to decide whether to ultimately
reject or assume the lease, which could significantly delay or prevent the execution of a new lease or the assignment of the
existing lease to a replacement operator. In the event that an operator rejects the lease, our ability to collect amounts owed
to us 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, there is no guarantee that such replacement operator
will achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.
We do not currently plan to enter into hedging arrangements with respect to the oil and natural gas production from our
properties, and we will be exposed to the impact of decreases in the price of oil and natural gas.
We do not currently plan to enter into hedging arrangements to establish, in advance, a price for the sale of the oil and
natural gas produced from our properties. As a result, although we may realize the benefit of any short-term increase in the
price of oil and natural gas, we will not be protected against decreases in the price of oil and natural gas or prolonged
periods of low commodity prices, which could materially adversely affect our business, results of operation and cash
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available for distribution. If we enter into hedging arrangements in the future, it may limit our ability to realize the benefit
of rising prices and may result in hedging losses.
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 or greater access to capital. Many of these companies explore for and produce
oil and natural gas, 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 when market prices of oil and natural gas are low. Our operators’ larger competitors may be able to better
address the burden of present and future federal, state, local and other laws and regulations more easily than our operators
can, which could adversely affect our operators’ competitive position. Our operators may have access to 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 natural 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 cannot guarantee our
ability to acquire additional properties and to discover reserves in the future as this will be dependent upon our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Drilling activities on our properties may not be productive, which could have an adverse effect on future results of
operations and financial condition.
The Operating Partnership may participate in drilling activities in limited circumstances on the properties underlying
the NPIs, and third parties may undertake drilling activities on our properties. Any increases in our reserves will come from
such drilling activities or from acquisitions.
Drilling involves a wide variety of risks, including the risk that no commercially productive oil or natural gas
reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling
operations may be delayed or canceled as a result of a variety of factors, including:
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pressure or irregularities in formations;
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equipment failures or accidents;
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unexpected drilling conditions;
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shortages or delays in the delivery of equipment;
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adverse weather conditions; and
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disputes with drill-site owners.
Future drilling activities on our properties may not be successful. If these activities are unsuccessful, this failure could
have an adverse effect on our future results of operations and financial condition. In addition, under the terms of the NPIs,
the costs of unsuccessful future drilling on the working interest properties that are subject to the NPIs will reduce amounts
payable to us under the NPIs by 96.97% of these costs.
Our ability to identify and capitalize on acquisitions is limited by contractual provisions and substantial competition.
Our partnership agreement limits our ability to acquire oil and natural gas properties in the future, especially for
consideration other than our limited partnership interests or cash proceeds of a securities offering. Because of the
limitations on our use of operating cash for acquisitions and on our ability to accumulate operating cash for acquisition
purposes, we may be required to attempt to effect acquisitions by first selling our securities to raise cash or by issuing our
limited partnership interests. However, we may be unable to sell our securities in sufficient quantities and for sufficient
consideration to provide adequate consideration to fund an acquisition, and sellers of properties we would like to acquire
may be unwilling to take our limited partnership interests in exchange for properties.
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Our partnership agreement obligates our General Partner to use all reasonable efforts to avoid generating unrelated
business taxable income. Accordingly, to acquire working interests we would have to arrange for them to be converted into
overriding royalty interests, net profits interests, or another type of interest that does not generate unrelated business taxable
income. Third parties may be less likely to deal with us than with a purchaser to which such a condition would not apply.
These restrictions could prevent us from pursuing or completing business opportunities that might benefit us and our
unitholders, particularly unitholders who are not tax-exempt investors.
The duty of affiliates of our General Partner to present acquisition opportunities to our Partnership is limited, pursuant
to the terms of the business opportunities agreement. Accordingly, business opportunities that could potentially be pursued
by us might not necessarily come to our attention, which could limit our ability to pursue a business strategy of acquiring
oil and natural gas properties.
We compete with other companies and producers for acquisitions of oil and natural gas interests. Many of these
competitors have substantially greater financial and other resources than we do.
Any future acquisitions will involve risks that could adversely affect our business, which our unitholders generally will
not have the opportunity to evaluate.
Our current strategy contemplates that we may grow through acquisitions and development of our undeveloped
property. We expect to participate in discussions relating to potential acquisition and investment opportunities. If we
consummate any additional acquisitions and investments, our capitalization and results of operations may change
significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant
information that we will consider in connection with the acquisition, unless the terms of the acquisition require approval of
our unitholders. Additionally, our unitholders will bear 100% of the dilution from issuing new common units while
receiving essentially 96% of the benefit as 4% of the benefit goes to our General Partner.
Acquisitions and business expansions involve numerous risks, including assimilation difficulties, unfamiliarity with
new assets or new geographic areas and the diversion of management's attention from other business concerns. In addition,
the success of any acquisition will depend on a number of factors, including the ability to estimate accurately the
recoverable volumes of reserves, rates of future production and future net revenues attributable to reserves and to assess
possible environmental liabilities. Our review and analysis of properties prior to any acquisition will be subject to
uncertainties and, consistent with industry practice, may be limited in scope. We may not be able to successfully integrate
any oil and natural gas properties that we acquire into our operations, or we may not achieve desired profitability
objectives.
A natural disaster or catastrophe could damage pipelines, gathering systems and other facilities that service our
properties, which could substantially limit our operations and adversely affect our cash flow.
If gathering systems, pipelines or other facilities that serve our properties are damaged by any natural disaster,
accident, catastrophe or other event, our income could be significantly interrupted. Any event that interrupts the production,
gathering or transportation of our oil and natural gas, or which causes us to share in significant expenditures not covered by
insurance, could adversely impact the market price of our limited partnership units and the amount of cash available for
distribution to our unitholders. We do not carry business interruption insurance.
A significant portion of the properties subject to the NPIs are geographically concentrated, which could cause net
proceeds payable under the NPIs to be impacted by regional events.
A significant portion of the properties subject to the NPIs are properties located in the Bakken region and Permian
Basin. Because of this geographic concentration, any regional events, including natural disasters that increase costs, reduce
availability of equipment, services, or supplies, reduce demand or limit production may impact the net proceeds payable
under the NPIs more than if the properties were more geographically diversified.
Under the terms of the NPIs, much of the economic risk of the underlying properties is passed along to us.
Under the terms of the NPIs, virtually all costs that may be incurred in connection with the properties, including
overhead costs that are not subject to an annual reimbursement limit, are deducted as production costs or excess production
costs in determining amounts payable to us. Therefore, to the extent of the revenues from the burdened properties, we bear
96.97% of the costs of the working interest properties. If costs exceed revenues, we do not receive any payments under the
NPIs. However, except as described below, we are not required to pay any excess costs.
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The terms of the NPIs provide for excess costs that cannot be charged currently because they exceed current revenues
to be accumulated and charged in future periods, which could result in us not receiving any payments under the NPIs until
all prior uncharged costs have been recovered by the Operating Partnership.
Our cash flow is subject to operating hazards and unforeseen interruptions for which we may not be fully insured.
Neither we nor the Operating Partnership are fully insured against certain risks, either because such full insurance is
not available or because of high premium costs. Operations that affect the properties are subject to all of the risks normally
incident to the oil and natural gas business, including blowouts, cratering, explosions, and pollution and other
environmental damage, any of which could result in substantial decreases in the cash flow from our royalty interests and
other interests due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-
up responsibilities, regulatory investigations and penalties and suspension of operations. Any uninsured costs relating to the
properties underlying the NPIs will be deducted as a production cost in calculating the net proceeds payable to us.
Governmental policies, laws and regulations could have an adverse impact on our business and cash distributions.
Our business and the properties in which we hold interests are subject to federal, tribal, state and local laws and
regulations relating to the oil and natural gas industry as well as regulations relating to environmental, health, and safety
matters. These laws and regulations can have a significant impact on production and costs of production. Regulators have
the ability, directly or indirectly, to limit production from our properties, and such limitations or changes in those
limitations could negatively impact us in the future.
Cyber incidents or attacks targeting our systems and infrastructure used by the oil and natural gas industry may
adversely impact our operations, and if we are unable to obtain and maintain adequate protection of our data, our
business may be adversely impacted.
We and our operators increasingly rely on information technology systems to operate our respective businesses, and
the oil and natural gas industry depends on digital technologies in exploration, development, production, and processing
activities. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks
continue to grow. Our technologies, systems, networks, including third party software, cloud services and other internally
and externally hosted hardware and software platforms, and those of the operators of our properties, vendors, suppliers, and
other business partners, may become the target of cyberattacks or information security breaches that could result in the
unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other
disruption of business activities. In addition, certain cyber incidents, such as surveillance, may remain undetected for some
period of time. While we utilize various procedures and controls to mitigate exposure to such risk, cyber incidents and
attacks are evolving and unpredictable. Our information technology systems and any insurance coverage for protecting
against cybersecurity risks may not be sufficient. As cyber security threats continue to evolve, we may be required to
expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any
vulnerability to cyber incidents. It is possible that our business, finances, systems and assets could be compromised in a
cyber attack.
The Partnership may be adversely affected by price volatility in the oil and natural gas markets.
Historically, there has been price volatility in the oil and natural gas markets, which have been impacted by a number
of factors, including actions by oil producing nations. For example, after OPEC and a group of oil producing nations led by
Russia failed in March 2020 to agree on oil production cuts, Saudi Arabia announced that it would cut oil prices and
increase production, leading to a sharp decline in oil and natural gas prices. While OPEC, Russia and other oil producing
countries reached an agreement in April 2020 to reduce production levels, and U.S. production declined, oil prices
remained lower than in previous years on account of an oversupply of oil and natural gas, with a simultaneous decrease in
demand as a result of the impact of COVID-19 on the global economy. Thereafter, in 2021, oil and natural gas prices
significantly rebounded. However, global military conflicts, fluctuating interest rates, changes in tariff rates, global supply
chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent
inflation, and actions taken by OPEC and its non-OPEC allies, collectively OPEC+, continued to contribute to economic
and pricing volatility during 2024. Oil and natural gas markets remain subject to price volatility, which may have a material
adverse effect on our cash distributions in periods of lower prices. During periods of substantial declines in prices, such as
in 2020, oil and natural gas operators on our properties may suspend drilling programs, which would impact our revenues
and operating income. In the event that any wells on our properties are shut-in, restarting wells may require significant costs
from our operators, and we cannot guarantee that they would be able to restart at the same level. Moreover, due to the
extremely volatile market conditions, we are unable to predict the degree or duration of any adverse impact on our
operations and financial condition and other risks in our industry may be enhanced by such conditions.
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Continuing or worsening inflationary issues and associated changes in federal monetary policy may result in increases to
the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and
operating costs to rise and may delay or restrict their exploration and development activities.
Recently, the U.S. has had periods of high inflation. These inflationary pressures may result in increases to the costs of
the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise.
Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest
rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which, or the
combination thereof, could hurt the financial and operating results of our operators’ businesses. If our operators are unable
to secure the goods, services and labor necessary for their operations at reasonable costs, their exploration and development
activities could be delayed or restricted, which in turn could have a material adverse effect on our financial condition,
results of operations and free cash flow.
Regulatory and Environmental Risk Factors
Environmental costs and liabilities and changing environmental regulation could affect our cash flow.
As with other companies engaged in the ownership and production of oil and natural gas, we always have possible risk
of exposure to environmental costs and liabilities because of the costs associated with environmental compliance or
remediation. The properties in which we hold interests are subject to extensive federal, state, tribal and local regulatory
requirements relating to environmental affairs, health and safety and waste management. Governmental authorities have the
power to enforce compliance with applicable regulations and permits, which could increase production costs on our
properties and affect their cash flow. Third parties may also have the right to pursue legal actions to enforce compliance.
Because we do not directly operate our properties, our direct liability under environmental laws is limited. It is likely,
however, that expenditures in connection with environmental matters, individually or as part of normal capital expenditure
programs, will affect the net cash flow from our properties. Future environmental law developments, such as stricter laws,
regulations or enforcement policies, could significantly increase the costs of production from our properties and reduce our
cash flow.
The following is a summary of some of the existing environmental laws, rules and regulations that apply to oil and
natural gas operations, and that may indirectly affect our cash flow.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the
Superfund law, and comparable state statutes impose strict liability (i.e., no showing of “fault” is required), and under
certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release
of a hazardous substance into the environment. The term “hazardous substance” is specifically defined to exclude
petroleum, including crude oil and any fraction thereof, natural gas and natural gas liquids. Despite this exclusion, certain
materials that are commonly used in connection with oil and natural gas operations are considered to be hazardous
substances under CERCLA. Responsible persons include the current or former owner or operator of the site where the
release occurred, and anyone who disposed of or arranged for the disposal of a hazardous substance released at the site,
regardless of whether the disposal of hazardous substances was lawful at the time of the disposal. Under CERCLA, such
persons may be subject to strict, joint and several liabilities for the costs of investigating releases of hazardous substances,
cleaning up the hazardous substances that have been released into the environment, damages to natural resources
and certain health studies. In addition, 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
operators of our properties may be responsible under CERCLA for all or part of these costs. Although we are not an
operator, our ownership of royalty interests could cause us to be responsible for all or part of such costs to the extent that
CERCLA imposes such responsibilities on such parties as “owners.”
The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation,
transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced
water and many other wastes associated with the exploration, development and production of oil or natural gas are currently
excluded from regulation under RCRA’s hazardous waste provisions. However, it is possible that certain oil and natural gas
exploration and production wastes could be classified as hazardous wastes in the future. In addition, exploration and
production wastes are regulated under state laws analogous to RCRA. Many of our properties have produced oil and/or
natural gas for many years. We have no knowledge of current and prior operators’ procedures with respect to the disposal
of oil and natural gas wastes. Hydrocarbons or other solid or hazardous wastes may have been released on or under our
properties by the operators or prior operators. Our properties and the materials disposed or released on, at, under or from
them may be subject to CERCLA, RCRA and analogous state laws, and removal or remediation of such materials could be
required by a governmental authority.
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The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air
emissions permitting programs and other requirements, such as emissions controls. Existing laws and regulations and
possible future laws and regulations may require our operators to obtain pre-approval for the expansion or modification of
existing facilities or the construction of new facilities expected to produce air emissions and may impose stringent air
permit requirements or mandate the use of specific equipment or technologies to control emissions. The U.S.
Environmental Protection Agency (“EPA”) continues to develop New Source Performance standards for oil and natural gas
facilities. On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic
compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and
natural gas sector. However, on August 13, 2020, in response to an executive order by President Trump, the EPA amended
the New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to
transmission or storage segments and eliminating methane requirements altogether. On June 30, 2021, President Biden
signed into law a joint resolution of Congress disapproving the 2020 amendments, with the exception of some technical
changes, thereby reinstating the prior standards. The EPA expects owners and operators of regulated sources to take
“immediate steps” to comply with these standards. Additionally, on March 8, 2024, the EPA published a final rule that
would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas
industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and
tank batteries, and prohibiting venting of natural gas in certain situations. Federal changes will affect state air permitting
programs in states that administer the federal CAA under a delegation of authority, including states in which we have
operations. These new standards, to the extent implemented, as well as any future laws and their implementing regulations,
may require our operators to obtain pre-approval for the expansion or modification of existing facilities or the construction
of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific
equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to our
operators to comply with such requirements with any certainty.
The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws impose
restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other
substances into regulated waters, including wetlands. The discharge of pollutants into regulated waters is prohibited, except
in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the
United States Army Corps of Engineers (“USACOE”). The scope of waters regulated under the CWA has fluctuated in
recent years. On June 29, 2015, the EPA and the USACOE jointly promulgated a final rule expanding the scope of “Waters
of the United States” (“WOTUS”), which would have made additional waters subject to the jurisdiction of the Clean Water
Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 WOTUS rule, and then, on April
21, 2020, the EPA and the USACOE published a final rule replacing the 2015 rule and significantly reducing the waters
subject to federal regulation under the CWA. On August 30, 2021, a federal court struck down the replacement rule and, on
January 18, 2023, the EPA and the USACOE published a final rule that would restore water protections that were in place
prior to 2015. However, on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of
“waters of the United States” protected under the CWA. On September 8, 2023, the EPA and the USACOE published a
final rule conforming their regulations to the decision. These recent actions have provided some clarity. To the extent the
EPA and the USACOE broadly interpret their jurisdiction and expand the range of properties subject to the CWA’s
jurisdiction, our operators could face increased costs and delays with respect to obtaining permits for dredge and fill
activities in wetland areas, which could cause delays in development and/or increase the cost of development and operation
of those properties.
Spill prevention, control, and countermeasure (“SPCC”) regulations promulgated under the CWA and later amended
by the Oil Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages
resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of
certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be
expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other
requirements of the CWA and analogous state laws and regulations.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to
obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the
EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas
extraction facilities to publicly owned wastewater treatment plants. Costs may be associated with the treatment of
wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling
the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that
require permits for discharges or operations that may impact groundwater conditions.
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Various federal laws, including the Endangered Species Act and the Migratory Bird Treaty Act, and analogous state
laws, restrict activities that may adversely affect listed endangered or threatened species or their habitat. If endangered or
threatened species are located on our properties, operations on those properties could be prohibited or delayed or expensive
mitigation may be required. Also, the United States Fish and Wildlife Service (“USFWS”) may designate critical habitat
and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical
habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use
and could delay or prohibit land access, development or operations (including prevent oil and natural gas exploration or
production). Additionally, the designation of previously unprotected species in areas where we operate as endangered or
threatened could result in the imposition of restrictions on our operators and consequently have a material adverse effect on
our business.
Oil and natural gas operations are subject to the requirements of the federal Occupational Safety and Health Act
(“OSHA”) and comparable state statutes and their implementing regulations. The OSHA hazard communication standard,
the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management
Planning regulations promulgated under section 112(r) of the CAA and similar state statutes may require disclosure of
information about hazardous materials used, produced or otherwise managed during operation. These laws also require the
development of risk management plans for certain facilities to prevent accidental releases of extremely hazardous
substances and to minimize the consequences of such releases should they occur.
