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YoY shift: Neutral
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.03pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.06pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.01pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
endangerment+4
crisis+3
delay+2
litigation+2
conflicts+1
Positive rising
beautiful+2
greater+1
leadership+1
Risk Factors (Item 1A)
15,972 words
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:
the worldwide and domestic supplies of oil and natural gas;
the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil prices and production controls;
political instability or armed conflict in oil-producing regions;
the price and level of foreign imports;
the level of consumer demand;
the price and availability of alternative fuels;
the availability of pipeline capacity;
technological advances affecting energy consumption;
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
conflicts+1
lack+1
Positive rising
No words rose this year.
MD&A (Item 7)
4,655 words
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, 2025, and 2024, 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 2023 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, 2024, filed with the SEC on February 20, 2025, 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.
2025 Overview
Our results during 2025 were mainly driven by lower industrywide realized oil prices versus 2024, decreases in NPI properties oil and natural gas sales volumes due to lower drilling activity in the Bakken region, and increased capital expenditures deducted under the NPI calculation, offset by increases in Royalty Properties oil and natural gas sales volumes from incremental production from 2024 and 2025 acquisitions and continued drilling activity in the Rockies, increased leasing activity, and higher industrywide realized natural gas sales prices versus 2024. Significant results include the following:
Net income of $57.4 million;
Distributions of $132.0 million to our limited partners;
Acquisition of mineral interests representing approximately 3,050 net royalty acres located in Adams County, Colorado in exchange for 915,694 common units representing limited partnership interests in the Partnership valued at $23.0 million and issued pursuant to the Partnership's registration statement on Form S-4;
First payments on 761 gross and 5 net new wells on our Royalty Properties, of which 250 gross and three net wells were attributable to our 2024 and 2025 acquisitions, and on 108 gross and one net new wells on our NPI properties. The wells were located in 43 counties and parishes in seven states with the majority of the activity concentrated in the Permian Basin, the Rockies, and the Bakken region. 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;
Assignment of leasehold interest in Upton County, Texas, with proceeds totaling $5.4 million; and
Lease bonus of $4.0 million includes consummation of leases or extension of existing leases of our mineral interests in undeveloped properties located in 13 counties in five states. Of the $4.0 million, $3.6 million was attributable to an extension of an existing lease on 243 net acres in two tracts of land in Reagan County, Texas for $15,000 per acre and a 25% royalty.
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Critical Accounting Estimates
The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“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:
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.
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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:
% Change
Royalty Properties natural gas sales (mmcf)
Royalty Properties oil sales (mbbls)
NPI natural gas sales (mmcf)
NPI oil sales (mbbls)
Accrual basis average sales price:
Royalty Properties natural gas sales ($/mcf)
Royalty Properties oil sales ($/bbl)
NPI natural gas sales ($/mcf)
NPI oil sales ($/bbl)
Comparison of the years ended December 31, 2025 and 2024
The increase in oil sales volumes attributable to our Royalty Properties during 2025 versus 2024 is primarily a result of incremental increases in baseline production in the Permian Basin and Rockies from wells acquired in 2024 and 2025 and higher suspense releases on new wells on legacy acreage in the Rockies, partially offset by lower suspense releases on new wells on legacy acreage in the Permian Basin and Bakken region and decreased baseline production from legacy wells in the Permian Basin. The increase in natural gas sales volumes attributable to our Royalty Properties during 2025 versus 2024 is primarily a result of incremental increases in baseline production in the Permian Basin and Rockies from wells acquired in 2024 and 2025 and higher suspense releases on new wells on legacy acreage in the Rockies, partially offset by lower suspense releases on new wells on legacy acreage in the Permian Basin and lower suspense releases on new wells on legacy acreage and decreased baseline production from legacy wells in the Mid-Continent and East Texas.
The decrease in oil and natural gas sales volumes attributable to our NPI properties during 2025 versus 2024 is primarily the result of decreased baseline production and lower suspense releases on new wells in the Permian Basin and Bakken region, partially offset by increased suspense releases on existing wells in the Permian Basin in the second and third quarters of 2025 versus 2024.
