Annual Report for Fiscal Year Ending 12-31, 2025 (Form 10-K)

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:

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Net income of $57.4 million;

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Distributions of $132.0 million to our limited partners;

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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;

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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;

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Assignment of leasehold interest in Upton County, Texas, with proceeds totaling $5.4 million; and

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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.

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.

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:		2025				2024				% Change
Royalty Properties natural gas sales (mmcf)			6,132				5,680				8	%
Royalty Properties oil sales (mbbls)			2,002				1,943				3	%
NPI natural gas sales (mmcf)			1,963				2,134				(8	)%
NPI oil sales (mbbls)			621				645				(4	)%
Accrual basis average sales price:
Royalty Properties natural gas sales ($/mcf)		$	2.24			$	1.37				64	%
Royalty Properties oil sales ($/bbl)		$	56.99			$	66.74				(15	)%
NPI natural gas sales ($/mcf)		$	2.55			$	1.54				66	%
NPI oil sales ($/bbl)		$	57.50			$	64.02				(10	)%

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.

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.

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.

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
2024		4th		February 3, 2025		February 13, 2025		$	0.739412			$	35,004			$	1,291
2025		1st		May 5, 2025		May 15, 2025		$	0.725835				34,360				1,283
2025		2nd		August 4, 2025		August 14, 2025		$	0.620216				29,361				1,125
2025		3rd		November 3, 2025		November 13, 2025		$	0.689883				33,291				1,229
Total distributions paid in 2025								$	2.775346			$	132,016			$	4,928
2025		4th		February 2, 2026		February 12, 2026		$	0.755712			$	36,467			$	1,226

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		$	-			$	4,745
96% of net cash receipts from Royalty Properties			113,864				-
1% of NPI payments to our Partnership			-				183
99% of NPI payments to our Partnership			18,152				-
Total distributions		$	132,016			$	4,928
Operating Partnership share (3.03% of net proceeds)							573
Total General Partner share						$	5,501
% of total			96	%			4	%

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".

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.