The potential adoption of federal and state hydraulic fracturing laws or executive orders could delay or restrict
development of our oil and natural gas properties.
Hydraulic fracturing is an important, common practice that is used to stimulate production of hydrocarbons from tight
formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into
formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas
commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water
Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require
federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of
the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over
certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing
diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II”
Underground Injection Control wells under the SDWA. Future federal laws or regulations could require hydraulic
fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications,
fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. Such federal
legislation or regulation could lead to operational delays or increased operating costs and could result in additional
regulatory burdens that could make it more difficult to perform hydraulic fracturing.
In addition, on March 26, 2015, the Bureau of Land Management (“BLM”) published a final rule governing hydraulic
fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing,
implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of
detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the
depths of all usable water. Also, on November 18, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking
of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an
executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise
them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. A
coalition of environmentalists, tribal advocates and the State of California filed lawsuits challenging the rule rescission.
Also, on September 28, 2018, the BLM published a final rule to revise the 2016 methane rule; however, a federal court
struck down the scaled-back rule on July 15, 2020, and shortly thereafter, on October 8, 2020, another federal court struck
down the 2016 methane rule. On April 10, 2024, the BLM published a final replacement rule to reduce the waste of natural
gas from venting, flaring and leaks during oil and natural gas production activities on federal and Indian lands, which
would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring.
On April 24, 2024, several states challenged the 2024 waste prevention rule in federal court, which has resulted in a
preliminary injunction against the BLM enforcing the rule in North Dakota, Texas, Montana, Wyoming, and Utah. Also, on
April 23, 2024, the BLM published a final rule to update its oil and gas leasing regulations, which increases bonding
requirements and raises royalty rates. Each of these regulations, to the extent that they are implemented, reinstated or
modified, may result in additional levels of regulation or complexity that could lead to operational delays, increased
operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and
increase costs of compliance.
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Additionally, certain states in which our properties are located, including Oklahoma, Texas and Wyoming, have
adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public
disclosure and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing
activities altogether. For example, pursuant to legislation adopted by the State of Texas in June 2011, the Railroad
Commission of Texas enacted a rule in December 2011, requiring public disclosure of certain information regarding
additives, chemical ingredients, concentrations and water volumes used in hydraulic fracturing. In addition to state laws,
local land use restrictions, such as city ordinances, may restrict or prohibit well drilling in general and/or hydraulic
fracturing in particular. In response to a 2014 ballot initiative by the voters of the City of Denton, Texas banning hydraulic
fracturing, the Texas legislature enacted a statute preempting local government regulation of oil and natural gas activities,
including hydraulic fracturing. In other states, however, local governments may retain the ability to directly or indirectly
regulate hydraulic fracturing. State and local governments may also seek to regulate or recover costs of activities
tangentially associated with hydraulic fracturing, such as increased truck traffic. In the event state, local, or municipal legal
restrictions are adopted in areas where our properties are located, the cost of the operators of our oil and natural gas
properties to comply with such requirements may be significant in nature, which may cause delays or curtailment in the
pursuit of exploration, development, or production activities, and perhaps even preclude the operators from drilling wells.
Some states have become concerned about the connection between hydraulic fracturing-related activities, particularly
the injection or disposal of produced water, and the increased occurrence of seismic activity, and they have adopted or are
considering additional regulations regarding such activities. Changes in regulations or the inability to obtain permits for
new disposal wells in the future may affect the ability of the operators of the Royalty Properties and the operators of the
working interests and other properties underlying our NPIs to dispose of produced water and ultimately increase the cost of
operation of the Royalty Properties and the working interests and other properties underlying our NPIs or delay production
schedules. Certain state agencies, including those in Texas and Oklahoma, have implemented regulations authorizing the
imposition of certain limitations on existing wells if seismic activity increases in the area of an injection well, including a
temporary injection ban. For example, in Oklahoma, the Oklahoma Corporations Commission (“OCC”) has implemented a
variety of measures, including the adoption of the National Academy of Science’s “traffic light system,” pursuant to which
the agency reviews new disposal well applications and may restrict operations at existing wells. Beginning in 2013, the
OCC has ordered the reduction of disposal volumes into the Arbuckle formation. More recently, the OCC directed the shut
in of a number of disposal wells due to increased earthquake activity in the Arbuckle formation and imposed further
disposal well volume reductions in the Covington, Crescent, Enid, and Edmond areas. The Texas Railroad Commission has
also implemented measures to assess the potential for seismic activity in the vicinity of disposal wells, and it has restricted
and indefinitely suspended disposal well activities in some cases. Moreover, vigorous public debate over hydraulic
fracturing and shale gas production continues and has resulted in delays of well permits in some areas.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental
aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for
hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water
in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report
with findings and recommendations related to public concern about induced seismic activity from disposal wells. The
report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events.
Other governmental agencies have also evaluated or are evaluating various other aspects of hydraulic fracturing. These
ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it
more difficult or costly for our operators to perform fracturing and increase their costs of compliance and doing business.
Climate change legislation or regulations could result in increased operating costs and reduced demand for the oil and
natural gas production from our properties.
In recent years, federal, state, and local governments have taken steps to reduce emissions of greenhouse gases
(“GHGs”), though policy changes at the federal level have caused uncertainty. For example, the Infrastructure Investment
and Jobs Act of 2021 and the Inflation Reduction Act of 2022 (“IRA”) include billions of dollars in incentives for the
development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and
supporting infrastructure and carbon capture and sequestration. Also, in March 2024, the EPA finalized ambitious rules to
reduce harmful air pollutant emissions, including GHGs, from light-, medium-, and heavy-duty vehicles beginning in
model year 2027, which could decrease demand for, and in turn the prices of, oil and natural gas and adversely impact our
business.
In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge.
Specifically, the IRA amends the Clean Air Act to impose a fee on the emission of methane that exceeds an applicable
waste emissions threshold from sources required to report their GHG emissions to the EPA, including sources in the
offshore and onshore petroleum and natural gas production and gathering and boosting source categories. In
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implemented, methane emissions charge could increase our operators’ costs, which could adversely impact our business,
financial condition and cash flows. However, on January 20, 2025, President Trump signed multiple executive orders
seeking to reverse these climate incentives, including pausing the disbursement of funds under the IRA. The same day,
President Trump also issued executive orders to encourage fossil fuel production and exploration on federal lands and
waters, while moving away from renewable energy and electric vehicles. Such actions have the potential to impact prior
efforts to transition the economy away from the use of fossil fuels and towards lower or zero-carbon emissions alternatives.
The EPA has also finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas
industry, and almost half of the states have taken measures to reduce GHG emissions primarily through the development of
GHG emission inventories and/or regional GHG cap and trade programs. The cap and trade programs require major sources
of emissions or major fuel producers to acquire and surrender emission allowances corresponding with their annual
emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission
reduction goal is achieved. Many states also have enacted renewable portfolio standards, which require utilities to purchase
a certain percentage of their energy from renewable fuel sources. In addition, states have imposed increasingly stringent
requirements related to the venting or flaring of natural gas during oil and natural gas operations.
At the international level, the United States has been involved in negotiations regarding GHG reductions under the
United Nations Framework Convention on Climate Change (“UNFCCC”). The U.S. was among approximately 195 nations
that signed an international accord in December 2015, the so called Paris Agreement, which became effective on November
4, 2016, with the objective of limiting GHG emissions. On April 21, 2021, the United States announced that it was setting
an economy-wide target of reducing its GHG emissions by 50-52 percent below 2005 levels by 2030. In November 2021,
in connection with Glasgow Climate Pact, the United States and other world leaders made further commitments to reduce
GHG emissions, including reducing global methane emissions by at least 30 percent by 2030 from 2020 levels. More than
150 countries have now signed on to this pledge. Most recently, at the 28th Conference of the Parties in the United Arab
Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple
renewables and double energy efficiency globally by 2030. Additionally, the Biden Administration announced a new
climate target for the United States on December 19, 2024, which included a 61-66 percent reduction in economy-wide net
greenhouse gas emissions by 2035, as compared to 2005 levels. Many state and local leaders have stated their intent to
intensify efforts to support the international climate commitments. Though President Trump issued an executive order on
January 20, 2025, directing the United States Ambassador to the United Nations to immediately withdraw from the Paris
Agreement, it is possible that the Paris Agreement and other domestic and international regulatory requirements will have
an adverse effect on the demand for oil and natural gas products.
Although it is not possible at this time to predict whether or when Congress may adopt additional climate change
legislation, or whether EPA may promulgate additional regulation of GHGs from the oil and natural gas industry, any laws
or regulations that may be adopted to restrict or reduce emissions of GHGs could require oil and natural gas operators that
develop our properties to incur increased operating costs and could have an adverse effect on demand for the oil and natural
gas produced from our properties.
It should also be noted that, recently, activists concerned about the potential effects of climate change have directed
their attention at sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions,
funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. In addition,
spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for
corporate transparency and a demonstrated commitment to sustainability goals. Environmental, social, and governance
(“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social
responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the
industry. While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies
with robust ESG programs in place. The SEC published final rules on March 28, 2024, relating to the disclosure of a range
of climate-related risks and other information. Several lawsuits have been filed challenging the rules. In April 2024, the
SEC agreed to pause the rules to facilitate an orderly judicial resolution. To the extent the rules are implemented, the
Partnership, our operators and/or our customers could incur increased costs related to the assessment and disclosure of
climate-related information. Enhanced climate disclosure requirements could also accelerate any trend by certain
stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain
carbon intensive sectors. Ultimately, these initiatives could make it more difficult to secure funding for exploration and
production activities.
Finally, climate change may be associated with extreme weather conditions such as more intense hurricanes,
thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate
change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to
experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can
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interfere with our operators’ activities and increase their costs and damage resulting from extreme weather may not be fully
insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm
or weather hazards affecting our operations.
Our oil and natural gas reserve data and future net revenue estimates are uncertain.
Estimates of proved reserves and related future net revenues are projections based on engineering data and reports of
independent consulting petroleum engineers hired for that purpose. The process of estimating reserves requires substantial
judgment, resulting in imprecise determinations. Different reserve engineers may make different estimates of reserve
quantities and related revenue based on the same data. Therefore, those estimates should not be construed as being accurate
estimates of the current market value of our proved reserves. If these estimates prove to be inaccurate, our business may be
adversely affected by lower revenues. We are affected by changes in oil and natural gas prices. Oil prices and natural gas
prices may experience inverse price changes.
The outcome of pending litigation related to the Dakota Access Pipeline and any related executive orders could have a
material adverse effect on our revenue and cash distributions.
In connection with ongoing litigation initiated in February 2017 by the Standing Rock Sioux Tribe and the Cheyenne
River Sioux Tribe contesting the validity of the process used by the USACOE to permit the Dakota Access Pipeline, on
July 6, 2020, the United States District Court for the District of Columbia (the “Court”) issued an order vacating the
USACOE’s easement for the Dakota Access Pipeline and requiring that the pipeline be shut down by August 5, 2020.
Dakota Access, LLC and the USACOE appealed the decision. On July 14, 2020, the Court of Appeals granted a temporary
administrative stay, and on January 26, 2021, the Court of Appeals affirmed that part of the lower court decision vacating
the USACOE’s easement while it prepares a new environmental impact statement, but reversed the lower court’s order to
shut down the pipeline. Since then, both the Biden Administration and the Court have declined to shut down the pipeline,
and on June 22, 2021, the Court dismissed the subject lawsuit. The Court noted, however, that future challenges were
possible depending on the outcome of the ongoing environmental study, which the USACOE issued in draft form on
September 8, 2023. On October 14, 2024, the Standing Rock Sioux Tribe filed a new lawsuit in the U.S. District Court for
the District of Columbia, alleging that the USACOE is allowing the pipeline to operate without the necessary easement and
without an appropriate environmental impact statement. The USACOE and Dakota Access Pipeline filed motions to
dismiss the case on January 17, 2025, though the matter remains pending. Accordingly, the continued operation of Dakota
Access Pipeline in the future is uncertain. While this litigation does not directly impact our operations, we derive a
significant amount of revenue from the Royalty Properties and NPIs we hold in the Bakken region, the region for which the
Dakota Access Pipeline is intended to be a key pipeline. The outcome of this litigation may have a material adverse effect
on our Royalty and NPI revenues derived from the Bakken region based on the timing of future development of wells on, or
production of oil and natural gas from, or the method and cost of transportation related to the production on the properties.
We have no control over the operation of such properties.
Risks Inherent In An Investment In Our Common Units
Cost reimbursement due our General Partner may be substantial and reduce our cash available to distribute to our
unitholders.
Prior to making any distribution on the common units, we reimburse the General Partner and its affiliates for
reasonable costs and expenses of management. The reimbursement of expenses could adversely affect our ability to pay
cash distributions to our unitholders. Our General Partner has sole discretion to determine the amount of these expenses,
subject to the annual limit of 5% of an amount primarily based on our distributions to partners for that fiscal year. The
annual limit includes carry-forward and carry-back features, which could allow costs in a year to exceed what would
otherwise be the annual reimbursement limit. In addition, our General Partner and its affiliates may provide us with other
services for which we will be charged fees as determined by our General Partner.
Our net income as reported for tax and financial statement purposes may differ significantly from our cash flow that is
used to determine cash available for distributions.
Net income as reported for financial statement purposes is presented on an accrual basis in conformity with accounting
principles generally accepted in the United States of America. Unitholder Schedule K-1 tax statements are calculated based
on applicable tax conventions, and taxable income as calculated for each year will be allocated among unitholders who hold
units on the last day of each month. Distributions, however, are calculated on the basis of actual cash receipts, changes in
cash reserves, and disbursements during the relevant reporting period. Consequently, due to timing differences between the
receipt of proceeds of production and the point in time at which the production giving rise to those proceeds actually
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occurs, net income reported on our consolidated financial statements and on unitholder Schedule K-1 tax statements will
not reflect actual cash distributions during that reporting period.
Our unitholders have limited voting rights and do not control our General Partner, and their ability to remove our
General Partner is limited.
Our unitholders have only limited voting rights on matters affecting our business. The general partner of our General
Partner manages our activities. Our unitholders only have the right to annually elect the managers comprising the Advisory
Committee of the Board of Managers of the general partner of our General Partner. Our unitholders do not have the right to
elect the other managers of the general partner of our General Partner on an annual or any other basis.
Our General Partner may not be removed as our general partner except upon approval by the affirmative vote of the
holders of at least a majority of our outstanding common units (including common units owned by our General Partner and
its affiliates), subject to the satisfaction of certain conditions. Our General Partner and its affiliates do not own sufficient
common units to be able to prevent its removal as general partner, but they do own sufficient common units to make the
removal of our General Partner by other unitholders difficult.
These provisions may discourage a person or group from attempting to remove our General Partner or acquire control
of us without the consent of our General Partner. As a result of these provisions, the price at which our common units trade
may be lower because of the absence or reduction of a takeover premium in the trading price.
The control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may withdraw or transfer its general partner interest to a third party in a merger or in a sale of all
or substantially all of its assets without the consent of our unitholders. Other than some transfer restrictions agreed to
among the owners of our General Partner relating to their interests in our General Partner, there is no restriction in our
partnership agreement or otherwise for the benefit of our limited partners on the ability of the owners of our General
Partner to transfer their ownership interests to a third party. The new owner of the General Partner would then be in a
position to replace the management of our Partnership with its own choices.
A group of unitholders own a large percentage of our units and have the right to appoint a Manager to our Board of
Managers and may be able to exert significant influence over certain matters.
West Texas Minerals LLC and Carrollton Mineral Partners, LP, and certain affiliates, beneficially hold, in the
aggregate, approximately 6.9% of our outstanding Units. These unitholders, acting together, would be able to influence all
matters requiring unitholder approval and have the right to appoint a Manager to our Board of Managers, for so long as they
collectively hold an aggregate of at least 1,000,000 Units. For example, these unitholders would be able to influence
amendments of our organizational documents, or approval of any merger, sale of assets, or other major corporate
transaction.
Our General Partner and its affiliates have conflicts of interests, which may permit our General Partner and its affiliates
to favor their own interests to the detriment of unitholders.
We and our General Partner and its affiliates share, and therefore compete for, the time and effort of General Partner
personnel who provide services to us. Officers of our General Partner and its affiliates do not, and are not required to, spend
any specified percentage or amount of time on our business. In fact, our General Partner has a duty to manage our
Partnership in the best interests of our unitholders, but it also has a duty to operate its business for the benefit of its partners.
Some of our officers are also involved in management and ownership roles in other oil and natural gas enterprises and have
similar duties to them and devote time to their businesses. Because these shared officers function as both our
representatives and those of our General Partner and its affiliates and of third parties, conflicts of interest could arise
between our General Partner and its affiliates, on the one hand, and us or our unitholders, on the other, or between us or our
unitholders on the one hand and the third parties for which our officers also serve management functions. As a result of
these conflicts, our General Partner and its affiliates may favor their own interests over the interests of unitholders.
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We may issue additional securities, diluting our unitholders' interests.
We can and may issue additional common units and other capital securities representing limited partnership units,
including options, warrants, rights, appreciation rights and securities with rights to distributions and allocations or in
liquidation equal or superior to our common units; however, a majority of the unitholders must approve such issuance if (i)
the partnership securities to be issued will have greater rights or powers than our common units or (ii) if after giving effect
to such issuance, such newly issued partnership securities represent over 40% of the outstanding limited partnership
interests.
If we issue additional common units, it will reduce our unitholders' proportionate ownership interest in us. This could
cause the market price of the common units to fall and reduce the per unit cash distributions paid to our unitholders. In
addition, if we issued limited partnership units with voting rights superior to the common units, it could adversely affect our
unitholders' voting power.