The increase in lease bonus revenue from 2024 to 2025 is primarily attributable to receipt of $3.6 million in 2025 from an extension of an existing lease, wherein the Partnership leased 243 net acres in two tracts of land in Reagan County, Texas for $15,000 per acre, and receipt of $5.4 million from an assignment of leasehold interests.
Production taxes and operating expenses attributable to our Royalty Properties increased a combined 9% from 2024 to 2025. The increase is primarily a result of higher proportionate natural gas production taxes and post-production costs, such as compression, transportation, processing, and marketing, due to higher natural gas sales revenue and volumes and higher ad valorem taxes, partially offset by lower proportionate oil production taxes due to lower oil sales revenue.
Depreciation, depletion and amortization increased 56% from 2024 to 2025. 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.
General and administrative expenses increased 12% from 2024 to 2025. The increase is primarily attributable to increased legal and other professional services fees, higher regulatory filing fees due to the Partnership’s S-4 registration statement filing in the first quarter of 2025, increased data service and technology costs, and higher compensation expense, including an expanded Operating Partnership equity program designed for employee retention.
Net cash provided by operating activities remained consistent from 2024 to 2025. The lack of change is primarily due to lower NPI payment receipts, lower revenue receipts attributable to our Royalty Properties, net of production taxes and operating expenses, and higher general and administrative expenses being offset by higher lease bonus and other income.
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Acquisitions for Units
On August 29, 2025, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral interests totaling approximately 3,050 net royalty acres located in Adams County, Colorado in exchange for 915,694 common units representing limited partnership interests in the Partnership valued at $23.0 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 $1.8 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2025.
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. Final settlement net cash received, net of capitalized transaction costs paid, of $1.9 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2025.
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. 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, 2025.
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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.
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 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. 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. However, our liquidity and ability to fund future distributions may be affected by material uncertainties arising from factors beyond our control, including: ongoing global military conflicts such as those in Ukraine and the Middle East; current inflation and interest rates; political uncertainty in Venezuela; changes to tariff and import/export regulations by the United States or other countries; and prevailing economic conditions in the oil and natural gas market and other financial and business factors. We cannot predict events that may lead to future oil and natural gas price volatility. If market conditions were to change due to declines in oil prices, uncertainty created by military conflicts, or changes in trade policy, and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced. The current economic environment is volatile, and we cannot predict the ultimate long-term impact on our liquidity or cash flows from these factors.
Liquidity and Working Capital
Cash and cash equivalents were $41.9 million as of December 31, 2025, and $42.5 million as of December 31, 2024.
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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
February 3, 2025
February 13, 2025
May 5, 2025
May 15, 2025
August 4, 2025
August 14, 2025
November 3, 2025
November 13, 2025
Total distributions paid in 2025
February 2, 2026
February 12, 2026
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 $18.3 million during October 2024 through September 2025, which payments reflected 96.97% of total net proceeds of $18.9 million realized from September 2024 through August 2025. Net proceeds realized by the Operating Partnership during September through November 2025 were reflected in NPI payments made during October through December 2025. These payments were included in the fourth quarter distribution paid February 12, 2026, and are excluded from this 2025 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 2024 through September 2025 were $118.6 million, of which $113.9 million (96%) was distributed to the limited partners and $4.7 million (4%) was distributed to the General Partner. Proceeds received by us from the Royalty Properties during October through December 2025 became part of the fourth quarter distribution paid on February 12, 2026, and are excluded from this 2025 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 2024 through September 2025 demonstrates the method:
In Thousands
Limited
General
Partners
Partner
4% of net cash receipts from Royalty Properties
96% of net cash receipts from Royalty Properties
1% of NPI payments to our Partnership
99% of NPI payments to our Partnership
Total distributions
Operating Partnership share (3.03% of net proceeds)
Total General Partner share
% of total
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 2024 through September 2025, our Partnership's quarterly distribution payments to limited partners were based on all of its available cash, as defined in "Item 1 – Business".
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Fourth Quarter 2025 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 fourth quarter of 2025 totaled $32.2 million. Approximately 62% of these receipts reflect oil sales during September 2025 through November 2025 and natural gas sales during August 2025 through October 2025, and approximately 38% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the Royalty Properties during the 2025 fourth quarter were $54.98/bbl and $1.91/mcf, respectively.