Our unitholders may not have limited liability in the circumstances described below and may be liable for the return of
certain distributions.
Under Delaware law, our unitholders could be held liable for our obligations to the same extent as a general partner if a
court determined that the right of unitholders to remove our General Partner or to take other action under our partnership
agreement constituted participation in the "control" of our business.
Our General Partner generally has unlimited liability for the obligations of our Partnership, such as its debts and
environmental liabilities, except for those contractual obligations of our Partnership that are expressly made without
recourse to the General Partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under certain
circumstances, a unitholder may be liable for the amount of distribution for a period of three years from the date of
distribution.
Because we conduct our business in various states, the laws of those states may pose similar risks to our unitholders.
To the extent to which we conduct business in any state, our unitholders might be held liable for our obligations as if they
were general partners if a court or government agency determined that we had not complied with that state's partnership
statute, or if rights of unitholders constituted participation in the "control" of our business under that state's partnership
statute. In some of the states in which we conduct business, the limitations on the liability of limited partners for the
obligations of a limited partnership have not been clearly established.
We are dependent upon key personnel, and the loss of services of any of our key personnel could adversely affect our
operations.
Our continued success depends to a considerable extent upon the abilities and efforts of the senior management of our
General Partner, particularly William Casey McManemin, its Chief Executive Officer, and our Chief Executive Officer,
Bradley J. Ehrman, and Chief Financial Officer, Leslie A. Moriyama. The loss of the services of any of these key personnel
could have a material adverse effect on the results of our operations. We have not obtained insurance or entered into
employment agreements with any of these key personnel.
We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders.
There are a very limited number of service firms that currently perform the detailed computations needed to provide
each unitholder with estimated depletion and other tax information to assist the unitholder in various U.S. federal income
tax computations. There are also very few publicly traded limited partnerships that need these services. As a result, the
future costs and timeliness of providing Schedule K-1 tax statements to our unitholders is uncertain.
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Tax Risk Factors
The tax consequences to a unitholder of the ownership and sale of common units will depend in part on the unitholder’s
tax circumstances. Each unitholder should consult such unitholder’s own tax advisor about the federal, state and local
tax consequences of the ownership of common units.
We generally do not obtain rulings or assurances from the IRS or state or local taxing authorities on matters affecting us.
We generally have not requested, and do not intend to request, rulings from the Internal Revenue Service, or IRS, or
state or local taxing authorities with respect to owning and disposing of our common units or other matters affecting us. It
may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of those conclusions or
positions taken or expressed by us, and some or all of those conclusions or positions ultimately may not be sustained. Our
unitholders and General Partner will bear, directly or indirectly, the costs of any contest with the IRS or other taxing
authority. In 2020, we obtained a ruling from the IRS permitting us to aggregate the Minerals NPI, including the previously
aggregated Maecenas NPI, Bradley NPI, Republic NPI, and Spinnaker NPI for federal income tax purposes effective
January 1, 2020.
We will be subject to federal income tax and possibly certain state corporate income or franchise taxes if we are
classified as a corporation and not as a partnership for federal income tax purposes.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated
as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under
Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying
income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.
However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income
tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state income tax at varying
rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains,
losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our
cash available for distribution to our unitholders would be substantially reduced. In addition, changes in current state law
may subject us to additional entity-level taxation by individual states. Several states have subjected, or are evaluating ways
to subject, partnerships to entity-level taxation through the imposition of state income, franchise and other forms of
taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders.
Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a
material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction
in the value of our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential
legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our
common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time.
For example, from time to time, the President and members of Congress propose and consider substantive changes to the
existing U.S. federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax
treatment for publicly traded partnerships.
Under current law, we believe that our royalty income is qualifying income for purposes of Section 7704(d)(1)(E) of
the Internal Revenue Code of 1986, as amended (the “Code”). If the current law remains effective in its current form, we
believe we will continue to be able to meet the qualifying income requirement. However, there can be no assurance that
there will not be changes to the federal income tax laws or the Treasury Department's interpretation of the qualifying
income rules in a manner that could impact our ability to qualify as a partnership for federal income tax purposes in the
future.
Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied
and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or
otherwise adversely affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be
enacted. Any such changes could negatively impact the value of an investment in our common units.
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The recently enacted 20% deduction for certain pass-through income may not be available for our unitholders’ allocable
share of our net income, in which case our unitholders’ tax liability with respect to ownership and disposition of our
units may be materially higher than if the deduction is available.
For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual
taxpayer may generally claim a deduction in the amount of 20% of its allocable share of certain publicly traded partnership
income, including generally, among other items, the net amount of its items of income, gain, deduction, and loss from a
publicly traded partnership’s U.S. trade or business. Because we own only non-operated, passive mineral and royalty
interests, most or all of the income that we now generate, or will generate in the future, may not be “qualifying publicly
traded partnership income” eligible for the 20% deduction. If the deduction is not available, our unitholders’ tax liability
from ownership and disposition of our units may be materially higher than if the deduction is available. We urge our
unitholders to consult with their tax advisors regarding the availability of the 20% deduction on any income allocated from
us.
The IRS could reallocate items of income, gain, deduction and loss between transferors and transferees of common units
if the IRS does not accept our monthly convention for allocating such items.
In general, each of our items of income, gain, loss and deduction will, for federal income tax purposes, be determined
annually, and one twelfth of each annual amount will be allocated to those unitholders who hold common units on the last
business day of each month in that year. In certain circumstances we may make these allocations in connection with
extraordinary or nonrecurring events on a more frequent basis. As a result, transferees of our common units may be
allocated items of our income, gain, loss and deduction realized by us prior to the date of their acquisition of our common
units. The U.S. Treasury Department has issued final Treasury regulations that provide a safe harbor pursuant to which
publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferors and
transferee unitholders. Nonetheless, if the IRS challenges our method of allocation, our income, gain, loss and deduction
may be reallocated among our unitholders and our General Partner, and our unitholders may have more taxable income or
less taxable loss. Our General Partner is authorized to revise our method of allocation between transferors and transferees,
as well as among our other unitholders whose common units otherwise vary during a taxable period, to conform to a
method permitted or required by the Code and the regulations or rulings promulgated thereunder.
Our unitholders may not be able to deduct losses attributable to their common units.
Any losses relating to our unitholders’ common units will be losses related to portfolio income and their ability to use
such losses may be limited.
Our unitholders’ partnership tax information may be audited.
We will furnish our unitholders with a Schedule K-1 tax statement that sets forth their allocable share of income, gains,
losses and deductions. In preparing this schedule, we will use various accounting and reporting conventions and various
depreciation and amortization methods we have adopted. This schedule may not yield a result that conforms to statutory or
regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, and any
such audit could result in an audit of our unitholders’ individual income tax returns as well as increased liabilities for taxes
because of adjustments resulting from the audit. An audit of our unitholders’ returns also could be triggered if the tax
information relating to their common units is not consistent with the Schedule K-1 that we are required to provide to the
IRS.
Our unitholders may have more taxable income or less taxable loss with respect to their common units if the IRS does not
respect our method for determining the adjusted tax basis of their common units.
We have adopted a reporting convention that will enable our unitholders to track the basis of their individual common
units or unit groups and use this basis in calculating their basis adjustments under Section 743 of the Code and gain or loss
on the sale of common units. This method does not comply with an IRS ruling that requires a portion of the combined tax
basis of all common units to be allocated to each of the common units owned by a unitholder upon a sale or disposition of
less than all of the common units and may be challenged by the IRS. If such a challenge is successful, our unitholders may
recognize more taxable income or less taxable loss with respect to common units disposed of and common units they
continue to hold.
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Tax-exempt investors may recognize unrelated business taxable income.
Generally, unrelated business taxable income, or UBTI, can arise from a trade or business unrelated to the exempt
purposes of the tax-exempt entity that is regularly carried on by either the tax-exempt entity or a partnership in which the
tax-exempt entity is a partner. However, UBTI does not apply to interest income, royalties (including overriding royalties)
or net profits interests, whether the royalties or net profits are measured by production or by gross or taxable income from
the property. Pursuant to the provisions of our partnership agreement, our General Partner shall use all reasonable efforts to
prevent us from realizing income that would constitute UBTI. In addition, our General Partner is prohibited from incurring
certain types and amounts of indebtedness and from directly owning working interests or cost bearing interests and, in the
event that any of our assets become working interests or cost bearing interests, is required to assign such interests to the
Operating Partnership subject to the reservation of a net profits overriding royalty interest. However, it is possible that we
may realize income that would constitute UBTI in an effort to maximize unitholder value.
Tax consequences of certain NPIs are uncertain.
We are prohibited from owning working interests or cost-bearing interests. At the time of the creation of the Minerals
NPI, we assigned to the Operating Partnership all rights in any such working interests or cost-bearing interests that might
subsequently be created from the mineral properties that were and are subject of the Minerals NPI. As additional working
interests and other cost-bearing interests are created out of such mineral properties, they are owned by the Operating
Partnership pursuant to such original assignment, and we have executed various documents since the creation of the
Minerals NPI to confirm such treatment under the original assignment. This treatment could be characterized differently by
the IRS, and in such a case we are unable to predict, with certainty, all of the income tax consequences relating to the
Minerals NPI as it relates to such working interests and other cost-bearing interests.
Our unitholders may not be entitled to deductions for percentage depletion with respect to our oil and natural gas
interests.
Our unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable)
percentage depletion with respect to the oil and natural gas interests owned by us. However, percentage depletion is
generally available to a unitholder only if the unitholder qualifies under the independent producer exemption contained in
the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil,
natural gas, or derivative products or the operation of a major refinery. If a unitholder does not qualify under the
independent producer exemption, the unitholder generally will be restricted to deductions based on cost depletion.
Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our
method of allocating depletion deductions.
The Code requires that income, gain, loss and deduction attributable to appreciated or depreciated property that is
contributed to a partnership in exchange for a partnership interest be allocated so that the contributing partner is charged
with, or benefits from, unrealized gain or unrealized loss, referred to as “Built-in Gain” and “Built-in Loss,” respectively,
associated with the property at the time of its contribution to the partnership. Our partnership agreement provides that the
adjusted tax basis of the oil and natural gas properties contributed to us generally is allocated to the contributing partners
for the purpose of separately determining depletion deductions. Any gain or loss resulting from the sale of property
contributed to us generally will be allocated to the partners that contributed the property, in proportion to their percentage
interest in the contributed property, to take into account any Built-in Gain or Built-in Loss. This method of allocating Built-
in Gain and Built-in Loss is not specifically permitted by the applicable Treasury regulations, and the IRS may challenge
this method. Such a challenge, if successful, could cause our unitholders to recognize more taxable income or less taxable
loss on an ongoing basis in respect of their common units.
Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our
method of determining a unitholder's share of the basis of partnership property.
Our General Partner utilizes a method of calculating each unitholder's share of the basis of partnership property that
results in an aggregate basis for depletion purposes that reflects the purchase price of common units as paid by the
unitholder. This method is not specifically authorized under applicable Treasury regulations, and the IRS may challenge
this method. Such a challenge, if successful, could cause our unitholders to recognize more taxable income or less taxable
loss on an ongoing basis in respect of their common units.
24
The ratio of the amount of taxable income that will be allocated to a unitholder to the amount of cash that will be
distributed to a unitholder is uncertain, and cash distributed to a unitholder may not be sufficient to pay tax on the
income we allocate to a unitholder.
The amount of taxable income realized by a unitholder will be dependent upon a number of factors, and so we cannot
predict the ratio of the amount of taxable income that will be allocated to a unitholder to the amount of cash that will be
distributed to a unitholder. Unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local
income taxes, on their share of taxable income, whether or not they receive cash distributions from us equal to their share of
our taxable income or even equal to the actual tax liability that results from that income.
A unitholder may lose his status as a partner of our Partnership for federal income tax purposes if the unitholder lends
our common units to a short seller to cover a short sale of such common units.
If a unitholder loans his common units to a short seller to cover a short sale of common units, the unitholder may be
considered as having disposed of his ownership of those common units for federal income tax purposes. If so, the
unitholder would no longer be a partner of our Partnership for tax purposes with respect to those common units during the
period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any of our income,
gain, loss or deduction with respect to those common units would not be reportable, and any cash distributions received for
those common units would be fully taxable and may be treated as ordinary income.
Foreign, state and local taxes could be withheld on amounts otherwise distributable to a unitholder.
A unitholder may be required to file tax returns and be subject to tax liability in the foreign, state or local jurisdictions
where the unitholder resides and in each state or local jurisdiction in which we have assets or otherwise do business. We
also may be required to withhold state income tax from distributions otherwise payable to a unitholder, and state income tax
may be withheld by others on royalty payments to us.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any
resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for
distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any
resulting taxes (including any applicable penalties and interest) directly from us. We generally will have the ability to shift
any such tax liability (including any applicable penalties and interest) to our General Partner and our unitholders in
accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so
under all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance
with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic
burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under
audit. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash
available for distribution to our unitholders might be substantially reduced.
Our unitholders may be subject to withholding tax upon transfers of their common units.
If a unitholder sells or otherwise disposes of a common unit on or after January 1, 2023, the transferee generally will be
required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign
person. However, final regulations issued by the Treasury Department on the application of these rules to transfers of
certain publicly traded partnership interests, including our common units, provide that the obligation to withhold on a
transfer of interests in a publicly traded partnership that is effected through a broker is imposed on the transferor’s broker
(instead of the transferee), and the “amount realized” on such a transfer will generally be the amount of gross proceeds paid
to the broker effecting the applicable transfer on behalf of the transferor (and thus determined without regard to any
decrease in that transferor’s share of the publicly traded partnership's liabilities). Prospective foreign unitholders should
consult their tax advisors regarding the impact of these rules on an investment in our common units.
25
General Risk Factors
Public health threats could have an adverse effect on our Partnership, our cash flow and our industry.
Public health threats and other highly communicable diseases, outbreaks of which have been occurring in across the
world, including the United States, could adversely impact our Partnership, drilling activities on our properties and the
global economy.
In particular, the outbreak starting in 2020 of a coronavirus (COVID-19) resulted in quarantines, restrictions on travel
and a decrease in economic activity across the world, which then resulted in a decrease in demand for hydrocarbons. At its
height, the COVID-19 pandemic had a significant negative effect on the global economy, supply chains and labor force
participation, and created significant volatility in financial markets. Although the effects of the pandemic during 2022 were
not as significant as prior years, new variants continued to cause waves of COVID-19 cases around the world. The COVID-
19 pandemic and its ongoing variants may continue to have a material adverse effect on the demand for hydrocarbons and
the prices at which they are sold, which may impact our revenues and operating income, our cash distributions and our
business generally. It is impossible to predict the effect of the continued spread, or fear of continued spread, of COVID-19
and its ongoing variants globally. No assurance can be given that public health threats will not have a material adverse
effect, and that any further spread of COVID-19 and its ongoing variants will not have a material adverse effect, on our
business, operations and financial results.
The Partnership may be adversely affected by the international economic instability caused by ongoing global conflicts.
From 2022 through 2024, multiple global military conflicts arose causing instability in the international economy
which may continue into 2025. Although the length, impact and outcome of these military conflicts are highly
unpredictable, an escalation or expansion of any of these conflicts could lead to significant market and other disruptions,
including disruptions to the oil and gas industry, significant volatility in commodity prices and supply of energy resources,
instability in financial markets, supply chain interruptions, political and social instability and other material and adverse
effects on macroeconomic conditions. It is not possible at this time to predict or determine the ultimate consequences of
these ongoing conflicts.
We will continue to incur increased costs as a result of operating as a public company, and our management will
continue to devote substantial time to compliance with our public company responsibilities and corporate governance
practices.
As a public company, we have incurred and will continue to incur significant legal, accounting and other expenses,
particularly since we are now a large accelerated filer and are no longer a smaller reporting company. The Sarbanes-Oxley
Act of 2002, or the Sarbanes Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing
requirements of the Nasdaq Global Select Market and other applicable securities rules and regulations impose various
requirements on public companies. Our management and other personnel will need to continue to devote a substantial
amount of time to comply with these requirements. Moreover, these rules and regulations have increased, and will continue
to increase, our legal and financial compliance costs and will make some activities more time-consuming and costly. If,
notwithstanding our efforts to comply with new or changing laws, regulations, and standards, we fail to comply, regulatory
authorities may initiate legal proceedings against us, and our business may be harmed. Further, failure to comply with these
laws, regulations and standards may make it more difficult and more expensive for us to obtain directors’ and officers’
liability insurance, which could make it more difficult for us to attract and retain qualified members to serve on our board
of managers or committees or as members of senior management. These rules and regulations are often subject to varying
interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over
time as new guidance is provided by regulatory and governing bodies. This could result in future uncertainty regarding
compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.
Disclosure Regarding Forward-Looking Statements
Statements included in this report that are not historical facts (including any statements concerning plans and objectives
of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-
looking statements. These statements can be identified by the use of forward-looking terminology including "may,"
"believe," "will," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future
expectations, contain projections of results of operations or of financial condition or state other forward-looking
information.
26
These forward-looking statements are made based upon management's current plans, expectations, estimates,
assumptions and beliefs concerning future events impacting us and, therefore, involve a number of risks and uncertainties.
We caution that forward-looking statements are not guarantees and that actual results could differ materially from those
expressed or implied in the forward-looking statements for a number of important reasons, including those discussed under
"Risk Factors" and elsewhere in this report. Examples of such reasons include, but are not limited to, changes in the price or
demand for oil and natural gas, public health crises including the worldwide coronavirus (COVID-19) outbreak beginning
in early 2020 and its ongoing variants, the conflict in Ukraine, the conflict between Israel and Hamas, changes in the
operations on or development of our properties, changes in economic and industry conditions and changes in regulatory
requirements (including changes in environmental requirements) and our financial position, business strategy and other
plans and objectives for future operations.
You should read these statements carefully because they may discuss our expectations about our future performance,
contain projections of our future operating results or our future financial condition, or state other forward-looking
information. Before you invest, you should be aware that the occurrence of any of the events herein described in "Item 1A –
Risk Factors" and elsewhere in this report and in the Partnership’s other filings with the Securities and Exchange
Commission could substantially harm our business, results of operations and financial condition and that upon the
occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of
your investment.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
We and our operators increasingly rely on information technology systems to operate our respective businesses, and
the oil and natural gas industry depends on digital technologies in exploration, development, production, and processing
activities. We depend on digital technology in many areas of our business and operations, including, but not limited to,
estimating quantities of oil and natural gas reserves, processing and recording financial and operating data, oversight and
analysis of drilling, completion and production operations and communications with the employees of the Operating
Partnership and third party customers and services providers. We recognize the importance of assessing, identifying, and
managing material risks associated with cybersecurity threats, as defined in Item 106(a) of Regulation S-K. These risks
include, among other things: operational risks, gathering, misuse, loss or destruction of proprietary and other information,
fraud, extortion, harm to employees or customers, violation of data privacy or security laws and disruption of other business
activities.
We maintain a comprehensive process for identifying, assessing, and managing material risks from cybersecurity
threats as part of our broader risk management process. Our executive officers, along with input from our outsourced IT
managed services provider, other external experts, and department managers, are responsible for our overall enterprise risk
assessment and management process and regularly consider cybersecurity risks in the context of other material risks to the
Partnership. We obtain input on the security industry and threat trends for our cybersecurity risk management processes
from external experts, as appropriate. Our outsourced IT managed services provider has expertise in areas including, but not
limited to, information technology and infrastructure, network and communications architecture, information systems and
database management, back up management, and cybersecurity.
Our risk management process also assesses third party risks. We perform assessments to identify and mitigate risks
from third parties such as vendors and other business partners associated with our use of third party service providers.
Cybersecurity risks are evaluated when determining the selection and oversight of applicable third party service providers
and potential fourth party risks when handling and/or processing employee, business, or customer data.
To protect our information systems from cybersecurity threats, we, among other things: (i) conduct regular reviews of
information systems security programs and policies, (ii) perform penetration testing using external third party tools and
techniques to test security controls, (iii) provide employee training, (iv) monitor emerging trends, laws, and regulations
related to data protection and information security, and (v) use various security tools that help monitor, prevent, identify,
escalate, investigate, resolve, and recover from identified vulnerabilities and security incidents in a timely manner,
including, but not limited to, monitoring and detection tools managed by external experts and internal reporting.
27
We, in coordination with external experts, have implemented a cyber and data security incident response plan that has
four overarching and interconnected stages: 1) preparation for a cybersecurity incident, 2) identification, analysis, and
notification of a security incident by external experts, as applicable, 3) containment, eradication, and recovery, and 4) post-
incident analysis and learnings for future preparedness. Such incident responses are managed by our outsourced IT
managed services provider, Chief Financial Officer (“CFO”), and department managers, who, together, comprise our
primary incident response team. As part of our cybersecurity risk management process, our incident response team logs and
tracks privacy and security incidents across the Partnership, vendors, third party service providers, and other business
partners. Cyber and data security incidents are evaluated to determine materiality, as well as operational, business, and
privacy impact, ranked by severity, and prioritized for response and remediation. Significant incidents are evaluated by the
primary incident response team to determine whether further escalation is appropriate, and any incident assessed as
potentially being or potentially becoming material is immediately escalated for further assessment and reported to the Chief
Executive Officer (“CEO”). We consult with outside counsel and other subject matter experts regarding materiality
analysis, disclosure, and other compliance matters, as appropriate, and our executive officers, with input from the Board of
Managers, as appropriate, make the final materiality determinations and disclosure and other compliance decisions. Our
management apprises the Partnership’s independent public accounting firm of matters and any relevant developments.
The Advisory Committee of the Board of Managers of the general partner of our General Partner has oversight
responsibility for risks and incidents relating to cybersecurity threats, including compliance with disclosure requirements,
cooperation with law enforcement, and related effects on financial and other risks, and it reports any findings and
recommendations, as appropriate, to the full Board of Managers for consideration. Reports are periodically provided to the
Advisory Committee during our board meetings by the individuals who oversee risk management in cybersecurity. This
includes existing and new cybersecurity risks, status on how management is addressing and/or mitigating those risks,
cybersecurity and data privacy incidents (if any), and status on key information security initiatives. Members of the Board
of Managers also engage in ad hoc conversations with management on cybersecurity-related news events and discuss any
updates to our cybersecurity risk management and strategy programs.
As of the date of this filing, our business strategy, results of operations, and financial condition have not been
materially affected by risks from cybersecurity threats, including as a result of previously identified cybersecurity incidents,
but we cannot provide assurance that they will not be materially affected in the future by such risks or any future material
incidents. For more information on our cybersecurity related risks, see "Item 1A – Risk Factors".
ITEM 2. PROPERTIES
Facilities
Our corporate office is located in Dallas, Texas and consists of 11,847 square feet of leased office space.
Properties
We own two categories of properties: Royalty Properties and net profits overriding royalty interests (referred to as the
Net Profits Interest, or “NPI”).
Royalty Properties
We own Royalty Properties representing producing and nonproducing mineral, royalty, overriding royalty, net profit
and leasehold interests in properties located in 594 counties and parishes in 28 states. Acreage amounts listed herein
represent our best estimates based on information provided to us as a royalty owner. Due to the significant number of
individual deeds, leases and similar instruments involved in the acquisition and development of the Royalty Properties by
us or our predecessors, acreage amounts are subject to change as new information becomes available. In addition, as a
royalty owner, our access to information concerning activity and operations on the Royalty Properties is limited. Most of
our producing properties are subject to old leases and other contracts pursuant to which we are not entitled to well
information. Some of our newer leases provide for access to technical data and other information. We may have limited
access to public data in some areas through third party subscription services. Consequently, the exact number of wells
producing from or drilling on the Royalty Properties at a given point in time is not easily determinable. The primary
manner by which we will become aware of activity on the Royalty Properties is the receipt of division orders or other
correspondence from operators or purchasers.
28
Acreage Summary
The following table sets forth, as of December 31, 2024, a summary of our gross and net acres, where applicable, of
mineral, royalty, overriding royalty and leasehold interests, and a compilation of the number of counties and parishes and
states in which these interests are located. The majority of our net mineral acres are unleased.
Overriding
Mineral
Royalty
Royalty
Leasehold
Number of States ................................................................
28
17
17
8
Number of Counties/Parishes ............................................
525
196
151
33
Gross Acres .........................................................................
2,951,000
679,000
370,000
24,000
Net Acres (where applicable) .............................................
471,000
-
-
-
Our net interest in production from royalty, overriding royalty and leasehold interests is based on lease royalty and
other third party contractual terms, which vary from property to property. Consequently, net acreage ownership in these
categories is not determinable. Our net interest in production from properties in which we own a royalty or overriding
royalty interest may be affected by royalty terms negotiated by the previous mineral interest owners in such tracts and their
lessees. Our interest in the majority of these properties is perpetual in nature. However, a minor portion of the properties are
subject to terms and conditions pursuant to which a portion of our interest may terminate upon cessation of production.
The following table sets forth, as of December 31, 2024, the combined summary of total gross and net acres, where
applicable, of mineral, royalty, overriding royalty and leasehold interests in each of the states in which these interests are
located. Overriding royalty interests are only included in gross acre totals.
State
Gross
Net
State
Gross
Net
Alabama ..............................
105,000
8,000 Montana ........................................
366,000
81,000
Arkansas ..............................
49,000
16,000 Nebraska .......................................
3,000
< 500
Colorado ..............................
73,000
5,000 New Mexico ..................................
58,000
3,000
Florida .................................
89,000
25,000 New York ......................................
23,000
19,000
Georgia ................................
4,000
1,000 North Dakota ................................
523,000
82,000
Idaho ....................................
17,000
2,000 Ohio ...............................................
< 500
< 500
Illinois ..................................
5,000
1,000 Oklahoma .....................................
273,000
19,000
Indiana ................................
< 500
< 500 Oregon ..........................................
6,000
1,000
Kansas .................................
14,000
2,000 Pennsylvania .................................
10,000
6,000
Kentucky .............................
2,000
1,000 South Dakota ................................
55,000
11,000
Louisiana .............................
136,000
3,000 Texas ............................................. 2,041,000
171,000
Michigan ..............................
54,000
3,000 Utah ...............................................
6,000
< 500
Mississippi ...........................
81,000
9,000 West Virginia ...............................
< 500
< 500
Missouri ...............................
< 500
< 500 Wyoming .......................................
32,000
2,000
Leasing Activity
We received $0.3 million during 2024 attributable to lease bonus on 19 leases or extension of existing leases in lands
located in nine counties in four states. These leases reflected bonus payments ranging up to $5,000/acre and initial royalty
terms ranging up to 25%. The following table sets forth a summary of leases and pooling elections consummated during
2022, 2023 and 2024.
2024
2023
2022
Number .............................................................................................
19
14
31
Number of States .............................................................................
4
3
4
Number of Counties ........................................................................
9
11
17
Average Royalty(1) ..........................................................................
24.3%
25.0%
24.2%
Average Bonus, $/acre(1) ................................................................ $
532 $
18,385 $
10,268
Total Lease Bonus (in millions) ...................................................... $
0.3 $
12.7 $
8.7
(1) Based on net acreage weighted average.
29
Payments received for shut-in and delay rental payments, coal royalty, surface use agreements, litigation judgments
and settlement proceeds are reflected in our accompanying consolidated financial statements in other operating revenues.
Net Profits Interests
The NPI represents a net profits overriding royalty interest burdening various properties owned by the Operating
Partnership. We receive monthly payments from the NPI equaling 96.97% of the net profits realized by the Operating
Partnership from these properties in the preceding month. In the event costs, including budgeted capital expenditures,
exceed revenues on a cash basis in a given month for properties subject to the NPI, no payment is made, and any deficit is
accumulated and reflected in the following month's calculation of net profit. In the event the NPI has a deficit of cumulative
revenue versus cumulative costs, the deficit will be borne solely by the Operating Partnership.
From a cash perspective, as of December 31, 2024, the Minerals NPI was in a surplus position and had outstanding
capital commitments, primarily in the Bakken region, equaling cash on hand of $3.5 million.
Acreage Summary
The following tables set forth, as of December 31, 2024, information concerning properties owned by the Operating
Partnership and subject to the NPI. Acreage amounts listed under “Leasehold” reflect gross acres leased by the Operating
Partnership and the working interest share (net acres) in those properties. Acreage amounts listed under “Mineral” reflect
gross acres in which the Operating Partnership owns a mineral interest and the undivided mineral interest (net acres) in
those properties. The Operating Partnership's interest in these properties may be unleased, leased by others or a
combination thereof. In addition to amounts listed below, the Operating Partnership owns interests limited to certain
wellbores located on lands in which we own mineral, royalty or leasehold interests. The acreage amounts associated with
the wellbore interests are included in Royalty Properties Acreage Summary and not in the table below.
Mineral
Royalty
Leasehold
Number of States ........................................................................
12
5
5
Number of Counties/Parishes ....................................................
61
22
13
Gross Acres .................................................................................
50,000
-
14,000
Net Acres .....................................................................................
6,000
-
2,000
The following table reflects the states in which the acreage amounts listed above are located.
Mineral/Royalty
Leasehold
Total
Gross
Net
Gross
Net
Gross
Net
Arkansas .......................................
1,000
< 500
8,000
1,000
9,000
1,000
North Dakota ...............................
4,000
1,000
< 500
< 500
4,000
1,000
All Others .....................................
44,000
4,000
6,000
< 500
50,000
4,000
The leasehold acreage in Arkansas listed above includes all of the acreage in the Fayetteville Shale properties in which
the Operating Partnership participates as a working interest owner.
Productive Well Summary
The following table sets forth, as of December 31, 2024, the approximate combined number of producing wells on the
properties subject to the NPI. Gross wells refer to wells in which a working interest is owned. Net wells are determined by
multiplying gross wells by our working interest in those wells.
Productive Wells/Units(1)
Gross
Net
Texas ........................................................................................................................
543
18
North Dakota ..........................................................................................................
552
11
All others .................................................................................................................
284
9
Total .........................................................................................................................
1,379
38
(1) Defined as all wells/units for which we received production revenue during the calendar year. Large, multi-well
units paid on an aggregate basis are included as one gross well.
30
New Well Activity
The following table sets forth first payments received for new wells on our Royalty Properties and NPI properties
during 2024. The majority of the activity was concentrated in the Permian Basin, Bakken region, South Texas, and the
Rockies. Included in the table below are wells in which we own both a royalty interest and a net profits interest. Wells with
such overlapping interests are counted in both categories.
Royalty
Net Profits
Properties(1)
Interest
Gross Wells .............................................................................................................
1,943
146
Net Wells .................................................................................................................
12
2
Number of States ....................................................................................................
7
5
Number of Counties/Parishes ................................................................................
49
17
(1) 130 gross and less than one net well additions were attributable to acquisitions closed during 2023. These well
additions were in nine counties and parishes and three states. 1,110 gross and eight net well additions were attributable
to acquisitions closed during 2024. These well additions were in 15 counties in three states. We anticipate receiving
more first payments for new wells attributable to acquisitions closed during 2024 in the first half of 2025.
We have and will continue to consider a range of transaction structures for our unleased mineral interests including
leasing to third parties, working interest participation through the Operating Partnership, electing non-consent under State
laws, or a combination thereof.
Oil and Natural Gas Reserves
The below table reflects the Partnership's proved developed producing reserves at December 31, 2024. The reserves are
based on the reports of independent petroleum engineering consulting firm LaRoche Petroleum Consultants, Ltd.
(“LPC”), who is registered with the Engineering Board of the State of Texas and has been engaged in the business of oil
and natural gas property evaluation since its formation in 1979. Other than our filings with the SEC, we have not filed the
estimated proved reserves with, or included them in any reports to, any federal agency. Copies of the reports prepared by
LPC are attached hereto as Exhibits 99.1 and 99.2.
The Partnership does not have information that would be available to a company with oil and natural gas operations
because detailed information is not generally available to owners of royalty interests. The Partnership’s petroleum
engineer provides production and accounting information to our independent petroleum engineering consulting firm who
extrapolates from such information estimates of the reserves attributable to the Royalty Properties and NPI based on their
expertise in the oil and natural gas fields where the Royalty Properties and NPI are situated, as well as publicly available
information. Ensuring compliance with generally accepted petroleum engineering and evaluation methods and procedures
is the responsibility of the Partnership's Chief Executive Officer (“CEO”). Our CEO has a bachelor’s degree in Petroleum
Engineering from the University of Alberta and has worked in the upstream oil and natural gas business in various
capacities since 1996.
Summary of Oil and Natural Gas Reserves as of Fiscal Year-End
All Proved Developed Producing and located in the United States
Royalty Properties
Net Profits Interests(1)
Total
Year
Oil(2)
Natural Gas
Oil(2)
Natural Gas
Oil(2)
Natural Gas
(mbbls)
(mmcf)
(mbbls)
(mmcf)
(mbbls)
(mmcf)
2024 ...............................................
9,398
31,651
1,671
3,948
11,069
35,599
2023 ...............................................
6,642
28,138
1,676
5,213
8,318
33,351
2022 ...............................................
7,251
31,946
1,669
7,207
8,920
39,153
(1) Reserves reflect 96.97% of the corresponding amounts assigned to the Operating Partnership’s interests in the NPI
properties.
(2) Oil reserves include volumes attributable to natural gas liquids.
31
Proved oil and natural gas reserves means 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 governmental 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. See “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Results of Operations” for average sales prices.
Title to Properties
We believe we have satisfactory title to all of our assets. Record title to essentially all of our assets has undergone the
appropriate filings in the jurisdictions in which such assets are located. Title to property may be subject to encumbrances.
We believe that none of such encumbrances should materially detract from the value of our properties or from our interest
in these properties or should materially interfere with their use in the operation of our business.
ITEM 3. LEGAL PROCEEDINGS
The Partnership and the Operating Partnership are involved in legal and/or administrative proceedings arising in the
ordinary course of their businesses, none of which have predictable outcomes. We do not believe that the resolution of these
matters will have a material adverse impact on our financial condition or results of operations.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
32
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common units trade on the NASDAQ Global Select Market under the ticker symbol “DMLP”.
As of December 31, 2024, there were 22,793 common unitholders.
Our partnership agreement requires that we make quarterly distributions in an amount equal to all funds that we receive
from the Royalty Properties and the NPI (other than cash proceeds received by the Partnership from a public or private
offering of securities of the Partnership) less certain expenses and reasonable reserves.
Performance Graph
The Performance Graph below compares the cumulative five-year total unitholder return on our common units
beginning December 31, 2019 and for each subsequent year end through and including December 31, 2024, with
cumulative returns of the S&P 500 Index and an industry peer group selected by us. The industry peer group we selected is
comprised of the following companies: Black Stone Minerals, L.P., Viper Energy, Inc., Sitio Royalties Corp., and Kimbell
Royalty Partners, L.P.
The Performance Graph assumes $100 was invested in our common units and in each of the other indices described
above on December 31, 2019. Distribution or dividend reinvestments have been assumed on the payment dates. The stock
performance shown on the graph below is not necessarily indicative of future price performance.
12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024
Dorchester Minerals, L.P.