Cash receipts attributable to the Partnership's NPI during the fourth quarter of 2025 totaled $4.0 million. Approximately 66% of these receipts reflect oil and natural gas sales during August 2025 through October 2025, and approximately 34% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $54.47/bbl and $2.16/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, 2025, the reimbursement amounts actually paid or reserved did not exceed the limitation.
domestic and foreign governmental regulations and taxes; and
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 NPI, 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 NPI. 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 NPI are under no obligation to continue operating the underlying properties. Our unitholders do not have the right to replace an operator.
Our lease bonus revenue depends in significant part on the actions of third parties, which are outside of our control.
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 NPI.
Our General Partner, through the Operating Partnership, may at any time transfer all or part of the properties underlying the NPI. Our unitholders are not entitled to vote on any transfer; however, any such transfer must also simultaneously include the NPI 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 NPI 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 NPI, 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.
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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.
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 receiving 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 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.
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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 and continues to experience 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 NPI, 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:
pressure or irregularities in formations;
equipment failures or accidents;
unexpected drilling conditions;
shortages or delays in the delivery of equipment;
adverse weather conditions; and
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 NPI, the costs of unsuccessful future drilling on the working interest properties that are subject to the NPI will reduce amounts payable to us under the NPI 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.
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 flexibility 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 achievedesiredprofitability objectives.
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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 NPI are geographically concentrated, which could cause net proceeds payable under the NPI to be impacted by regional events.
A significant portion of the properties subject to the NPI 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 NPI more than if the properties were more geographically diversified.
Under the terms of the NPI, much of the economic risk of the underlying properties is passed along to us.
Under the terms of the NPI, 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 NPI. However, except as described below, we are not required to pay any excess costs.
The terms of the NPI 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 NPI until all prior uncharged costs have been recovered by the Operating Partnership.
Our cash flow is subject to operating hazards and unforeseeninterruptions 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 NPI 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 and the use of artificial intelligence tools by us, the operators of our properties, vendors, suppliers, and other business partners 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. Security vulnerabilities may be introduced from the use of artificial intelligence by us, the operators of our properties, vendors, suppliers, and other business partners. Our information technology systems and any insurance coverage for protecting against cybersecurity risks may not be sufficient. As cyber security threats continue to evolve, including those leveraging the increasing availability and sophistication of artificial intelligence tools, 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. We may not have sufficient resources available to do so on a timely basis. It is not possible to predict all of the risks related to the use of artificial intelligence. It is possible that our business, finances, systems and assets could be compromised in a cyber attack or from the unintended consequences of the use of artificial intelligence tools by us, the operators of our properties, vendors, suppliers, and other business partners. In addition, new laws and regulations regarding cybersecurity and artificial intelligence may pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
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. Global military conflicts and political uncertainty, 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 2025. 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, 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 domestic inflationary issues and associated changes in federal monetary policy and increased tariffs by the United States on foreign jurisdictions 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 and in turn our business.
Recently, the U.S. has had periods of high inflation and increased tariffs on foreign jurisdictions. These inflationary and tariff pressures have resulted, and may continue to result, in increases to the costs of the goods, services and labor used by our operators, which has and may continue to 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 through 2025, with only slight moderation later in the year. Sustained levels of high interest rates, combined with expectations of no further rate cuts and potential future rate increases, as well as potential volatility in monetary policy resulting from new leadership at the federal reserve, could raise the cost of capital and depress 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 damageallegedly 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.
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, and states will be required to adopt implementing plans for existing sources consistent with EPA’s emissions guidelines. Separately, on July 4, 2025, President Trump signed the One Big Beautiful Bill Act, which amended CAA section 136(g) to delay the collection of data regarding the annual GHG emissions for oil and natural gas systems to 2034 and for each year thereafter, which may affect overall compliance timeframe. 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, and compliance timeframes may be adjusted through EPA rulemakings or state plan approvals. We cannot predict the final regulatory requirements or the cost to our operators to comply with such requirements with any certainty.