$
100.00 $
62.90 $
125.23 $
215.16 $
257.02 $
300.03
Industry Group
$
100.00 $
51.65 $
93.09 $
149.33 $
150.12 $
180.02
S&P 500 Index
$
100.00 $
118.40 $
152.39 $
124.79 $
157.59 $
197.02
33
Issuer Purchases of Equity Securities
(c)
(d)
Total
Maximum
Number of
Number
Units
of Units that
Purchased
May
as
Yet Be
(a)
(b)
Part of
Purchased
Total
Average
Publicly
Under the
Number of
Price
Announced
Plans
Units
Paid
Plans
or
Period
Purchased
per Unit
or Programs
Programs
October 1, 2024 – October 31, 2024
-
N/A
-
100,259(1)
November 1, 2024 – November 30, 2024
-
N/A
-
100,259(1)
December 1, 2024 – December 31, 2024
33,454(2) $
32.82
33,454
66,805(1)
Total
33,454
$
32.82
33,454
66,805(1)
(1) The number of common units that our General Partner may grant under the Dorchester Minerals Management LP
Equity Incentive Program, as amended and restated as of October 4, 2023, which was approved by our common
unitholders on October 4, 2023 (the “Equity Incentive Program”), each fiscal year may not exceed 0.333% of the
number of common units outstanding at the beginning of the fiscal year. In 2024, the maximum number
of common units that could be purchased under the Equity Incentive Program is 131,812 common units.
(2) Open-market purchases by the Operating Partnership, an affiliate of the Partnership, pursuant to a Rule 10b5-1
plan adopted on November 5, 2024 for the purpose of satisfying equity awards to be granted pursuant to the
Equity Incentive Program.
Recent Sales of Unregistered Securities
None.
ITEM 6. [RESERVED]
34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Objective
The following discussion summarizes our results of operations and liquidity and capital resources for the fiscal years
ended December 31, 2024 and 2023 and should be read in conjunction with our Consolidated Financial Statements and the
accompanying notes included elsewhere in this Annual Report. A discussion of results of operations and liquidity and
capital resources for fiscal year 2022 has been omitted from this report but may be found at “Item 7 – Management’s
Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the
fiscal year ended December 31, 2023, filed with the SEC on February 22, 2024, and is incorporated by reference in this
report from such prior Annual Report on Form 10-K. We intend for this discussion to provide the reader with information
that will assist in understanding our consolidated financial statements, the changes in certain key items in those
consolidated financial statements from period to period, and the primary factors that accounted for those changes.
2024 Overview
Our results during 2024 were mainly driven by increases in Royalty Properties sales volumes from continued drilling
activity in the Permian Basin and Bakken region and incremental production from 2023 and 2024 acquisitions, offset by
decreases in NPI sales volumes, leasing activity, and lower industrywide realized natural gas sales prices versus 2023.
Significant results include the following:
Ɣ
Net income of $92.4 million;
Ɣ
Distributions of $146.5 million to our limited partners;
Ɣ
Acquisition of mineral, royalty, and overriding royalty interests in producing and non-producing oil and natural
gas properties representing approximately 14,225 net mineral acres located in 14 counties across New Mexico and
Texas in exchange for 6,721,144 common units representing limited partnership interests in the Partnership valued
at $202.6 million and issued pursuant to the Partnership's registration statements on Form S-4;
Ɣ
Acquisition of overriding royalty interests representing approximately 1,204 net royalty acres located in Weld
County, Colorado in exchange for 530,000 common units representing limited partnership interests in the
Partnership valued at $16.0 million and issued pursuant to the Partnership's registration statement on Form S-4;
Ɣ
Acquisition of mineral interests representing approximately 1,485 net royalty acres located in two counties in
Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership
valued at $17.0 million and issued pursuant to the Partnership's registration statement on Form S-4; and
Ɣ
First payments on 1,943 gross and 12 net new wells on our Royalty Properties, of which 1,240 gross and eight net
wells were attributable to our 2023 and 2024 acquisitions, and 146 gross and two net new wells on our NPI
properties. The wells were located in 53 counties and parishes in eight states with the majority of the activity
concentrated in the Permian Basin, Bakken region, South Texas, and the Rockies. Included in these totals are
wells in which we own both a royalty interest and a net profits overriding royalty interest. Wells with such
overlapping interests are counted in both categories.
Critical Accounting Estimates
The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally
accepted in the United State (“U.S. GAAP”), which requires us to make certain estimates and apply judgments that affect
our financial position and results of operations as reflected in our consolidated financial statements. Actual results may
differ from those estimates. The Partnership’s accounting policies are summarized in Note 2 of the Notes to Consolidated
Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.
Management continually reviews our accounting policies, how they are applied, and how they are reported and
disclosed in our consolidated financial statements. The following items require significant estimation or judgment:
35
Oil and Natural Gas Properties
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method,
all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-
of-production method. These capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate
of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties.
The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test
calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and
geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and
natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative
information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However,
there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions
could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the
ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas
reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test
calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period
ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held
constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the
reserves. Oil and natural gas prices have historically been volatile, and the prevailing prices at any given time may not
reflect our Partnership’s or the industry’s forecast of future prices.
Revenue Recognition
The pricing of oil and natural gas sales from the Royalty Properties and NPI is primarily determined by supply and
demand in the marketplace and can fluctuate considerably. As a royalty owner, we have no operational control over the
volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI.
Revenues from Royalty Properties and NPI are recorded under the cash receipts approach as directly received from the
remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months
after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes
and product prices. Estimates of uncollected revenues and unpaid expenses from Royalty Properties (which are interests in
oil and natural gas leases that give the Partnership the right to receive a portion of the production from the leased acreage,
without bearing the costs of such production) and net profits overriding royalty interests (referred to as the Net Profits
Interest, or “NPI”) operated by nonaffiliated entities are particularly subjective due to our inability to gain accurate and
timely information. Identified differences between our accrued revenue estimates and actual revenue received historically
have not been significant.
The Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations. The
Partnership’s right to revenues from Royalty Properties and NPI occurs at the time of production, at which point, payment
is unconditional, and no remaining performance obligation exists for the Partnership. Accordingly, the Partnership’s
revenue contracts for Royalty Properties and NPI do not generate contract assets or liabilities.
36
Results of Operations
Normally, our period-to-period changes in net income and cash flows from operating activities are principally
determined by changes in oil and natural gas sales volumes and prices, and to a lesser extent, by capital expenditures
deducted under the NPI calculation. Our portion of oil and natural gas sales volumes and average sales prices are shown in
the following table.
Years Ended December 31,
Accrual basis sales volumes:
2024
2023
% Change
Royalty Properties natural gas sales (mmcf) ......................................
5,680
5,110
11%
Royalty Properties oil sales (mbbls) ...................................................
1,943
1,518
28%
NPI natural gas sales (mmcf) .............................................................
2,134
2,301
(7)%
NPI oil sales (mbbls) ..........................................................................
645
740
(13)%
Accrual basis average sales price:
Royalty Properties natural gas sales ($/mcf) ...................................... $
1.37 $
2.39
(43)%
Royalty Properties oil sales ($/bbl) .................................................... $
66.74 $
67.39
(1)%
NPI natural gas sales ($/mcf) ............................................................. $
1.54 $
2.65
(42)%
NPI oil sales ($/bbl) ............................................................................ $
64.02 $
67.44
(5)%
Comparison of the years ended December 31, 2024 and 2023
The increase in oil sales volumes attributable to our Royalty Properties during 2024 versus 2023 is primarily a result of
higher suspense releases on new wells in the Permian Basin and Bakken region, suspense releases on first payments in the
Permian Basin from wells acquired in the third quarter of 2024, higher suspense releases on first payments in the Rockies
from wells acquired in the third quarter of 2024 and first quarters of 2024 and 2022, and increased baseline production in
South Texas from wells acquired in 2023 and 2022, partially offset by lower suspense releases from first payments on
acquired wells in South Texas and decreased baseline production in the Permian Basin, Bakken region, and the Rockies,
particularly in the fourth quarter of 2024 compared to the same period of 2023. The increase in natural gas sales volumes
attributable to our Royalty Properties during 2024 compared to 2023 is primarily attributable to higher baseline production
and higher suspense releases on new wells in the Permian Basin, suspense releases on first payments in the Permian Basin
from wells acquired in the third quarter of 2024, higher suspense releases on first payments in the Rockies from wells
acquired in the first and third quarters of 2024, higher suspense releases on first payments and increased baseline
production in East Texas from wells acquired in 2022, and increased baseline production in the Mid-Continent, partially
offset by decreased baseline production and lower suspense releases from first payments on acquired wells in South Texas
and decreased production from legacy wells in the Rockies, Fayetteville Shale, Barnett Shale, and Southeast.
The decrease in oil sales volumes attributable to our NPI properties during 2024 versus 2023 is primarily the result of
lower suspense releases on new wells in the Permian Basin, partially offset by increased baseline production in the Permian
Basin and Bakken region and higher suspense releases on new wells in the Bakken region. The decrease in natural gas sales
volumes attributable to our NPI properties during 2024 compared to 2023 is primarily the result of lower suspense releases
on new wells in the Permian Basin and Mid-Continent, partially offset by higher suspense releases on new wells in the
Bakken region and increased baseline production in the Permian Basin, Bakken region, and Mid-Continent.
The decrease in lease bonus revenue from 2023 to 2024 is primarily attributable to receipt of $11.8 million from a lease
and lease amendment transaction executed in 2023, wherein the Partnership leased 243 net acres in two tracts of land in
Reagan County, Texas for $30,000 per acre and a 25% royalty and amended an existing lease on two separate tracts of land
also totaling 243 net acres in Reagan County, Texas for $18,750 per acre.
Production taxes and operating expenses increased a combined 19% from 2023 to 2024. The increase is primarily a
result of higher proportionate oil production taxes due to higher oil sales revenue attributable to our Royalty Properties and
higher proportionate post-production costs, such as compression, transportation, processing, and marketing, due to higher
oil and natural gas sales volumes attributable to our Royalty Properties.
Depreciation, depletion and amortization increased 62% from 2023 to 2024. Depletion is the amount of cost basis of oil
and natural gas properties at the beginning of a period attributable to the volume of reserves extracted during such period,
calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the
calculation of depletion. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural
gas reserves, including recent acquisitions and suspense releases on new wells.
37
General and administrative expenses increased 7% from 2023 to 2024. The increase is primarily attributable to higher
compensation expenses due to market adjustments, increased bonuses and an expanded Equity Incentive Program designed
for employee retention, and increased legal and other professional services fees, partially offset by a decrease resulting
from one-time, non-recurring professional services expenses of $1.2 million related to an unsuccessful acquisition in the
first nine months of 2023.
Net cash provided by operating activities decreased 5% from 2023 to 2024. The decrease is primarily due to lower NPI
payment receipts and lower lease bonus receipts, partially offset by higher revenue receipts attributable to our Royalty
Properties, net of production and operating expenses.
Acquisitions for Units
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals
LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton
Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership,
Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited
partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and
Carrollton Royalty, LP, a Texas limited partnership, the Partnership acquired mineral, royalty, and overriding royalty
interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres
located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited
partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership’s registration
statements on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was
accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a
relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed
cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $8.8 million is
included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended
December 31, 2024.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party,
the Partnership acquired overriding royalty interests totaling approximately 1,204 net royalty acres located in Weld
County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership
valued at $16.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the
acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets
under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs
were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final
settlement net cash received, net of capitalized transaction costs paid, of $1.4 million is included in net cash contributed in
acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
On March 28, 2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third
parties, the Partnership acquired mineral interests totaling approximately 1,485 net royalty acres located in two counties in
Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership valued at
$17.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is
considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP.
Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as
a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received,
net of capitalized transaction costs paid, of $4.4 million is included in net cash contributed in acquisitions on the
consolidated statement of cash flows for the year ended December 31, 2024.
On September 29, 2023, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party,
the Partnership acquired mineral and royalty interests totaling approximately 716 net royalty acres located in three counties
in Texas in exchange for 494,000 common units representing limited partnership interests in the Partnership valued at $14.4
million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is
considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP.
Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as
a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received,
net of capitalized transaction costs paid, of $0.9 million is included in net cash contributed in acquisitions on the
consolidated statement of cash flows for the year ended December 31, 2023.
38
On August 31, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third
parties, the Partnership acquired mineral and royalty interests totaling approximately 568 net royalty acres located in three
counties in Texas in exchange for 374,000 common units representing limited partnership interests in the Partnership
valued at $10.4 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the
acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets
under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs
were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final
settlement net cash received, net of capitalized transaction costs paid, of $0.3 million is included in net cash contributed in
acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023. Final settlement net cash
received, net of capitalized transaction costs paid, of $0.2 million is included in net cash contributed in acquisitions on the
consolidated statement of cash flows for the year ended December 31, 2024.
On July 12, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties,
the Partnership acquired mineral and royalty interests totaling approximately 900 net royalty acres located in 13 counties
and parishes across Louisiana, New Mexico, and Texas in exchange for 343,750 common units representing limited
partnership interests in the Partnership valued at $11.0 million and issued pursuant to the Partnership’s registration
statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was
accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a
relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed
cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is
included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended
December 31, 2023.
On September 30, 2022, pursuant to a non-taxable contribution and exchange agreement with Excess Energy, LLC, a
Texas limited liability company, the Partnership acquired mineral, royalty and overriding royalty interests totaling
approximately 2,100 net royalty acres located in 12 counties across Texas and New Mexico in exchange for 816,719
common units representing limited partnership interests in the Partnership valued at $20.4 million and issued pursuant to
the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complementary to our
business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the
acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of
the assets acquired. Final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is included
in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
Texas Margin Tax
Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less
certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations
and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships,
trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies,
holding companies, joint ventures and certain other business entities having limited liability protection.
Limited partnerships that receive at least 90% of their gross income from designated passive sources, including
royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of
their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive
entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax
purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a
passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to
include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code
provides such income is sourced according to the principal place of business of the Partnership, which would be the state of
Texas.
Each unitholder is urged to consult an independent tax advisor regarding the requirements for filing state income,
franchise and Texas margin tax returns.
39
Liquidity and Capital Resources
Capital Resources
Our primary sources of capital, on both a short-term and long-term basis, are our cash flows from the Royalty
Properties and the NPI. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we
receive from the Royalty Properties and NPIs (other than cash proceeds received by the Partnership from a public or private
offering of securities of the Partnership) less certain expenses and reasonable reserves. Additional cash requirements
include the payment of oil and natural gas production and property taxes not otherwise deducted from gross production
revenues and general and administrative expenses incurred on our behalf and allocated to the Partnership in accordance
with the partnership agreement. Because the distributions to our unitholders are, by definition, determined after the payment
of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payment of
expenses. Because many of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate
that sufficient funds will be available at all times for payment of these expenses. See below for the dates of cash
distributions to unitholders.
Contractual Obligations
The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease
(the “Office Lease”). The third amendment to our Office Lease was executed in April 2017 for a term of 129 months,
beginning June 1, 2018 and expiring in 2029. Under the third amendment to the Office Lease, monthly rental payments
range from $25,000 to $30,000. Future maturities of Office Lease liabilities representing monthly cash rental payment
obligations are summarized in Note 7 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements
and Supplementary Data”.
We are not directly liable for the payment of any exploration, development or production costs. We do not have any
transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital
resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with
other entities that could potentially result in unconsolidated debt.
To the extent necessary to avoid unrelated business taxable income, our partnership agreement prohibits us from
incurring indebtedness, excluding trade payables, in excess of $50,000 in the aggregate at any given time or which would
constitute “acquisition indebtedness” (as defined in Section 514 of the Code).
We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations despite potential
material uncertainties that may impact us as a result of increased oil and natural gas market volatility caused by ongoing
global military conflicts, global supply chain disruptions and the recent rise in inflation and interest rates. Although demand
and market prices for oil and natural gas have remained strong due to the rising energy use and worldwide shortage of oil
due to sanctions implemented on Russia, we cannot predict events that may lead to future price volatility. Our ability to
fund future distributions to unitholders may be affected by the prevailing economic conditions in the oil and natural gas
market and other financial and business factors, including the evolution of COVID-19 and any ongoing variants, along with
the military conflict between Russia and Ukraine and the conflict between Israel and Hamas which are beyond our control.
If market conditions were to change due to declines in oil prices or uncertainty created by COVID-19 or any ongoing
variants and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows
and liquidity could be reduced. Despite recent improvements, the current economic environment is volatile, and therefore,
we cannot predict the ultimate impact that COVID-19, the ongoing military conflict between Russia and Ukraine or the
ongoing conflict between Israel and Hamas will have on our liquidity or cash flows.
Liquidity and Working Capital
Cash and cash equivalents were $42.5 million as of December 31, 2024 and $47.0 million as of December 31, 2023.
40
Distributions
Distributions to limited partners and the General Partner related to cash receipts were as follows:
In Thousands
Per Unit
Limited
General
Year Quarter
Record Date
Payment Date
Amount
Partners
Partner
2023…..
4th
January 29, 2024
February 8, 2024
$
1.007874 $
39,895 $
1,517
2024…..
1st
April 29, 2024
May 9, 2024
$
0.781837
31,343
1,092
2024…..
2nd
July 29, 2024
August 8, 2024
$
0.702058
28,144
974
2024…..
3rd
October 28, 2024 November 7, 2024 $
0.995785
47,140
1,776
Total distributions paid in 2024 ............................................................... $
146,522 $
5,359
2024…..
4th
February 3, 2025
February 13, 2025 $
0.739412 $
35,004 $
1,291
In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of NPI net receipts.
Net Profits Interest
We receive monthly payments from the Operating Partnership equal to 96.97% of the net proceeds realized by the
Operating Partnership from the properties underlying the Net Profits Interest (or “NPI”). The Operating Partnership retains
the 3.03% balance of these net proceeds. Net proceeds generally reflect gross proceeds attributable to oil and natural gas
production actually received during the month, less production costs actually paid during the same month, net of budgeted
capital expenditures. Production costs generally reflect drilling, completion, operating and general and administrative costs
and exclude depletion, amortization and other non-cash costs. The Operating Partnership made NPI payments to us totaling
$23.9 million during October 2023 through September 2024, which payments reflected 96.97% of total net proceeds of
$24.6 million realized from September 2023 through August 2024. Net proceeds realized by the Operating Partnership
during September through November 2024 were reflected in NPI payments made during October through December 2024.
These payments were included in the fourth quarter distribution paid February 13, 2024 and are excluded from this
2024 analysis.
Royalty Properties
Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes
deducted and remitted by others. Additionally, we generally pay ad valorem taxes, general and administrative costs, and
marketing and associated costs because royalties and lease bonuses generally do not otherwise bear operating or similar
costs. After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty
Properties during October 2023 through September 2024 were $128.0 million, of which $122.9 million (96%) was
distributed to the limited partners and $5.1 million (4%) was distributed to the General Partner. Proceeds received by us
from the Royalty Properties during October through December 2024 became part of the fourth quarter distribution paid in
early 2025, which is excluded from this 2024 analysis.
Distribution Determinations
The actual calculation of distributions is performed each calendar quarter in accordance with our partnership
agreement. The following calculation covering the period October 2023 through September 2024 demonstrates the method:
In Thousands
Limited
General
Partners
Partner
4% of net cash receipts from Royalty Properties......................................................... $
- $
5,120
96% of net cash receipts from Royalty Properties.......................................................
122,879
-
1% of NPI payments to our Partnership ......................................................................
-
239
99% of NPI payments to our Partnership ....................................................................
23,643
-
Total distributions ....................................................................................................... $
146,522 $
5,359
Operating Partnership share (3.03% of net proceeds) .................................................
746
Total General Partner share .........................................................................................
$
6,105
% of total .....................................................................................................................
96%
4%
41
In summary, our limited partners received 96%, and our General Partner received 4% of the net cash generated by our
activities and those of the Operating Partnership during this period. Due to these fixed percentages, our General Partner
does not have any incentive distribution rights or other right or arrangement that will increase its percentage share of net
cash generated by our activities or those of the Operating Partnership.
During the period October 2023 through September 2024, our Partnership's quarterly distribution payments to limited
partners were based on all of its available cash, as defined in "Item 1 – Business".
Fourth Quarter 2024 Distribution Indicated Price
In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly
distributions, management calculates the average price by dividing gross revenues received by the net volumes of the
corresponding product without regard to the timing of the production to which such sales may be attributable. This
“indicated price” does not necessarily reflect the contractual terms for such sales and may be affected by transportation
costs, location differentials, and quality and gravity adjustments. While the relationship between the Partnership's cash
receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be
materially impacted by purchasers’ release of suspended funds and by prior period adjustments.
Cash receipts attributable to the Partnership's Royalty Properties during the 2024 fourth quarter totaled $34.9 million.
Approximately 68% of these receipts reflect oil sales during September 2024 through November 2024 and natural gas sales
during August 2024 through October 2024, and approximately 32% from prior sales periods. The average indicated prices
for oil and natural gas sales attributable to the Royalty Properties during the 2024 fourth quarter were $64.25/bbl and
$1.22/mcf, respectively.
Cash receipts attributable to the Partnership's NPI during the 2024 fourth quarter totaled $5.4 million. Approximately
61% of these receipts reflect oil and natural gas sales during August 2024 through October 2024, and approximately 39%
from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $63.93/bbl
and $1.24/mcf, respectively.
General and Administrative Costs
In accordance with our partnership agreement, we bear all general and administrative and other overhead expenses
subject to certain limitations. We reimburse our General Partner for certain allocable costs, including rent, wages, salaries
and employee benefit plans that are not direct expenses. This reimbursement is limited to an amount equal to the sum of 5%
of our distributions plus certain costs previously paid. For the year ended December 31, 2024, the reimbursement amounts
actually paid or reserved did not exceed the limitation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
The pricing of oil and natural gas sales is primarily determined by supply and demand in the global marketplace and
can fluctuate considerably. As a royalty owner and non-operator, we have extremely limited access to timely information
and no operational control over the volumes of oil and natural gas produced and sold or the terms and conditions on which
such volumes are marketed and sold.
Our profitability is affected by oil and natural gas market prices. Oil and natural gas market prices have fluctuated
significantly in recent years in response to changes in the supply and demand for oil and natural gas in the market, along
with domestic and international political and economic conditions.
In January 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new
strain of coronavirus (“COVID-19”) and the significant risks to the international community and economies as the virus
spread globally beyond its point of origin. In March 2020, the WHO classified COVID-19 as a pandemic, based on the
rapid increase in exposure globally, and thereafter, COVID-19 continued to spread throughout the U.S. and worldwide. In
addition, in early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a
result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken
by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant
decrease in demand due to the COVID-19 pandemic. Additionally, multiple variants emerged in 2021 and became highly
transmissible, which contributed to additional pricing and demand volatility during 2021 to date. However, conditions have
significantly improved since 2022 with the increase in domestic vaccination programs, a reduction in global constraints and
42
a reduced spread of COVID-19 overall, and in May 2023, the WHO determined that COVID-19 is now an established and
ongoing health issue which no longer constitutes a public health emergency of international concern. Nevertheless, the long
term impact of COVID-19 remains uncertain.
Furthermore, from 2022 through 2024, multiple global military conflicts arose, causing instability in the international
economy which may lead to significant market and other disruptions, including disruptions to the oil and gas industry,
significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain
interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. It is not
possible at this time to predict or determine the ultimate consequences of these ongoing conflicts.
As a result of the lifting of certain restrictions put in place in response to COVID-19 and the global supply shortage of
oil and natural gas caused by the Russian invasion of Ukraine, in addition to other changing market conditions, oil and
natural gas market prices sharply increased during the first half of 2022 followed by a slight softening in oil prices during
the second half of 2022 due to higher inflation and rising interest rates. During the first quarter of 2023, with the exception
of a decline of oil prices in March in reaction to the U.S. regional bank instability, oil prices remained generally in line with
those seen in the later portion of 2022. Despite the decline in oil prices we have seen during 2023, demand and market
prices for oil and natural gas remain resilient, due in part to global travel trending towards pre-COVID-19 levels and the
recently announced OPEC+ production cuts. However, commodity prices have historically been volatile, and we cannot
predict events which may lead to future fluctuations in these prices. Although the WHO in May 2023 determined that
COVID-19 is now an established and ongoing health issue which no longer constitutes a public health emergency of
international concern, additional actions may be required in response to the COVID-19 pandemic on a national, state, and
local level by governmental authorities, and such actions may further adversely affect general and local economic
conditions if there is a resurgence in the spread of COVID-19. The long term effects of COVID-19 remain uncertain.
Similarly, the length, impact and outcome of the ongoing military conflicts are highly unpredictable and could lead to
significant market disruptions and increased volatility in oil and natural gas prices and supply of energy resources along
with instability in the global commodity and financial markets.
Customer Credit Risk
Our principal exposure to credit risk results from receivables generated by the production activities of our operators.
We do not require collateral and the failure or inability of our operators to meet their obligations to us due to their liquidity
issues, bankruptcy, insolvency, or liquidation may adversely affect our financial results. However, we believe the credit risk
associated with our operators and customers is acceptable. Volatility in commodity pricing environment and
macroeconomic conditions may enhance our purchaser credit risk. See Note 2 of the Notes to Consolidated Financial
Statements in “Item 8 – Financial Statements and Supplementary Data” for further detail of our concentration of credit risks
and significant customers.
Interest Rate Risk
We do not anticipate having a credit facility or incurring any debt, other than trade debt. Therefore, we do not expect
interest rate risk to be material to us.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements are set forth herein commencing on page F-1.
43
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
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the
effectiveness 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, 2024. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have
concluded that, as of December 31, 2024, our disclosure controls and procedures were effective, in that they ensure that
information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded,
processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated
and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate
to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
Management acknowledges its responsibility for establishing and maintaining adequate internal control over financial
reporting in accordance with Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934. Management has also
evaluated the effectiveness of its internal control over financial reporting in accordance with generally accepted accounting
principles within the guidelines of the Committee of Sponsoring Organizations of the Treadway Commission framework
(2013). Based on the results of this evaluation, management has determined that the Partnership’s internal control over
financial reporting was effective as of December 31, 2024. The independent registered public accounting firm of Grant
Thornton LLP (PCAOB ID Number 248), as auditors of the Partnership’s consolidated financial statements included in the
Annual Report, has issued an attestation report on the Partnership’s internal control over financial reporting.
Changes in Internal Controls
There were no changes in our Partnership’s internal control over financial reporting (as defined in Rule 13a-15(f) of the
Securities Exchange Act of 1934) during the quarter ended December 31, 2024, that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
During the quarter and year ended December 31, 2024, none of our executive officers or directors adopted or
terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the
affirmative defense conditions of Rule 10b5-1(c) of any “Non-Rule 10b5-1 trading arrangement.”
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
44
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item, including information about our Managers, Executive Officers and Audit
Committee, is incorporated herein by reference to the 2025 Proxy Statement, which will be filed with the Securities and
Exchange Commission not later than 120 days subsequent to December 31, 2024.
Insider Trading Arrangements and Policies
We have adopted an insider trading policy governing the purchase, sale and/or other dispositions of our securities by
our Managers, the officers and employees of the Operating Partnership, or the Partnership itself that we believe is
reasonably designed to promote compliance with insider trading laws, rules and regulations, and NASDAQ listing
standards. A copy of our insider trading policy is filed as Exhibit 19.1 to this Annual Report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be
filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2024.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED UNITHOLDER MATTERS
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be
filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2024.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be
filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2024.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated herein by reference to the 2025 Proxy Statement, which will be
filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2024.
45
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements and Schedules
(1) See the Index to Consolidated Financial Statements on page F-1.
(2) No schedules are required.
(3) The exhibits required by Item 601 of Regulation S-K are as follows:
Number Description
3.1
Certificate of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.1 to
Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.2
Amended and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P. (incorporated by
reference to Exhibit 3.2 to Dorchester Minerals’ Report on Form 10-K filed for the year ended December 31,
2002)
3.3
Amendment No. 1 to Amended and Restated Partnership Agreement of Dorchester Minerals, L.P.
(incorporated by reference to Exhibit 3.1 to Dorchester Minerals’ Current Report on Form 8-K filed with the
SEC on December 22, 2017)
3.4
Amendment No. 2 to Amended and Restated Partnership Agreement of Dorchester Minerals, L.P.
(incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Report on Form 10-Q filed with the SEC on
August 6, 2018)
3.5
Amendment No. 3 to Amended and Restated Partnership Agreement of Dorchester Minerals, L.P.
(incorporated by reference to Exhibit 3.1 to Dorchester Minerals’ Current Report on Form 8-K filed with the
SEC on October 6, 2023)
3.6
Certificate of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to
Exhibit 3.4 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.7
Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Management LP (incorporated
by reference to Exhibit 3.4 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
3.8
Certificate of Formation of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit
3.7 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.9
Second Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management
GP LLC (incorporated by reference to Exhibit 3.1 to Dorchester Minerals’ Current Report on Form 8-K filed
with the SEC on October 18, 2024)
3.10
Certificate of Formation of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.10
to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.11
Limited Liability Company Agreement of Dorchester Minerals Operating GP LLC (incorporated by reference
to Exhibit 3.11 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.12
Certificate of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit
3.12 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.13
Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Operating LP (incorporated
by reference to Exhibit 3.10 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31,
2002)
3.14
Certificate of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit
3.11 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)
3.15
Agreement of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit
3.12 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)
3.16
Certificate of Incorporation of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit
3.13 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)
3.17
Bylaws of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.14 to Dorchester
Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)
4.1*
Description of the Registrant’s Securities
10.1
Amended and Restated Business Opportunities Agreement dated as of December 13, 2001 by and between the
Registrant, the General Partner, Dorchester Minerals Management GP LLC, SAM Partners, Ltd., Vaughn
Petroleum, Ltd., Smith Allen Oil & Gas, Inc., P.A. Peak, Inc., James E. Raley, Inc., and certain other parties
(incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Annual Report on Form 10-K for the year
ended December 31, 2002)
46
Number Description
10.2
Transfer Restriction Agreement (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Annual
Report on Form 10-K for the year ended December 31, 2002)
10.3
Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to Dorchester Minerals’ Annual
Report on Form 10-K for the year ended December 31, 2002)
10.4
Lock-Up Agreement by William Casey McManemin (incorporated by reference to Exhibit 10.4 to Dorchester
Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)
10.5
Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Quarterly
Report on Form 10-Q for the quarter ended June 30, 2004)
10.6#
Dorchester Minerals Operating LP Equity Incentive Program (incorporated by reference to Annex A to
Dorchester Minerals’ Proxy Statement on Schedule 14A filed with the SEC on March 16, 2015)
10.7
Contribution and Exchange Agreement dated September 16, 2022, by and among Dorchester Mineral, L.P., and
Excess Energy, LLC (incorporated by reference to Exhibit 2.1 to Dorchester Minerals' Current Report on Form
8-K filed with the SEC on September 21, 2022)
10.8#
Amendment No. 1 to the Dorchester Minerals Management LP Equity Incentive Program (incorporated by
reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K filed with the SEC on October
6, 2023)
10.9#
Form of Common Unit Award Agreement (incorporated by reference to Exhibit 10.9 to Dorchester Minerals’
Annual Report on Form 10-K for the year ended December 31, 2023)
10.10#
Form of Notional Unit Award Agreement (incorporated by reference to Exhibit 10.10 to Dorchester Minerals’
Annual Report on Form 10-K for the year ended December 31, 2023)
10.11
Contribution and Exchange Agreement dated September 12, 2024, by and among Dorchester Minerals, L.P.,
West Texas Minerals LLC, Carrollton Mineral Partners, LP, Carrollton Mineral Partners Fund II, LP,
Carrollton Mineral Partners III, LP, Carrollton Mineral Partners III-B, LP, Carrollton Mineral Partners IV, LP,
CMP Permian, LP, CMP Glasscock, LP, and Carrollton Royalty, LP. (incorporated by reference to Exhibit 2.1
to Dorchester Minerals’ Current Report on Form 8-K filed with the SEC on September 16, 2024)
10.12#
Letter Agreement dated September 30, 2024 by and among Carrollton Mineral Partners, LP and the members
of Dorchester Minerals Management GP, LLC (incorporated by reference to Exhibit 10.1 to Dorchester
Minerals’ Current Report on Form 8-K filed with the SEC on October 18, 2024)
19.1*## Insider Trading Policy
21.1*
Subsidiaries of the Registrant
23.1*
Consent of Grant Thornton LLP
23.2*
Consent of LaRoche Petroleum Consultants, Ltd.
31.1*
Certification of Chief Executive Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934
31.2*
Certification of Chief Financial Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934
32.1**
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350
97.1*
Dorchester Minerals, L.P. Clawback Policy
99.1*
Report of LaRoche Petroleum Consultants, Ltd.
99.2*
Report of LaRoche Petroleum Consultants, Ltd.
101.INS*
XBRL Instance Document – the instance document does not appear in the Interactive Data File because its
XBRL tags are embedded within the Inline XBRL document
101.SCH* Inline XBRL Taxonomy Extension Schema Document
101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* Inline XBRL Taxonomy Extension Definition Document
101.LAB* Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*
Filed herewith
** Furnished herewith
#
Management contract or compensatory plan or arrangement
## Certain schedules and/or appendices have been omitted in accordance with Item 601(a)(5) of Regulation S-K. A copy
of any omitted schedule and/or appendix will be furnished to the Securities and Exchange Commission upon request.
ITEM 16. FORM 10-K SUMMARY
None.
47
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The definitions set forth below shall apply to the indicated terms as used in this document. All volumes of natural gas
referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees
Fahrenheit and in most instances are rounded to the nearest major multiple.
"bbl" means a standard barrel of 42 U.S. gallons and represents the basic unit for measuring the production of crude
oil, natural gas liquids and condensate.
“boe” means one barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to 1 Bbl of
oil. Also see mcfe below.
"Depletion" means (a) the volume of hydrocarbons extracted from a formation over a given period of time, (b) the rate
of hydrocarbon extraction over a given period of time expressed as a percentage of the reserves existing at the beginning of
such period, or (c) the amount of cost basis at the beginning of a period attributable to the volume of hydrocarbons
extracted during such period.
"Division order" means a document to protect lessees and purchasers of production, in which all parties who may have
a claim to the proceeds of the sale of production agree upon how the proceeds are to be divided.
"Enhanced recovery" means the process or combination of processes applied to a formation to extract hydrocarbons in
addition to those that would be produced utilizing the natural energy existing in that formation. Examples of enhanced
recovery include water flooding and carbon dioxide (CO2) injection.
"Formation" means a distinct geologic interval, sometimes referred to as the strata, which has characteristics (such as
permeability, porosity and hydrocarbon saturations) that distinguish it from surrounding intervals.
"Future estimated net revenues" (also referred to as "future estimated net cash flow") means the result of applying
current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by
estimated future expenditures, based on current costs to be incurred in developing and producing the proved reserves,
excluding overhead.
"Gross acre" means the number of surface acres in which a working interest is owned.
"Gross well" means a well in which a working interest is owned.
"Lease bonus" means the initial cash payment made to a lessor by a lessee in consideration for the execution and
conveyance of the lease and includes proceeds from assignments of leasehold interests where the Partnership retains an
interest.
"Leasehold" means an acre in which a working interest is owned.
"Lessee" means the owner of a lease of a mineral interest in a tract of land.
"Lessor" means the owner of the mineral interest who grants a lease of his interest in a tract of land to a third party,
referred to as the lessee.
"Mineral interest" means the interest in the minerals beneath the surface of a tract of land. A mineral interest may be
severed from the ownership of the surface of the tract. Ownership of a mineral interest generally involves four incidents of
ownership: (1) the right to use the surface; (2) the right to incur costs and retain profits, also called the right to develop; (3)
the right to transfer all or a portion of the mineral interest; and (4) the right to retain lease benefits, including bonuses and
delay rentals.