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On February 12, 2026, EPA announced a final rule rescinding its 2009 GHG Endangerment Finding (a regulatory determination that GHGs, specifically carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride, threaten public health and welfare), and repealing all GHG emission standards and associated compliance, testing, reporting, averaging, banking and trading provisions for light-, medium-, and heavy-duty motor vehicles and engines under section 202(a) of the CAA. Although EPA deferred action on regulatory rollbacks of other GHG standards and reporting requirements under the CAA, revocation of the 2009 GHG Endangerment Finding marks a major shift in federal regulation and could potentially impact obligations regarding other GHG emissions, including those from the oil and gas industry. It is also possible that rescission of the 2009 GHG Endangerment Finding will give rise to greater and fragmented regulation at the state level, litigation from interested stakeholders challenging the repeal, and actions against GHG emitters under common law theories. Although we cannot predict whether and how federal and state regulators will proceed in the future, changes stemming from repeal of the EPA 2009 GHG Endangerment Finding could impact our operations and compliance costs.
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 criminalpenalties 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.
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.
The Bureau of Land Management (“BLM”) is responsible for protecting the resources and managing the uses of America’s public lands. In addition, the BLM, together with the Bureau of Indian Affairs (“BIA”), provides permitting and oversight of land held in trust by the Federal government on behalf of tribes and individual Indian owners. As oil and natural gas production has increased in recent years, so have the number of wells on BLM-managed public lands and on Indian lands that are stimulated by hydraulic fracturing techniques, prompting the BLM to regulate such activities in a manner that seeks to balance responsible development with protection of the environment and public safety. Notably, 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 injunctionagainst 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 NPI 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 NPI 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. If 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. Further, on July 4, 2025, President Trump signed the One Big Beautiful Bill Act, which amended CAA section 136(g) to delay the collection of data regarding the annual GHG emissions for oil and natural gas systems to 2034 and for each year thereafter.
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.
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. On January 7, 2026, President Trump issued a memorandum directing withdrawal of the United States from specified international organizations and treaties, including the UN Framework Convention on Climate Change and the Intergovernmental Panel on Climate Change, with implementation guidance to be issued by the Secretary of State. It is possible that the withdrawals will impact the demand for oil and natural gas products.
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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. On March 27, 2025, the SEC voted to end its defense of the rules requiring disclosure of climate-related risks and greenhouse gas emissions. Following the vote, the SEC staff sent a letter to the court stating that the Commission withdraws its defense of the rules and that Commission counsel are no longer authorized to advance the arguments in the brief the Commission had filed. 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 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 The case was dismissed on March 28, 2025. The Standing Rock Sioux appealed that dismissal on May 29, 2025 and litigation is ongoing. The USACOE completed the final environmental impact study on December 19, 2025. 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 NPI we hold in the Bakken region, the region for which the Dakota Access Pipeline is considered 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.
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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 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 5.2% 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 transactions.
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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. Because these shared officers function as both our representatives and those of our General Partner and its affiliates, conflicts of interest could arise between our General Partner and its affiliates, on the one hand, and us or our unitholders, on the other. As a result of these conflicts, our General Partner and its affiliates may favor their own interests over the interests of unitholders.
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 issue 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, our Chief Executive Officer, Bradley J. Ehrman, and Chief Financial Officer, Leslie A. Moriyama. The loss of the services of either 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 either 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.
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.
The 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.
Under current law, which made permanent the 20% deduction that was set to expire on 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.
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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.
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.
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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 its 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 its common units to a short seller to cover a short sale of common units, the unitholder may be considered as having disposed of its 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, 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, 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.
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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 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. While in May 2023 the World Health Organization (“WHO”) determined COVID-19 to be an established and ongoing health issue which no longer constitutes a public health emergency of international concern, the COVID-19 pandemic and its ongoing variants or a new global public health crisis may 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 a global public health crisis, including continued spread, or fear of continued spread, of COVID-19 and its ongoing variants globally or the occurrence of a new global public health crisis of similar magnitude. No assurance can be given that public health threats 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 2025, multiple global military conflicts arose causing instability in the international economy which has continued into 2026. 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 and large accelerated filer, we have incurred and will continue to incur significant legal, accounting and other expenses. 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.
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, the conflicts in Ukraine and the Middle East, the political uncertainty in Venezuela, changes in the operations on or development of our properties, changes in economic and industry conditions (including changes to tariff and import/export regulations by the United States or other countries) 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.