"mcf” means one thousand cubic feet of natural gas under prescribed conditions of pressure and temperature and
represents the basic unit for measuring the production of natural gas.
48
“mcfe” means one thousand cubic feet of natural gas equivalent, converting oil or condensate to natural gas at the ratio
of 1 Bbl of oil or condensate to 6 Mcf of natural gas. This conversion ratio, which is typically used in the oil and gas
industry, represents the approximate energy equivalent of a barrel of oil or condensate to an Mcf of natural gas. The sales
price of one barrel of oil or condensate has been much higher than the sales price of six Mcf of natural gas over the last
several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to one
barrel of oil or condensate.
"mbbls" means one thousand standard barrels of 42 U.S. gallons and represents the basic unit for measuring the
production of crude oil, natural gas liquids and condensate.
"mmcf” means one million cubic feet of natural gas under prescribed conditions of pressure and temperature and
represents the basic unit for measuring the production of natural gas.
"Net acre" means the product determined by multiplying gross acres by the interest in such acres.
"Net royalty acre" means the product determined by multiplying net acres by the royalty rate in the lease multiplied by
eight to normalize the interest based on a one-eighth royalty.
"Net well" means the product determined by multiplying gross oil and natural gas wells by the interest in such wells.
"Net profits interest" means a non-operating interest that creates a share in gross production from another (operating or
non-operating) interest in oil and natural gas properties. The share is determined by net profits from the sale of production
and customarily provides for the deduction of capital and operating costs from the proceeds of the sale of production. The
owner of a net profits interest is customarily liable for the payment of capital and operating costs only to the extent that
revenue is sufficient to pay such costs but not otherwise.
"Operator" means the individual or company responsible for the exploration, development, and production of an oil or
natural gas well or lease.
"Overriding royalty interest" means a royalty interest created or reserved from another (operating or non-operating)
interest in oil and natural gas properties. Its term extends for the same term as the interest from which it is created.
“Payout” or “Back-in” occurs when the working interest owners who participate in the costs of drilling and completing
a well recoup the costs and expenses, or a multiple of the costs and expenses, of drilling and completing that well. Only
then are the owners who chose not to contribute to these initial costs entitled to participate with the other owners in
production and share in the expenses and revenues associated with the well. The reversionary interest or back-in interest of
an owner similarly occurs when the owner becomes entitled to a specified share of the working or overriding royalty
interest when specified costs have been recovered from production.
“Pooling election” means the statutory combination of interests which affords owners the right to choose between
participating in the drilling of a well or accepting royalty payments.
"Proved developed reserves" means reserves that can be expected to be recovered (i) through existing wells with
existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to
the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the
reserves estimate if the extraction is by means not involving a well.
"Proved reserves" or “Proved oil and natural gas reserves” means 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
governmental 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.
“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible oil
and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
49
“Reserves” Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and
financing required to implement the project.
"Royalty" means an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion
of the production from the leased acreage (or of the proceeds of the sale thereof) but generally does not require the owner to
pay any portion of the costs of drilling or operating the wells on the leased acreage.
"Severance tax" means an amount of tax, surcharge or levy recovered by governmental agencies from the gross
proceeds of oil and natural gas sales. Severance tax may be determined as a percentage of proceeds or as a specific amount
per volumetric unit of sales. Severance tax is usually withheld from the gross proceeds of oil and natural gas sales by the
first purchaser (e.g., pipeline or refinery) of production.
"Standardized measure of discounted future net cash flows" (also referred to as "standardized measure") means the
pretax present value of estimated future net revenues to be generated from the production of proved reserves calculated in
accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the
date of estimation without future escalation, without giving effect to non-property related expenses such as general and
administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount
rate of 10%.
“Suspense release” means revenues that have been held by a purchaser or lessee, often attributable to multiple months
of production.
"Undeveloped acreage" means lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved
reserves.
"Unitization" means the process of combining mineral interests or leases thereof in separate tracts of land into a single
entity for administrative, operating or ownership purposes. Unitization is sometimes called "pooling" or "communitization"
and may be voluntary or involuntary.
"Working interest" (also referred to as an "operating interest") means a real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production
but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas.
A working interest owner who owns a portion of the working interest may participate either as operator or by voting his
percentage interest to approve or disapprove the appointment of an operator and certain activities in connection with the
development and operation of a property.
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DORCHESTER MINERALS, L.P.
By: /s/ Bradley Ehrman
Bradley Ehrman
Chief Executive Officer
Date: February 20, 2025
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ William Casey McManemin
/s/ H.C. Allen, Jr.
William Casey McManemin
Chairman and Manager
Date: February 20, 2025
H.C. Allen, Jr.
Manager
Date: February 20, 2025
/s/ Lesley R. Carver
/s/ Allen D. Lassiter
Lesley R. Carver
Manager
Date: February 20, 2025
Allen D. Lassiter
Manager
Date: February 20, 2025
/s/ Martha Ann Peak Rochelle
/s/ C. W. Russell
Martha Ann Peak Rochelle
Manager
Date: February 20, 2025
C. W. Russell
Manager
Date: February 20, 2025
/s/ Ronald P. Trout
/s/ Robert C. Vaughn
Ronald P. Trout
Manager
Date: February 20, 2025
Robert C. Vaughn
Manager
Date: February 20, 2025
/s/ F. Damon Box
F. Damon Box
Manager
Date: February 20, 2025
F-1
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Dorchester Minerals, L.P.
Reports of Independent Registered Public Accounting Firm (PCAOB ID Number 248) ......................................
F-2
Consolidated Balance Sheets ...................................................................................................................
F-4
Consolidated Income Statements .............................................................................................................
F-5
Consolidated Statements of Changes in Partnership Capital ..........................................................................
F-6
Consolidated Statements of Cash Flows ....................................................................................................
F-7
Notes to Consolidated Financial Statements ...............................................................................................
F-8
Supplemental Oil and Natural Gas Data (Unaudited) ................................................................................... F-16
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
General Partner and Unitholders
Dorchester Minerals, L.P.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Dorchester Minerals, L.P. (a Delaware limited partnership)
and subsidiaries (the “Partnership”) as of December 31, 2024, based on criteria established in the 2013 Internal Control—
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In
our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2024, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31,
2024, and our report dated February 20, 2025 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’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
Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the
Partnership’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 Partnership 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 included obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk, and 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.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 20, 2025
F-3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
General Partner and Unitholders
Dorchester Minerals, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Dorchester Minerals, L.P. (a Delaware limited
partnership) and subsidiaries (the “Partnership”) as of December 31, 2024 and 2023, the related consolidated statements of
income, changes in partnership capital, and cash flows for each of the three years in the period ended December 31, 2024,
and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated
financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2024
and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2024, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) ("PCAOB"), the Partnership's internal control over financial reporting as of December 31, 2024, based on criteria
established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission ("COSO"), and our report dated February 20, 2025 expressed an unqualified opinion.
Basis for opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to
express an opinion on the Partnership’s 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 Partnership 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 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
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 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 financial statements. We believe that our audits provide a reasonable basis for our
opinion.
Critical audit matters
Critical audit matters are matters arising from the current period audit of the 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
financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that
there are no critical audit matters.
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 1998.
Dallas, Texas
February 20, 2025
F-4
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONSOLIDATED BALANCE SHEETS
December 31,
(In Thousands)
2024
2023
ASSETS
Current assets:
Cash and cash equivalents ..................................................................................... $
42,508 $
47,025
Trade and other receivables ..................................................................................
19,780
14,407
Net profits interest receivable - related party ......................................................
5,544
8,275
Total current assets .........................................................................................
67,832
69,707
Oil and natural gas properties (full cost method) .......................................................
727,446
507,057
Accumulated full cost depletion ...................................................................................
(429,435)
(386,939 )
Total .................................................................................................................
298,011
120,118
Leasehold improvements ..............................................................................................
989
989
Accumulated amortization ...........................................................................................
(606)
(514 )
Total .................................................................................................................
383
475
Operating lease right-of-use asset ................................................................................
586
765
Total assets ..................................................................................................................... $
366,812 $
191,065
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
Accounts payable and other current liabilities .................................................... $
3,984 $
4,195
Operating lease liability .........................................................................................
263
272
Total current liabilities ...................................................................................
4,247
4,467
Operating lease liability ................................................................................................
777
1,041
Total liabilities .................................................................................................
5,024
5,508
Commitments and contingencies (Note 5)
Partnership capital:
General Partner ......................................................................................................
(1,997)
113
Unitholders (47,340 and 39,583 common units issued and outstanding as of
December 31, 2024 and 2023, respectively) ......................................................
363,785
185,444
Total partnership capital ................................................................................
361,788
185,557
Total liabilities and partnership capital ...................................................................... $
366,812 $
191,065
The accompanying notes are an integral part of these consolidated financial statements
F-5
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONSOLIDATED INCOME STATEMENTS
For each of the Years Ended December 31,
(In Thousands, except per unit amounts)
2024
2023
2022
Operating revenues:
Royalties ....................................................................................... $
137,465 $
114,531 $
133,262
Net profits interest .......................................................................
21,856
34,338
28,207
Lease bonus ..................................................................................
314
12,668
8,661
Other ............................................................................................
1,888
2,262
670
Total operating revenues .....................................................
161,523
163,799
170,800
Costs and expenses:
Production taxes ..........................................................................
6,884
5,776
6,582
Operating expenses .....................................................................
7,671
6,435
6,307
Depreciation, depletion and amortization .................................
42,588
26,307
19,083
General and administrative expenses ........................................
11,931
11,164
8,221
Total costs and expenses ......................................................
69,074
49,682
40,193
Net income ........................................................................................... $
92,449 $
114,117 $
130,607
Allocation of net income:
General Partner ........................................................................... $
3,249 $
3,728 $
4,486
Unitholders .................................................................................. $
89,200 $
110,389 $
126,121
Net income per common unit (basic and diluted) ............................ $
2.13 $
2.85 $
3.35
Weighted average basic and diluted common units outstanding ...
41,811
38,783
37,624
The accompanying notes are an integral part of these consolidated financial statements
F-6
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
For each of the Years Ended December 31,
(In Thousands)
General
Partner Unitholders
Total
Unitholder
Units
2022
Balance at January 1, 2022 ................................................ $
982 $
141,428 $
142,410
36,985
Net income .........................................................................
4,486
126,121
130,607
-
Acquisitions of oil and natural gas properties for
common units .................................................................
-
35,194
35,194
1,387
Distributions ($3.497244 per common unit) ......................
(4,792 )
(131,901 )
(136,693)
-
Balance at December 31, 2022 .......................................... $
676 $
170,842 $
171,518
38,372
2023
Net income ......................................................................... $
3,728 $
110,389 $
114,117
-
Acquisitions of oil and natural gas properties for
common units .................................................................
-
35,777
35,777
1,211
Distributions ($3.395933 per common unit) ......................
(4,291 )
(131,564 )
(135,855)
-
Balance at December 31, 2023 .......................................... $
113 $
185,444 $
185,557
39,583
2024
Net income ......................................................................... $
3,249 $
89,200 $
92,449
-
Acquisitions of oil and natural gas properties for
common units .................................................................
-
235,663
235,663
7,757
Distributions ($3.487554 per common unit) ......................
(5,359 )
(146,522 )
(151,881)
-
Balance at December 31, 2024 .......................................... $
(1,997 ) $
363,785 $
361,788
47,340
The accompanying notes are an integral part of these consolidated financial statements
F-7
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONSOLIDATED STATEMENTS OF CASH FLOWS
For each of the Years Ended December 31,
(In Thousands)
2024
2023
2022
Cash flows from operating activities:
Net income ................................................................................. $
92,449 $
114,117 $
130,607
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization ........................
42,588
26,307
19,083
Amortization of operating lease right-of-use asset ..........
179
194
209
Changes in operating assets and liabilities:
Trade and other receivables ..............................................
(4,513)
(442 )
(3,138)
Net profits interest receivable - related party ..................
2,731
(1,105 )
(348)
Accounts payable and other current liabilities ................
(522)
1,052
930
Operating lease liability .....................................................
(273)
(281 )
(291)
Net cash provided by operating activities .......................................
132,639
139,842
147,052
Cash flows provided by investing activities:
Net cash contributed in acquisitions of oil and natural gas
properties ................................................................................
14,725
2,284
2,089
Cash flows used in financing activities:
Distributions paid to General Partner and unitholders .........
(151,881)
(135,855 )
(136,693)
(Decrease) Increase in cash and cash equivalents ..........................
(4,517)
6,271
12,448
Cash and cash equivalents at beginning of period .........................
47,025
40,754
28,306
Cash and cash equivalents at end of period ................................... $
42,508 $
47,025 $
40,754
Non-cash investing and financing activities:
Fair value of common units issued for acquisitions of oil
and natural gas properties .................................................... $
235,663 $
35,777 $
35,194
The accompanying notes are an integral part of these consolidated financial statements
F-8
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
1.
Business and Basis of Presentation
Description of the Business
Dorchester Minerals, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership that commenced
operations on January 31, 2003. Our Partnership is based in Dallas, Texas and our business may be described as the
acquisition, ownership and administration of Royalty Properties (which consists of producing and nonproducing mineral,
royalty, overriding royalty, net profits, and leasehold interests located in 594 counties and parishes in 28 states (“Royalty
Properties”)) and net profits overriding royalty interests (referred to as the Net Profits Interest, or “NPI”). In these Notes,
the term “Partnership,” as well as the terms “us,” “our,” “we,” and “its” are sometimes used as abbreviated references to
Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities.
Basis of Presentation
The consolidated financial statements herein have been prepared in accordance with accounting principles generally
accepted in the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of Dorchester
Minerals, L.P., Dorchester Minerals Oklahoma, LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP,
Dorchester-Maecenas GP LLC, The Buffalo Co., A Limited Partnership, and DMLPTBC GP LLC, and DMLP Terra Firma
LLC. All intercompany balances and transactions have been eliminated in consolidation.
Recent Events
Recent Events – We are continuing to closely monitor future OPEC actions and the ongoing global military conflicts
which arose from 2022 through 2024, on all aspects of our business, including how these events may impact our future
operations, financial results, liquidity, the employees of Dorchester Minerals Operating LP, and operators. The ongoing
global military conflicts could continue into 2025 and could lead to significant market and other disruptions, including
disruptions to the oil and gas industry, significant volatility in commodity prices and supply of energy resources, instability
in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on
macroeconomic conditions. We cannot predict the long-term impact of these events on our liquidity, financial position,
results of operations or cash flows due to uncertainties including the duration and international impact of the ongoing global
military conflicts. These situations remain fluid and unpredictable, and we are actively managing our response.
2.
Summary of Significant Accounting Policies
Basic and Diluted Earnings Per Unit — Per-unit information is calculated by dividing the net income applicable to
holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has no
potentially dilutive securities and, accordingly, basic and dilutive net income per unit do not differ.
Use of Estimates — The preparation of financial statements in conformity with U.S. GAAP requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
General Partner — Our general partner is Dorchester Minerals Management LP, referred to in these Notes as “our
General Partner.” Our General Partner owns all of the partnership interests in Dorchester Minerals Operating LP, the
Operating Partnership. See Note 4 —Related Party Transactions. The General Partner is allocated 4% and 1% of our
Royalty Properties’ net revenues and Net Profits Interest ("NPI") proceeds received by the Operating Partnership,
respectively.
F-9
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
Cash and Cash Equivalents — Our principal banking relationships are with major financial institutions. Cash balances
in these accounts may, at times, exceed federally insured limits. We have not experienced any losses in such cash accounts
and do not believe we are exposed to any significant risk on cash and cash equivalents. Short term investments with an
original maturity of three months or less are considered to be cash equivalents and are carried at cost, which approximates
fair value.
Concentration of Credit Risks and Significant Customers — Our Partnership, as a royalty owner, has no control over
the volumes or method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI. Royalties
operating revenues from properties operated by Exxon Mobil Corporation and Diamondback Energy, Inc. represented
approximately 16% and 15% of total operating revenues for the year ended December 31, 2024, respectively. Royalties
operating revenues from properties operated by Pioneer Natural Resources Company represented approximately 11%, and
12% of total operating revenues for the years ended December 31, 2023 and 2022, respectively. If we were to lose a
significant customer, such loss could impact revenue. The loss of any single customer is mitigated by our diversified
customer base, and we do not believe that the loss of any single customer would have a long-term material adverse effect
on our financial position or the results of operations.
Fair Value of Financial Instruments — The carrying amount of cash and cash equivalents, trade and other receivables,
net profits interest receivable - related party, and accounts payables and other current liabilities approximates fair value
because of the short maturity of those instruments. These estimated fair values may not be representative of actual values of
the financial instruments that could have been realized as of year-end or that will be realized in the future.
Receivables — Our Partnership’s trade and other receivables and net profits interest receivable consist primarily of
Royalty Properties payments receivable and NPI payments receivable, respectively. Most payments are received two to
three months after production date. No reserve for current expected credit losses on accounts receivable is deemed
necessary based upon our lack of historical write offs and review of current receivables.
Oil and Natural Gas Properties — We utilize the full cost method of accounting for costs related to our oil and natural
gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated
lives of the properties using the unit-of-production method. These capitalized costs are subject to a ceiling test, which limits
such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas
reserves discounted at 10% plus the lower of cost or market value of unproved properties. For the purposes of determining
the capitalized costs ceiling, our Partnership only assigned value to proved developed producing oil and natural gas reserves
as of December 31, 2024. The full cost ceiling is evaluated at the end of each quarter and when events indicate possible
impairment. There have been no impairments for the years ended December 31, 2024, 2023 and 2022 as a result of the full
cost ceiling test.
The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test
calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and
geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and
natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative
information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However,
there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions
could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the
ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas
reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test
calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period
ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held
constant for the life of the oil and natural gas properties. As a result, the present value is not necessarily an indication of the
fair value of the reserves. Oil and natural gas prices have historically been volatile, and the prevailing prices at any given
time may not reflect our Partnership’s or the industry’s forecast of future prices.
F-10
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
Gains and losses are recognized upon the disposition of oil and natural gas properties involving a significant portion
(greater than 25%) of our Partnership’s reserves. Proceeds from other dispositions of oil and natural gas properties are
credited to the full cost pool.
Leasehold Improvements — Leasehold improvements are amortized over the shorter of their estimated useful lives or
the related life of the lease.
Leases — The Partnership determines if an arrangement is a lease at inception. The Partnership leases its office space
at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease (the “Office Lease”). The operating lease
is included in operating lease right-of-use (“ROU”) asset and operating lease liability in our consolidated balance sheets.
Operating lease expense is included in general and administrative expenses in the consolidated income statements.
Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments
over the lease term at commencement date. As the Partnership’s lease does not provide an implicit rate of return and as the
Partnership is precluded from incurring any borrowings above a nominal amount under its partnership agreement, the
Partnership used a discount rate commensurate with the incremental borrowing rate of a group of peers based on
information available at the application date in determining the present value of lease payments. Lease expense for
minimum lease payments is recognized on a straight-line basis over the lease term.
Asset Retirement Obligations — Based on the nature of our property ownership, we have no material obligations to
record.
Revenue Recognition — The pricing of oil and natural gas sales from the Royalty Properties and NPI is primarily
determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have no
operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty
Properties and NPI.
Revenues from Royalty Properties and NPI are recorded under the cash receipts approach as directly received from the
remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months
after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes
and product prices. Identified differences between our accrued revenue estimates and actual revenue received historically
have not been significant.
The Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations. The
Partnership’s right to revenues from Royalty Properties and NPI occurs at the time of production, at which point, payment
is unconditional, and no remaining performance obligation exists for the Partnership. Accordingly, the Partnership’s
revenue contracts for Royalty Properties and NPI do not generate contract assets or liabilities.
Revenues from lease bonus payments are recorded upon receipt. The lease bonus is separate from the lease itself and is
recognized as revenue to the Partnership upon receipt of payment. The Partnership generates lease bonus revenue by
leasing its mineral interests to exploration and production companies and includes proceeds from assignments of leasehold
interests where the Partnership retains an interest. A lease agreement represents the Partnership’s contract with a lessee and
generally transfers the rights to develop oil or natural gas, grants the Partnership a right to a specified royalty interest, and
requires that drilling and completion operations commence within a specified time period. Upon signing a lease agreement,
no further performance obligation exists for the Partnership, and therefore, no contract assets or contract liabilities are
generated.
Income Taxes — We are treated as a partnership for income tax purposes and, as a result, our income or loss is
includable in the tax returns of the individual unitholders. Depletion of oil and natural gas properties is an expense
allowable to each individual partner, and the depletion expense as reported on the consolidated financial statements will not
be indicative of the depletion expense an individual partner or unitholder may be able to deduct for income tax purposes.
F-11
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less
certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations
and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships,
trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies,
holding companies, joint ventures, and certain other business entities having limited liability protection.
Limited partnerships that receive at least 90% of their gross income from designated passive sources, including
royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of
their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive
entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax
purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a
passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to
include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code
provides that such income is sourced according to the principal place of business of the Partnership, which would be the
state of Texas.
Recent Accounting Pronouncements
Recently Adopted Pronouncements
In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update
(“ASU”) 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”),
which expands a public entity’s annual and interim disclosure requirements about their reportable segments, primarily
through more detailed disclosures about significant segment expenses. Public entities with a single reportable segment are
required to apply the disclosure requirements in ASU 2023-07, as well as all existing segment disclosures in ASC 280 on
an interim and annual basis. ASU 2023-07 is effective for annual periods beginning after December 15, 2023, and for
interim periods beginning after December 15, 2024. We have adopted this standard for our fiscal year 2024 annual
consolidated financial statements and interim condensed consolidated financial statements thereafter and have applied this
standard retrospectively for all prior periods presented in the consolidated financial statements. See Note 8 — Segment
Reporting for further information.
Accounting Pronouncements Not Yet Adopted
In November 2024, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update
(“ASU”) 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures
(Subtopic 220-40): Disaggregation of Income Statement Expenses” (“ASU 2024-03”), which requires public entities to
disclosure additional information about certain costs and expenses included in relevant expense captions presented on the
income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and for interim periods
within annual reporting periods beginning after December 15, 2027, with early adoption permitted. Management is
currently evaluating ASU 2024-03 to determine its impact on the Partnership’s disclosures.
The Partnership considers the applicability and impact of all ASUs. There are no other recent accounting
pronouncements not yet adopted that are expected to have a material effect on the Partnership upon adoption.
F-12
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
3.
Acquisitions for Units
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals
LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton
Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership,
Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited
partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and
Carrollton Royalty, LP, a Texas limited partnership, the Partnership acquired mineral, royalty, and overriding royalty
interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres
located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited
partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership’s registration
statements on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was
accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a
relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed
cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $8.8 million is
included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended
December 31, 2024. The consolidated balance sheet as of December 31, 2024 includes $193.7 million of net proved oil and
natural gas properties acquired in the transaction.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party,
the Partnership acquired overriding royalty interests totaling approximately 1,204 net royalty acres located in Weld County,
Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership valued at
$16.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is
considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP.
Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as
a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received,
net of capitalized transaction costs paid, of $1.4 million is included in net cash contributed in acquisitions on the
consolidated statement of cash flows for the year ended December 31, 2024. The consolidated balance sheet as of
December 31, 2024 includes $14.6 million of net proved oil and natural gas properties acquired in the transaction.
On March 28, 2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third
parties, the Partnership acquired mineral interests totaling approximately 1,485 net royalty acres located in two counties in
Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership valued at
$17.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is
considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP.
Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as
a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received,
net of capitalized transaction costs paid, of $4.4 million is included in net cash contributed in acquisitions on the
consolidated statement of cash flows for the year ended December 31, 2024. The consolidated balance sheet as of
December 31, 2024 includes $12.3 million of net proved oil and natural gas properties acquired in the transaction.
On September 29, 2023, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party,
the Partnership acquired mineral and royalty interests totaling approximately 716 net royalty acres located in three counties
in Texas in exchange for 494,000 common units representing limited partnership interests in the Partnership valued at $14.4
million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is
considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP.
Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as
a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received,
net of capitalized transaction costs paid, of $0.9 million is included in net cash contributed in acquisitions on
the consolidated statement of cash flows for the year ended December 31, 2023. The consolidated balance sheet as of
December 31, 2023 includes $13.4 million of net proved oil and natural gas properties acquired in the transaction.
F-13
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
On August 31, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third
parties, the Partnership acquired mineral and royalty interests totaling approximately 568 net royalty acres located in three
counties in Texas in exchange for 374,000 common units representing limited partnership interests in the Partnership
valued at $10.4 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the
acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets
under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs
were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final
settlement net cash received, net of capitalized transaction costs paid, of $0.3 million is included in net cash contributed in
acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023. The consolidated balance
sheet as of December 31, 2023 includes $10.1 million of net proved oil and natural gas properties acquired in the
transaction. Final settlement net cash received, net of capitalized transaction costs paid, of $0.2 million is included in net
cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
On July 12, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties,
the Partnership acquired mineral and royalty interests totaling approximately 900 net royalty acres located in 13 counties
and parishes across Louisiana, New Mexico, and Texas in exchange for 343,750 common units representing limited
partnership interests in the Partnership valued at $11.0 million and issued pursuant to the Partnership’s registration
statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was
accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a
relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed
cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is
included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended
December 31, 2023. The consolidated balance sheet as of December 31, 2023 includes $10.4 million of net proved oil and
natural gas properties acquired in the transaction.
On September 30, 2022, pursuant to a non-taxable contribution and exchange agreement with Excess Energy, LLC, a
Texas limited liability company (“Excess”), the Partnership acquired mineral, royalty and overriding royalty interests
totaling approximately 2,100 net royalty acres located in 12 counties across Texas and New Mexico in exchange for
816,719 common units representing limited partnership interests in the Partnership valued at $20.4 million and issued
pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered
complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP.
Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as
a component of the cost of the assets acquired. Final settlement net cash received, net of capitalized transaction costs paid,
of $0.5 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the
year ended December 31, 2023.
F-14
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
4.
Related Party Transactions
Our General Partner owns all of the partnership interests in the Operating Partnership. It is the employer of all
personnel, owns the working interests and other properties underlying our NPI, and provides day-to-day operational and
administrative services to us and the General Partner. In accordance with our partnership agreement, we reimburse the
General Partner for certain allocable general and administrative costs, including rent, salaries, and employee equity and
benefit plans that are not direct expenses. These types of reimbursements are limited to 5% of distributions, plus certain
costs previously paid. All such costs have been below the annual 5% limit amount, including the allowable surplus
carryforward, for the years ended December 31, 2024, 2023 and 2022. Additionally, certain reimbursable direct expenses
such as professional and regulatory fees, as well as certain general and administrative costs that are related to regulatory
matters, are not limited. Significant related party activity between the Partnership and the Operating Partnership that is
included in the Partnership’s consolidated balance sheet and consolidated income statement as of and for the years
ended December 31, 2024, 2023 and 2022 consists of the following:
In Thousands
From/To Operating Partnership
2024
2023
2022
Net profits interest receivable ............................................................. $
5,544 $
8,275 $
7,170
Net profits interest revenue ................................................................ $
21,856 $
34,338 $
28,207
General & administrative expenses (receivable)/ payable .................. $
(199) $
162 $
68
Total general & administrative expenses ............................................ $
6,485 $
5,108 $
3,399
5.
Commitments and Contingencies
Our Partnership and the Operating Partnership are involved in legal and/or administrative proceedings arising in the
ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any
significant effect on consolidated financial position, cash flows, or operating results.
6.
Distribution To Holders of Common Units
On January 23, 2025, the Partnership announced its cash distribution for the fourth quarter of 2024 of $0.739412 per
common unit, representing activity for the three-month period ended December 31, 2024, payable to common unitholders
on record as of February 3, 2025. This distribution was paid on February 13, 2025. The partnership agreement requires the
next cash distribution to be paid by May 15, 2025.
7.
Leases
The third amendment to our Office Lease was executed in April 2017 for a term of 129 months, beginning June 1,
2018 and expiring in 2029. At lease commencement, the Partnership concluded the Office Lease was an operating lease.
Under the third amendment to the Office Lease, monthly rental payments range from $25,000 to $30,000 and the
Partnership received lease incentives of $0.7 million.
Lease expense for the years ended December 31, 2024, 2023 and 2022 was as follows:
In Thousands
2024
2023
2022
Operating lease expense ......................................................... $
262 $
262 $
262
Supplemental cash flow information related to leases was as follows:
In Thousands
2024
2023
2022
Cash paid for amounts included in the measurement of
lease liabilities
Operating cash flows from operating leases ....................... $
356 $
350 $
344
F-15
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Notes to Consolidated Financial Statements
Supplemental balance sheet information related to leases was as follows:
2024
2023
2022
Weighted-Average Remaining Lease Term (months)
Operating lease ..................................................................
50
62
74
Weighted-Average Discount Rate
Operating lease ..................................................................
5%
5%
5%
Maturities of lease liabilities are as follows:
In Thousands
2024
2025 ............................................................................................................................................................... $
362
2026 ...............................................................................................................................................................
368
2027 ...............................................................................................................................................................
374
2028 ...............................................................................................................................................................
380
2029 ...............................................................................................................................................................
63
Thereafter ......................................................................................................................................................
-
Total lease payments .....................................................................................................................................
1,547
Less amount representing interest .................................................................................................................
(507)
Total lease obligation .................................................................................................................................... $
1,040
8.
Segment Reporting
The Partnership manages its business activities on a consolidated basis and operates in a single operating and
reportable segment. Operating segments are defined as components of a public entity that engages in business activities and
for which discrete financial information and operating results are available and regularly reviewed by the chief operating
decision maker in deciding how to allocate resources and assess performance. As disclosed in Note 1 – Business and Basis
of Presentation, our business may be described as the acquisition, ownership and administration of Royalty Properties and
the NPI. See Note 2 – Summary of Significant Accounting Policies for a summarization of the Partnerships revenue
recognition policy.
The Partnership’s Chief Executive Officer (“CEO”) has been determined to be the chief operating decision maker of
the Partnership. The CEO uses Net income, as reported on our Consolidated Income Statements, to assess financial
performance and allocate resources on a consolidated basis. The CEO manages and evaluates the results of the Partnership
on a consolidated basis, and Net income is used to evaluate key operating decisions, such as making strategic acquisitions,
determining transaction structures to capitalize on the development of the properties underlying our mineral interests, and
allocating resources for general and administrative expenditures. The CEO does not review consolidated balance sheet
assets when assessing segment performance and deciding how to allocate resources. Disaggregated operating revenues of
the Partnership’s single segment and all significant segment expenses are presented separately on the Partnership’s
Consolidated Income Statements. There are no other significant segment expenses or other segment items that would
require disclosure.
F-16
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Supplemental Oil and Natural Gas Data
(Unaudited)
Oil and Natural Gas Reserve and Standardized Measure
The NPI represents a net profits overriding royalty interest burdening various properties owned by the Operating
Partnership. The Royalty Properties consist of producing and nonproducing mineral, royalty, overriding royalty, net profits,
and leasehold interests located in 594 counties and parishes in 28 states. Amounts set forth herein attributable to the NPI
reflects our 96.97% net share. Although new activity has occurred on certain of the Royalty Properties, based on
engineering studies available to date, no events have occurred since December 31, 2024 that would have a material effect
on our estimated proved developed reserves.
In accordance with U.S. GAAP and Securities and Exchange Commission rules and regulations, the following
information is presented with regard to the Royalty Properties and NPI oil and natural gas reserves, all of which are proved,
developed, and located in the United States. These rules require inclusion as a supplement to the basic financial statements
a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves. The standardized
measure, in management's opinion, should be examined with caution. The basis for these disclosures are petroleum
engineers’ reserve studies which contain estimates of quantities and rates of production of reserves. Revision of prior year
estimates can have a significant impact on the results. Changes in production costs may result in significant revisions to
previous estimates of proved reserves and their future value. Therefore, the standardized measure is not necessarily a best
estimate of the fair value of oil and natural gas properties or of future net cash flows.
The following summaries of changes in reserves and standardized measure of discounted future net cash flows were
prepared from estimates of proved reserves. The Standardized Measure of Discounted Future Net Cash Flows reflects
adjustments for fuel, shrinkage, and pipeline loss.
Oil (mbbls)
Natural Gas (mmcf)
2024
2023
2022
2024
2023
2022
Estimated quantity, beginning of year ....
8,318
8,920
9,175
33,351
39,153
37,899
Revisions in previous estimates..............
2,927
1,283
1,096
4,799
839
3,508
Purchase of reserves in place (1) ............
2,429
374
457
5,296
743
3,615
Production ..............................................
(2,605 )
(2,259)
(1,808)
(7,847)
(7,384 )
(5,869 )
Estimated quantity, end of year ..............
11,069
8,318
8,920
35,599
33,351
39,153
(1) During 2024, the Partnership acquired mineral, royalty, and overriding royalty interests representing
approximately 16,914 net royalty acres in 16 counties across three states. The acquisitions represented 2,429 mbbls
and 5,296 mmcf of 2024 purchases of minerals in place.
During 2023, the Partnership acquired mineral and royalty interests representing approximately 2,184 net royalty
acres in 16 counties and parishes across three states. The acquisitions represented 374 mbbls and 743 mmcf of 2023
purchases of minerals in place.
During 2022, the Partnership acquired mineral, royalty, and overriding royalty interests representing approximately
5,700 net royalty acres in 25 counties and parishes across nine states. The acquisitions represented 457 mbbls and
3,615 mmcf of 2022 purchases of minerals in place.
F-17
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
Supplemental Oil and Natural Gas Data
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows
(Dollars in Thousands Except Where Noted)
2024
2023
2022
Future estimated gross revenues ............................................................ $
667,840 $
559,865 $
899,159
Future estimated production costs .........................................................
(43,476 )
(35,026 )
(55,363)
Future estimated net revenues ...............................................................
624,364
524,839
843,796
10% annual discount for estimated timing of cash flows ......................
(291,958 )
(252,761 )
(424,643)
Standardized measure of discounted future estimated net cash flows ... $
332,406 $
272,078 $
419,153
Sales of oil and natural gas produced, net of production costs .............. $
(146,050 ) $
(137,015 ) $
(146,938)
Net changes in prices and production costs ...........................................
(7,280 )
(122,884 )
163,535
Net change due to purchase of minerals in place ..................................
69,946
9,813
31,202
Revisions of previous quantity estimates ..............................................
109,971
54,220
46,192
Accretion of discount ............................................................................
27,208
41,915
26,947
Change in production rate and other .....................................................
6,533
6,876
28,748
Net change in standardized measure of discounted future estimated
net cash flows ................................................................................. $
60,328 $
(147,075 ) $
149,686
Depletion of oil and natural gas properties (dollars per mcfe) .............. $
1.81 $
1.25 $
1.14
Property acquisition costs ...................................................................... $
220,389 $
34,084 $
32,921
Average oil price per barrel (1)(2) ......................................................... $
61.19 $
66.04 $
84.70
Average natural gas price per mcf (1) ................................................... $
1.04 $
1.90 $
5.57
(1) Includes Royalty and NPI prices combined by volumetric proportions and represents the 12-month unweighted average
of first-day-of-the-month commodity prices for the periods presented with adjustments for basin differentials.
(2) Includes oil and natural gas liquids prices combined by volumetric proportions.
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